Comment

Comment by Bob Jenness on May 18, 2013 at 12:03am

Adam,

"pushing back"?  My brain is exploding trying to apply Newton's second law here:-).  My land's been through "booms" in 1984 and 2002, and I have to confess that I can't think of one instance of any landowner that I know actually "pushing" on any driller.  I did actually try to push on the driller in 2002 - I made one phone call and sent them a map showing the parts of my property that were off limits.  I got real lonesome after that, and my neighbors on both sides got drilled and I didn't (now much to my benefit, but then seemed like small push and squished like a bug).  Rather than "pushing back", I think I'd have chosen words like "continuing to suck as much wealth out of Crawford County as fast and cheap as possible".  But I do appreciate all the 160 acre unit historical analysis, and I hope other landowners can use this valuable info to generate a little more "push" in the next boom.  The bottom line take away on this is that we need a massive effort to reduce the HBP rights on any well that is not producing economic quantities of gas/oil.  Any attorneys and/or groups out there want to make a class action out of this?  I'd seriously consider paying another round of group "dues" to help my HBP neighbors (and myself) get our wealth out of this prison.  At least that might dis-incent or turn around the kind of cartel subsidy that Ohio seems to be doing with forced pooling.  Or we could just keep on keepin' on and become the next Bakken...

Comment by Adam Thomas on May 17, 2013 at 1:04am

Curious to know for sure, and to clarify... i don't know, but I would bet that the original lease has a max unitizatiin clause of 160 acres as it was a pretty common clause in the past. Rather than "renegotiate" the driller chose to drill one well per pad and keep the units to 160. My guess is the landowner thought he has more leverage than he did and thought they needed him to sign and never thought this could happen. They typically unitize large acreage so they can drill multiple laterals from the same pad over time as infrastructure is in place to support it. I dont know why but for some reason, In WV it is more common to see one lateral per pad like in this case. In this case and predominately with exploratory wells, It may be more cost effective for the driller than giving the landowner what he wants. They usually have way more power on these old leases than most people think. Everybody seems to think they have they upper hand when unfortunately most times they don't in these situations. Not having all the facts and purely speculating myself, this is probably an example of the drillers pushing back.

Comment by Joseph-Ohio on May 17, 2013 at 1:00am

My contribution to the discussion for what it may be worth to my landowner friends in Pa.:

In my opinion, in Ohio - ODNR forced pooling / unitization orders are putting a good deal of pressure on unleased landowners.

The basic issue as I see it is that the ODNR is allowing / applying rules (that were originally written many years ago and specifically for technologies relative to conventional vertical wells) to new Utica horizontal lateral wells; which appears to me to be a major affront to the landowner and bent toward / favoring the lessee.

It appears to me that it opens the door to force pooling an unleased landowner into a deficient 'tailgate lease' - and it's been written / interpretted by others (besides myself) that the tact cannot be ruled out.

Also, as I understand things, historically and again meant in application to conventional vertical wells, 160 acre drilling units were written into many old 'tailgate leases' here in Ohio.

Comment by Jim Litwinowicz on May 17, 2013 at 1:00am

Bob; I have no evidence as to the motive behind the smaller units but there is a working theory that I have heard. It is that by having a small unit unit in which all the land is HBPd by an old lease allows the operator to extract all the oil and gas they can and only pay a 1/8th royalty with deductions allowed. This means they are actually paying around 8-9% instead of paying out 17-18% as in many newer leases. All they need to do is make sure the horizontal leg is on HBPd properties, cutting the royalties in half.

An operator can drill a leg or two on HBPd leases, pay a very low royalty until the wells deplete and then declare a larger unit and drill new wells on properties with new leases. The law may even permit them to just declare a larger unit of 640 or 1280 aces without drilling another well. This would allow them to HBP up to 1280 acres with just the original, now depleted, well but it would greatly dilute the royalty payments.

Comment by Bob Jenness on May 17, 2013 at 12:34am

RJS, thanks very much for sharing this real-world scenario.

This looks to me like it could be yet another case of a vertical junk well doing HBP rape on lessors and adjoining landowners.  I've heard that there's been some success in renegotiating some of these cases, and I know one of my neighbors is attempting to get legal relief, but I'm certainly not a lawyer nor expert on this.  Markkot, you should look into this, too.  Perhaps SLDouglass or other expert could help us out here.  Is there still an after the fact opportunity to negotiate better terms on the royalty stream?  Could we see a pie chart to see the distribution between all affected landowners to try to discern if any of your "lost" 40% got "transferred", or is it really just still sleeping?  Was there some "horse trading" in the unitization process that affected any of the landowners?  And finally, how did the unit size shrink to 160?  I thought they always tried to make at least 640 acre units?  Is there a business motivation for smaller units when there's HBP gerrymandering, or is this a test-well-only consideration?

Comment by RJS on May 16, 2013 at 3:21pm

Yes, that is correct. The 60 acres were leased by the previous owner as a unit and a "shallow" well has caused the property to be HBP since then (we get about $25 a year from the shallow well).  So, apparently, the law requires that 60 acre unit to continue to be paid as such.

Comment by markkot on May 16, 2013 at 3:07pm

RJS,

Actually your explanation was good and easy to follow.  thanx, helps to understand how things work.  Was the reason you said that it couldn't be broken up, because it wasn't a previous lease that was released, but an active lease and HBP?  thanks,  mark

Comment by RJS on May 16, 2013 at 2:20pm

Hey, I had reported on the Lippert well a few months back in regards to our property being part of it and I thought the group may be interested in what happened.  We discussed that our royalty portion in it may be (the rate .125 * our acreage 11.027 / unit size 247.9).  We got the notice from Range Resources and the formula in our case is quite a bit different (not to our advantage) than I expected.  It turns out that PA has a law requiring a lease that was signed to not be broken up in future well activities.  Our property was originally leased a long time ago as a 60 acre property.  When we bought it, we got 11.027 acres and a neighbor bought the rest ~49 acres.  What this means is that we get only 11.027/60 of any acres of the 60 included in the unit and our neighbors get the remainder, regardless of which actual acres are in the unit.  It turns out that slightly over 16.3 acres were included in a unit of 160 acres (not the 247.9 on the well plat that I was given).  This makes the formula for our royalty in the well the following (see if you can follow this convoluted thing): (.125 * 11.027/60 * 16.3/160).  This is about 40% of what we expected because it looks like all 11.027 acres of ours are in the 160 acres.  I guess if they were to drill a second spoke parallel to the first one under the other 49 acres, though, we would benefit from that at that time.

Comment by Joseph-Ohio on May 16, 2013 at 9:40am

Thank you Mr. Grafton.

Comment by Andy Grafton on May 16, 2013 at 9:29am

Halliburton is finishing up the frac on the Staab well in North Shenango Township (Pymatuning Area).  I would imagine that Halcon will let it rest for a month or two before they start trying to measure any IP, considering that there will be quite a bit of flowback to get rid of before any quantities of hydrocarbons start to flow.

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