Replies to This Discussion

Permalink Reply by Sam Douglass on December 12, 2011 at 9:27pm

You are asking a lot of questions.  I will take a stab at  one of them.  I have not heard of a dry hole with the shales.  On the eastern edge of the reserve I think they gave up on it because the shale was, as I recall, descibed as overmature, burned out for the most part.  But you do not hear the word wildcatting with these operations.  The producers are spending maybe 3 to 4 million per well and can easily have 15 mil in a drill pad.  Seismic is done about a year in advance which gives a pretty good picture to the producer.  I suspect verical wells are drilled in newer areas to verify the seismic since the verticals are not as expensive - but they can not draw very far from the well.  If things still look good the horizontal wells follow.  Has anyone heard of a shale well not producing?  I do not think so.

There is an extraordinary amout of material easy to find on the internet that is instructive about the Marcellus and more information all the time about the Utica.  That is relevant.  The King Ranch just does not seem to be relevant.

It is my impression that produders are not looking for the price of gas to increase dramiatically since they are trying to expand the market for the gas and there is every reason to believe they could survive if necessary on $3 mcf gas when they are saying the cost to bring the gas to the wellhead is $1of less.

Liquids with the gas whether oil or wet gas with other things besides methane are quite attractive since they do bring higher prices.

A big problem and blessing isthe fact that there are millions of acres of this stuff in Marcellus - Utica territory maybe 100 years of drilling.  The bad news is that it will not make every landowner rich at the same time;

You are asking some intesting questions and you will find answers to some of them as you dig in.  As far as leases go there may be moreimportant things than the stated bonus and royalty.

Good luck with your quest.

Permalink Reply by Jim Litwinowicz on December 13, 2011 at 2:43pm

Way too many questions.  One could write a book, a big one at that, on all these issues.  I would suggest starting with one that is most important to to you, judge the response, and then go to the next one.

To follow up on Sam's post. there have been a couple of bad wells but it is very rare. Cabot pulled out of an area in eastern Pa that wasn't productive...it was at the edge of the formation so it was risky to begin with. One I heard of hit a very large salt water pocket and had to be plugged. A driller can also hit an unknown fault and have problems....bits get stuck or break off. More have hit gas but in levels that are not deemed enough to drill more wells in the area, at least at the current depressed prices.

But from what I hear, the success rate is 98-99% which is unheard of in the industry.

Permalink Reply by Bob Jenness on December 14, 2011 at 7:22am

OK, I'll voluntarily restrict this one to Jim's reply, and perhaps start new discussion threads on some of the others.  Let's affectionately call this thread "Dry Horizontal Holes"  I did a little digging on dry hole probabilities before I posted, and the success rate data points I came to were about 85% back in the 1980s and, with less confidence, the same 98-99% number Jim estimates, which is the number in my initial post example.  It is much harder to get good data on current drilling activity, because drillers are trying to hold this information in confidence, and the information is a little behind the horizontal drilling learning curve.  It would also be interesting to rate energy producers on this parameter, since at least that "hit an unknown fault" item could include the kind of poor quality practices that led to the "famous BP dry hole in the Gulf".  Has anybody read enough producer annual reports to know if more than XOM actually talk about their quality program and performance in any quantitative way?

By the way, a success rate of 99% (let's call it two nines) may be great compared to o&g history, but if we compare it to other complex business pursuits with safety risks, I can find examples where quality is managed to produce 3, 4, and even rarely 5 nines.  One business consideration that "encourages" such higher quality is the combination of insurance premiums and claims.  I wonder what the drilling performance 20 years from now would be if production were "taxed" in some way to fund dry hole insurance?  As a landowner group member, I'd be willing to consider a small contribution from my future royalties to fund such "insurance", if we could find someone who would do the financing for such a policy on a Utica Shale play. 

Permalink Reply by Jim Litwinowicz on December 14, 2011 at 10:23pm

I'm not sure what you mean by "dry hole insurance."  Are you looking for a policy that will pay you royalties even if a well doesn't produce? A tax system to pay royalties in that event?

These companies spend at least $5-7 million just to drill one well. You have to figure that not only is a dry hole a loss of millions of drilling cost but it would also have lost opportunity costs and lost production costs.  I bet a single dry hole costs them over $20 mil. Thats a pretty good incentive to minimize the number of dry holes they drill. I don't think taxing them a couple hundred grand more would have a major influence.

Two nines is amazingly good for this industry.  Its not some manufacturing or production process that can be made better by reproducing the same process repeatedly. Drilling to 7-8 thousand feet below the surface through bedrock is not an easily repeatable process. If they could get to four nines and reduce their costs I'm sure they would.

BP didn't hit  a dry hole in the Gulf but hit a very wet one that exploded. And they cut numerous corners that led to that disaster.

Permalink Reply by Bob Jenness on December 15, 2011 at 4:10pm

Well, the fact remains that the better quality is managed, dry holes and other costly events get rarer.  It's also a fact that even if a driller's cost is $20 Mil per well, if he's drilling a hundred of them, the cost to his business of a "corner-cutting-catastrophe" is only 1%.  If it happens to be on my lease, the cost to me is potentially 100% PLUS LIABILITIES.  My initial question was intended to generate discussion of  this big difference in relative risk.

By the way, did you see the "engineering" report on the BP disaster released in the last day or so?  It seems to indicate that perhaps the industry best practice for BOPs could use some added independent lab verification and risk analysis.

I've since learned that some leases contain a "shut-in clause", which may accomplish the same purpose.  It seems to be applicable to a broad spectrum of similar events, even including the possibility that a governing body will stop drilling activities due to "corner-cutting".  Again, stuff like this is part of the "normal" risk for a driller, but much more catastrophic to an individual landowner if he's the unfortunate one it falls on.

Further, it seems that leases often might provide for term extension for such shut-in events.  Obviously, this would constitute inverse insurance.  This would be especially unfavorable with some of the recent leases that make the only lease payment the bonus, with no delay payments.