On a depth clause, I had the following…" It is understood and agreed that following the expiration of the primary term of this lease or upon expiration of any extension or renewal of the primary term, this lease shall automatically terminate as to all rights lying one hundred (100) feet above and below any formation being produced in any well drilled on the lease premises or on lands pooled or unitized therewith."
The group I am negotiating a lease on wants to eliminate the “100 fee above” portion but they are okay with keeping 100 feet below. Any major red flags as a mineral owner to remove the 100 feet above language?
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Most operators would not want the 100’ above clause because it is common to drill to the deepest zone of interest and then complete that zone if economic and then go up hole to shallower zones over the years if they think they can make money on them after the lower zone is finished.
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So essentially if they produce the upper zones I would be at the same royalty under the lease. And the downside to the mineral owner is not receiving a new bonus and potentially better lease terms on the upper zones, correct?
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Most horizontal drillers are not interested in shallow vertical well zones. They lease with specific drilling target in mind, such as Wolfcamp or Woodford. Consider limiting the lease depths to deeper depths, e.g. lease is for depths below the top of Woodford. That way you can later lease shallow depths to a company wanting to drill produce from shallower formations. It is not beneficial to mineral owner for shallow depths to be held without development.
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Yes, if they will not allow the upper depth clause, then any shallower zones will be at the same lease royalty.
As TennisDaze says you can try to only lease particular zones, but that can be difficult.
Depending upon the state laws, some states will automatically release upper zones after a certain number of years.
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I would strongly suggest pushing to adjust the depth severance clause to state “…lease shall terminate as to all depths lying below 100” below the deepest producing perforation” instead of “formation”.
I am not sure where your minerals are located but just as an example if the lessee completed a well in the Wolfcamp A formation (WCA) if the depth severance clause stated “….lease shall terminate as to all depths lying below 100’ below the deepest producing formation” the lessee would hold all rights down to 100’ below the base of the Wolfcamp which would include the Wolfcamp A, B, C, D, etc. but if the clause stated 100’ below the deepest producing “perforation” or even “horizon” the lease would partially terminate and your minerals would be open as to the lower Wolfcamp formations and if they wanted to drill and complete a well in the lower Wolfcamp formations they would need a new lease and pay you another lease bonus.
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It is standard practice, and most economical, to complete the deepest zone first and produce upper zones later. We would never accept a lease like this. The operator spent the money and drilled through the zones behind casing and should have the right to complete them later. Unless there is a drainage issue in shallow zones, no reason to complete them when production available deeper in hole.
I Agree with Moeper. As an operator, we felt that we took all the risk to drill and evaluate the well bore,so should have the benefit of all the reserves that were proved up, no matter what formation they come from. Differing pressures in different formations prevent them from being produced concurrently so one zone has to be depleted before the next can be brought online. Your royalty and lease terms are the same, no matter what formation is producing. Any additional producing zones just extend the life of the well and the life of your royalty payments.
Not necessarily as any single well will hold the lease and the operator is able to ‘bank’ the undrilled formations (asset on books and used for loans). There is no incentive for the operator to develop and the mineral owner will get zero from these undevoped zones for decades. Many leases are 50+ years old with a dribbling deep gas well holding the lease and no other wells. Chevron, Exxon and other companies are after the deep formations with large units and big-producing wells and they will never drill the shallow 20 or 40 acre oil wells. Those smaller wells are only economic for smaller companies. So it is better to split the lease between shallow and deep depths, or have some specified time to develop the shallow formations or lose it. Seen it done a lot in Texas.
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Great Post! Thank you!
The mineral rights owners want their rights to be produced and utilized and converted into money! At least I do for myself and family. Produce it or LOOSE IT!
IMO operator earned those upper rights by drilling the well. Agree with deepest perf language. For protection, add offset clause and compensatory royalty for wells drilled next door
Are you speaking as a mineral owner or as lessor?
Very useful comment! This is the first I’ve heard anyone mention adding an Offset Clause or Compensatory Royalties Clause to a Depth Clause or in addition to a Depth Clause. I’m relatively new to all this, and always looking for ways to improve my Exhibit A. I’m very curious to learn more about these as it sounds rather important to include them in a lease. Can anyone share examples(not legal advice) of effective clauses and/or elaborate more on their uses. My minerals are in Oklahoma. Unsure how different states may handle this.
If your minerals are in Oklahoma, it would be difficult to get an operator to agree to a an offset clause or a compensatory royalties clause. And you do not need to really be concerned about it. The OCC regulates the distance between the wells to account for drainage and easements along the section lines and that takes care of it. It is more of a Texas clause.
Awesome, thanks M_Barnes! That’s why I thought to mention the state. Different states handle these things differently and potentially more effectively than others.