Comment

Comment by Kris on August 23, 2012 at 3:27am

I was offer this by Range currnetly trying to negotiate, don't think it's going to well.  I think I may try to look into cx-energy.  Currently in Troy county

Comment by rex roae on August 23, 2012 at 1:58am

Range is offering $3750/acre over 5 years with 15% royalty.  Bonus is spread out over 5 years so you will get $750/acre each year.  If they drill, bonus money stops.  640 acre units.  Royalty is WITH deductions so be careful there.  They can hold your land with any well drilled at any depth.

Comment by jim hall on August 23, 2012 at 1:24am

Has anyone else heard of Range offering a year to year lease ?

Comment by Jim Litwinowicz on August 23, 2012 at 1:21am

The length of the laterals vary for many reasons, one of which is the depth of the well. The rigs have limits to the total length of the drilling string so the deeper the well the shorter the horizontal. Since the Utica is relatively shallow, the horizontals should be longer.  From what I hear the recent Range well is 7000' long.

But that is not critical at this time. What is most important is the probability if getting such a process written into a lease. You still haven't answered the question..have you proposed this to an E & P company and what was their reaction?

I wish you great success in getting this done. Once a group gets something like this accepted, it becomes a new standard.  The Pugh Clause has only been around since 1947 when Lawrence Pugh first succeeded in writing that into leases. Now it is standard in some form or another. Perhaps someday all leases will have a Douglas Clause.

Comment by Bob Jenness on August 22, 2012 at 11:24pm

Sam,

Thanks very much for posting such rich detail on your proposal. I know you've done a lot of hard work on this, and I hope it changes the market.

I like the minimum/advance royalty, but only as a weak second to leasing to someone who is actually committed to bringing my oil and gas to full production in a time frame that closely approximates the timeframe of the "lease".  I think it borders on fraud to ask me sign a document that is titled "lease" at the top, but is effectively an option to "buy" my oil and gas by paying any old drilling company a pittance to place a junk vertical well somewhere in the neighborhood.  If they really want to "own" reserves, why don't they fess up and actually offer to "buy" said rights at a fair price based on estimated value of all strata they're buying.  On the other hand, if they want to lease them, then let's have a lease that commits to full horizontal production during the term of the lease, and if they choose to defer an area, then pay the market rate for a new lease when this one runs out.

This is also a compelling argument for complete strata separation.  If the lease restricts to one stratum and horizontal only, then I have some assurance that drilling will be planned for meaningful production, or that I'll have a future re-lease  or continuing delay income opportunity.

Is it ever done that the leasing, unitization, and drill plan are all done together, so that each small group of landowners know that there's a real plan before signing their leases?  That would also help here.

My next post(s) will have some detailed questions on the advance royalty text, but due to complexity, it may take a while.

Comment by Sam Douglass on August 22, 2012 at 2:24pm

The last time I looked the average length of a Range horizontal was something under 3500 feet and they were drilling them about 500 feet apart.  If they have found a way to draw gas for more than 250' feet from the well bore, then I expect the recovery from each well is greater - same for increased length as, I think, I mentioned.  All the numbers would be revised with probably close to the same amount per acre after all adjustments are made.  Bigger well - more production.

I suspect in the highly unlikely event that a well were depleted in year two, the producer would terminate the lease and walk away.  How often has that happened?  [Maybe on the eastern edge of the field]  These are not wildcat wells.  My example only asked for half the anticipated royalty  to be paid over 25 years starting with the first day of the 8th anniversary of the lease.  That gives the Lessee a lot of room to maneuver.  If the producer actually starts a drilling program, s/he/it will get half the production in the first couple of years.  That ought to cover a lot of future Advance Minimum Royalty otherwise due.  I suggested that production royalties could be used to offset future advance royalties.  Where is the problem.  It only occurs if he waits a couple of generation to drill and whatever the producer pays in Advance Minimum Royalty is an asset on the producer's books to offset future production royalties.

The numbers I used were for dry gas and wet gas areas should be more lucrative.

If the landowner's grandchildren are to be the first to see a production royalty there are going to be a lot of unhappy people.

At the rate things are going it is going to be a long time before there is real production royalty in Crawford County and environs.  Almost no permits.  The first exploratory wells are all that are being drilled.  Give the folks a break.  The landowner should not have to wait forever for some cash flow.

Comment by Jim Litwinowicz on August 22, 2012 at 1:18pm

the average horizontal well does anywhere from 70 to over a hundred acres. That depends on the length of the lateral and how wide they can fracture the shale. At 5000' and a 600' frac..that is about 70 acres. Shallower wells can have longer lats...the new Range one is 7000' long.

So you expect the companies to start paying at least $64,000/yr after the seventh year. What if they drilled a well in yr two and it is depleted below that.  Do the pay the lower royalty...maybe only ten grand a yr or do they pay the "advanced royalty"? Can they claim the higher royalty in yrs three and four offset the advanced royalty?

And most important. Have you talked to any companies about this and what is their reaction?

Comment by Sam Douglass on August 21, 2012 at 4:37pm

The amount of the minimum royalty would be negotiable of course and my current thinking is that one might take half the income that might be conservatively produced from a well over its life and spread it over say 25 years.  This involves many variables since not even the producer knows what he will produce or the price that will be paid.  I am thinking, without benefit of recent consultation with an expert prognosticator that it is reasonable to expect 4 million mcf over the life of one well and $4 per mcf is a very conservative figure for 7 years from now.  That is $16,000.000 as a very conservative gross return from the well.  One half of that would be $8,000,000 per well gross return.  To that one would apply the applicable royalty, say 20%, yielding $1,600,000 to the landowner.  Divide that by say 25 [for the number of years] would yield to the landowner $64,000 per year beginning with the 7th year.

As best I can find out the average acreage per well is about 40 acres and the number would have to be adjusted for the acreage in the tract being leased [eg. 80 acres would be $128,000]  Wells that use greater acreage would be producing more and so it is not likely to make much difference if you try to adjust for that.

And this is loaded for the producer since half the return can be expected the first two years of well operation because of the dramatic decline curve.

Any production royalty will soon pay the Advance Minimum Royalty far into the future.  But at least it gives the landowner some assurance of a payment while the lease is outstanding.

Seems reasonable to me.

By the way, your bonus and royalty numbers are off.  An optimum bonus for a 5 year lease is $5000 with a royalty of 20% with minimum deductions.  And it should be made clear that the royalty will be applied to the separated wet gas at its higher price to avoid ambiguity.  Of course, the landmen are making their first pass in the area and it will be a little while before they come around to offering what the companies will pay.  Everything I read indicates that demand for gas will skyrocket over the next two years and the stuff about the current low price is utter nonsense.  Prices may not rush above $6 per mcf since the the producers will not want to lose the expanding market they are capturing.

Comment by Sam Douglass on August 21, 2012 at 4:03pm

An Advance Minimum royalty would be without regard to whether the wells contemplated are shallow wells with many more operating sites or the factories required for deep wells.  What ever is leased is covered: shallow, Marcellus, Utica, Ohio shale, Onandaga limestone etc.  I am sure there are Advance Minimum Royalties paid in other parts of the country but maybe not around here.  Advance Minimum Royalties are quite common in this area for coal leases - a different resource but with like considerations.  I have seen plenty of them.

This is not a delay rental that the operator cannot recoup out of future operating income nor it is a bonus - which is an delay rental of sorts.

Arguably an Advance Minimum Royalty could be paid from day one of the lease, but I think it reasonable to wait a period, say 7 years to start the Advance Minimum Royalty - if the landowner has had the benefit of a substantial bonus.

7 years gives the Lessee 2 years following the primary term to get some production royalty to the Lessor.  If the client agreed to it, it might be appropriate for any paid production royalty to be credited against future Advance Minimum Royalty that would come due.  This way the the Lessee would never have to pay any Advance Minimum Royalty if there were production royalties of significance.  Production Royalties would be a credit against future Advance Minimum Royalties and he revers would be true, Advance Minimum Royalties would be a credit against Production Royalties later due.  The Lessee would be able to carry paid Advance Minimum Royalties of its books as an asset until recouped out of production royalties.

Continued to next comment.

Comment by Sam Douglass on August 21, 2012 at 3:41pm

In response to the comment by Jim Litwinowicz below.  I recognize that the producers need long term reserves.  The thought that they will suddenly produce from everyone's property all at once is inconceivable and the reserves from the different strata are likely to keep them going for 75 to 100 years.  I also think it is reasonable for the landowner to have some meaningful income from the resource over what amounts to a very long, indefinite term into the future.  I would be less concerned about battles over the various ways leases in the marketplace allow the producer to extend the lease if payment of income were assured to the Lessor - who will face some loss of marketability of his surface land and perhaps loss of the ability to mortgage it as well.

An Advance Minimum Royalty is to assure that under all circumstances the Lessee will get some return from the burden of the lease over what is likely to a very long term.

Please see my next comment for continuation.

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