Replies to This Discussion

Permalink Reply by Rock Man on June 9, 2018 at 5:20

All great points.

In the TMS / Hz AC Frac play area, small shallow productive targets are the norm in the Frio, Vicksburg and Wilcox intervals. The "poster child" for small targets is a one well Wilcox oil field in Amite County (Ms). Over 100,000 BO cumulative production from this one well - and this well was offset in every direction to try to extend the "field". All offsets (at least 4) were dry holes.

Shallow depth separation clauses would allow shallow rights to revert back to mineral owner so that they could be leased to operators wanting to chase these targets. Even if deep production is already in place.

How common are shallow Pugh clauses in Louisiana? I believe that more sophisticated landowners are including this clause in their leases in parts of the Eagle Ford trend as well as the Permian Basin.

Permalink Reply by Skip Peel - Mineral Consultant on June 9, 2018 at 5:30

Vertical Pugh clauses have been around since the 1970's but have been used sparingly and mostly limited to large mineral interests with the best O&G legal assistance.  When this topic first came up for discussion, a number of GHS industry members encouraged mineral owners to include depth limitations.  Neither the Haynesville focused companies nor the local/regional independent operators seemed interested.  A lot of small operators with shallow production and one eighth royalty leases made out like bandits when they conveyed their deep rights.  The big guys were in a hurry and didn't wish to prolong lease negotiations.  Mineral owners were anxious to start getting mail box money.  Independents held out hope for a big future pay day by having deep rights in their leases.  So here we are.  I'd like to see the state step in with an arbitrary but balanced regulation for farming out shallow zones if not explored or developed within a reasonable time frame but the DNR/OOC is loath to take any actions that might displease the industry.  A Catch 22.

Permalink Reply by Rock Man on June 9, 2018 at 5:40

Let's just hope for some AC Hz play success plus Australis "cracking the code" in being able to D&C economic TMS wells.

Permalink Reply by Dion Warr, CPL on June 12, 2018 at 16:51

Skip:

(NOTE: Ah! Functionality for the "Reply" button appears to have magically returned - perhaps we now don't have to talk in "strings" and carry on proper threads.)

That said: As to depths and strata and leasing: that's not how that worked.

Historically, leases originally had no provisions for limitation once production was established and entered their secondary term (ie., for as long thereafter as oil, gas or some other mineral is produced...)  Prior to lease termination provisions being created and incorporated into leases, "strata leases" did exist in which certain depths were leased, usually in the form of "shallow" (surface to base of / top of X formation or a named footage) or "deep" (base of / top of X formation or a named footage and below to another defined depth or "none").  Prior to Pugh clauses and extensive unitization, sophisticated owners would also lease allotted portions of property on each lease rather than leasing all of their lands on one lease.

Of course, many companies wanted to have the right to "earn" what they drilled and produced in the lease no matter shallow or deep.  This desire to accommodate (if not encourage) the lessee to explore and produce while protecting lessor's right to retain (or have released) rights to lands and depths not utilized gave rise to Pugh clauses - first vertical (ca. 1940s) and then horizontal (varies, but generally held to have originated in between the late 60s and early-to-mid-1970s).

The desire for operators to "hold all the rights and make out like bandits" doesn't really fit the actual narrative.  Companies holding unutilized or underutilized rights normally were willing to farm out rights to those willing to explore other zones not currently in pay - the farmor would usually reserve an ORI, sometimes convertible to a WI after payout at its option, and the farmee would bear the risk of attempting to drill, complete and produce from the farm acreage, and if successful, earned a portion of the leasehold rights, usually with a right or option to farmin more prospective acreage.  The farmor and farmee gained income and knowledge, the royalty was paid as agreed under the original terms of the lease to the lessor - everyone got something, and a new formation was coaxed to produce another stream of revenue.  Plus, it held the lease.

A couple of things happened along the way to RI being customarily an eighth to the "expected" quarter.  Technology improved which allowed for better accuracy of locating structures and predicting favorable conditions prior to the bit touching the earth.  Prior to this, 2D seismic showed gross structure and faulting and wells were still drilled after discovery like a string of pearls until the good pay ran out.  When common geology from other areas suggested possible deeper prospects than what was known in a given field, some better capitalized companies would drill wildcats "to the basement" (some still call these "moholes" after the government "deep hole" project of the same name).  This method of delineating fields was costly - in all but the larger proven fields, lessees / operators would be loathe to hand out a quarter (or even close) to the lessor when dry hole rates were still 30-40% and higher in nascent fields and wildcat areas.  As the technical side of the industry grew more nimble and sophisticated, the RI began to climb: 1/6...  3/16... 1/5... 9/40 (22.5%)...

But, bottom line: if you were an independent (or even a larger company) expecting to hold out for a big payday based upon your 1/8 lease being held by a shallow well drilled in 1960, you either (a) had a powerful crystal ball or (b) did good by not dealing anything away for almost 50 years until your "big ticket" came in.  For most, the smart use of their money was to not get caught expending resources trying to hold prospective depths with a money pit of a well, and to better use that money going find more oil and/or gas somewhere else.

Even if the state were to muster enough support to pass a measure to allow for statutory lease termination as you suggest, the precedent here and in other states where a Pugh clause is statutory (e.g., OK) is such that it would not be applicable against current leases in force - if for any other reason, the state is generally loathe to intervene or alter existing legal binding contracts (that would displease LOTS of people, not just "the industry").  Until such time, lessors are still entitled to sue for dissolution of their leases for failure to produce in paying quantities, failure to act as a reasonable and prudent operator, failure to fully develop or failure to protect from offsets, but the burden of proof is still on the lessor and is generally only availed of such relief once all contractual and/or administrative remedies are exhausted.

Permalink Reply by Dion Warr, CPL on June 12, 2018 at 15:44

Skip:

The L TUSC wells you cite produced from the Lower Tuscaloosa (Sand) formation. These are conventional wells which also bottom below the base of the AC section. The remaining wells (all titled with an "H") are the TMS completions.


Blairstown is the name of the large plantation tract (and associated tracts) in East Feliciana Parish which has been owned by the Reiley and Jones families for generations. Their ancestors hail from Blairstown, NJ - presumably, the property was named in honor of this. Otherwise, one may be looking at "Oak Grove Field". If one were to attempt to put a point on a map, Blairstown would be closest to the intersection of Hwys. 409 and 959, just north of Pride, LA.

Permalink Reply by Skip Peel - Mineral Consultant on June 13, 2018 at 1:24

Thanks for the clarification and history lesson, Dion.

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