Comment

Comment by Al Cramblett on July 31, 2012 at 5:11am

Peter, thanks for helping to tell the rest of the story. The numbers you site are surprisingly close to those actually offered in a private drilling partnership. This subscription amount is typically $20,000. To qualify for the intangible drilling expense deduction, one either has to be a general partner or negotiate a working interest in the well. The payments you receive after the well goes into production are reduced by 15% for tax purposes due to the depletion allowance. Yesterday, I received a statement from one of my partnership investments. This was a 2006 investment and today the wells in that partnership have returned only 53% of the drilling cost. As an aside, some of the drilling programs that I have been involved with have shutin some wells because they are not economically productive. These wells will most likely be put back into production once the price or natural gas increases above the $8 threshold.

Comment by Peter Schueler on July 31, 2012 at 4:08am

Looking at the law that covers mandatory pooling,

http://codes.ohio.gov/orc/1509.27

seems to give the owner of the pooled tract two options, participation in the well investment or non-participation. The first option results in the owner receiving a pro rata portion, based on acreage, of production from the beginning at the well's initial production. In the case mentioned in the Columbus Dispatch the unit size is 959 acres and the average size of the pooled properties is 2.5 acres or .26% of the total. I would think that a 959 acre unit would accommodate up to six wells, probably drilled in a sequence over as many years to equalize production coming from the site. An astute owner/investor might want to become a participant recognizing that whichever option he goes with the environmental outcome is the same. If the first well costs $7million a 2.5 acre owner would need to invest about $18,000 and would receive a 100% share of income for his pro rata acreage. Subsequent wells would be funded by income generated from the original wells. Also, there are significant tax benefits from intangible drilling costs that might make this method even more attractive.

Comment by Dan on July 30, 2012 at 4:08pm

Ok Al, I'll be a sucker and take that bet. I'm feeling more positive about it than you.  It just makes no economic sense for them to drill a well that can't pay for itself for 5 years, especially if production falls off steeply after the first couple years. Oh, and Nate can hold the wager. ;-)

 

I do agree that there are too many variables to let oneself be force-pooled, but I was just seeing that in the end, those hold-outs might not make out so bad either.  After all, someday the well will pay for itself twice over, and then, as I understand it, they will get 100% of the royalty due them from day one of production.

Comment by Al Cramblett on July 30, 2012 at 5:02am

Nate, nice to see you posting here again.  I have been an investor with PDC, Atlas, NGAS, and Magnum Hunter so the plays were in most fields-Texas, Oklahoma, Dakota, Kentucky, Pennsylvania.

Dan, I think there are too many variables to let one's property be force pooled.  I am involved in a drilling unit where forced pooling is likely to occur.  I'll bet you $10 those wells will not be paid off in 5 years.  If we have a bet, I'd like for Nate to hold the wager.

Comment by Nate on July 29, 2012 at 1:08pm

What I have seen from analysts at a "Shale Depletion Rule of Thumb" is 70% the first year and 30% the second. So now you need to figure an average well initial production and for how long does it make that IP number until it gets to it's own version of the 70% rule of thumb at the end of the year. So maybe the well does pay itself off twice with these types of depletion in 4-5 years but what is left in the tank after that. And who is to say that a well is not plugged somewhere in that time due to not being economic. Also remember we have $3 gas so that impacts payback time as well.

Al what types of wells were you involved in and where at? Just curious.

Comment by Dan on July 29, 2012 at 12:28pm

Al, based on production numbers reported in the Harrison/Carroll area, and well drilling costs of around $7M+ or so, even using reasonable production declines, revenues should equal to double the startup costs in 2-4 years, even at todays prices.  Do you think otherwise?

Comment by Shower Bath on July 29, 2012 at 12:12pm

Dan, The Harrison County Recorder story was only on that site for one day and they replaced it. I had been told previously that CHK was funding/assisting three or four Ohio counties in digitizing their records (where they had only the hardcopy book systems). My guess from reading the article is that Harrison may be complete in 2012, or early 2013.

Randy

Comment by Al Cramblett on July 29, 2012 at 10:54am

Dan, based upon my 12 years of involvement in private drilling programs, none of the wells are paid off and the payments are approximately 10% of the payments in the beginning years.  Depletion is significant and the depressed prices are not meeting production costs for natural gas.

Comment by Dan on July 29, 2012 at 9:47am

That's right Nate, I forgot to mention that part. I assume that means that is just a delay in payment, not that any of their royalty has to go towards that 200% payoff. That would mean that when they do finally receive their first royalty check, it would be a big one.

Comment by Nate on July 29, 2012 at 9:12am

However Dan, they won't receive any royalties until the well is 200% payed off.

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