Co-author Rusty TuckerConfirming the obvious, in In re Etheridge a Texas court concluded that “personal effects,” in a last will and testament did not include mineral royalties. Let’s investigate how the case got this far.
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Co-author Paul YaleWhat’s good for the goose is not always good for the gander, at least in some places. It appears that the North Dakota Supreme Court has adopted the minority “ Marketable Product Rule” in connection with a 1979 North Dakota state oil and gas lease. We say “it appears” because not so long ago, in its 2009 decision in Bice v. Petro-Hunt, LLC, the Court held that North Dakota was an “at the well” state, like Texas and the majority of other oil producing states. This latest decision is Newfield Exploration Company, et al v. State of North Dakota et al.
The difference between the “Marketable Product Rule” and the “at the well” rule has to do with the deductibility of post-production costs of transporting, compressing, treating and processing from royalty payments. In an “at the well” state such costs are charged proportionately against the royalty owner. In a “Marketable Product” state they are not.
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Did the lessor’s deposit of royalty checks for production from a pooled unit that she contends was improper ratify the improper pooling? In Strickhausen v. Petrohawk et al, a jury will have to sort out the answer. Her case will be aided by exculpatory language in her oil and gas lease and her complaints from the beginning that her lease was improperly pooled.
The “Future Documents” clause and other facts
Strickhausen’s lease on 50 percent of the minerals on land in LaSalle County, Texas, prohibited pooling without her express written consent. An unusual “Future Documents” provision said (to paraphrase): If the lessee requires her to execute any document, such as a division order, such execution does not constitute waiver, acceptance, ratification, reviver, or adoption or waiver of any claim or demand, unless the document expressly states that as its purpose.
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Welcome to today’s grab-bag of unrelated topics.
The climate avengers are clever in the way they demonize the industry. They give zero credit for technological advancement. Truth is, the industry’s use of technology is constantly evolving, resulting in improved performance and, not secondarily, lessened environmental impact from operations.
One example: Scientists from The Ohio State University are working on a project to convert fossil fuels and biomass into useful products, including electricity, without emitting carbon dioxide into the atmosphere. The papers were published in the journal Energy & Environmental Science.
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Co-author Ethan WoodIn Johnson et al vs. Chesapeake et al, unit operator Chesapeake deducted post-production costs (gathering, compression, treatment, processing, transportation and dehydration) from non-operating, unleased mineral owners’ share of production proceeds. The UMO’s (so-called by the court) sued. The federal district court concluded that La. R.S. 30:10(A)(3) governs the dispute, and post-production costs could not be recovered from the UMO’s share of production proceeds.
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Co-authors Ethan Wood and Chance Decker
Less than a year ago, we discussed the “Unanswered Questions” left in the wake of Devon Energy Prod. Co., LP v. Apache Corp. (which did answer the question, “Who is a ‘Payor’ Under the Texas Natural Resources Code?”). We asked:
“But if the non-participating working interest owner is not paying royalties—what is keeping the lease alive? Absent pooling of the leases or a JOA, the non-participating working interest owner cannot rely on the operator’s actions to perpetuate its leases. A sly operator can obtain top leases from the non-participating working interest lessors and run out the clock on those leases …”
In Cimarex Energy Co. v. Anadarko Petroleum Corp., the operator did just that …
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C
o-author Niloufar “Nikki” Hafizi
The latest Fifth Circuit opinion in Seeligson v. Devon Energy Production, L.P. is the latest round in a class action that has been developing since 2014. The plaintiffs are royalty owners who leased to defendant DEPCO. They were certified by the trial court as a class based on an alleged breach of DEPCO’s implied duty to market gas.
The issue on this appeal: Did the trial court abuse its discretion in certifying the lessors in 4,143 Barnett Shale leases as a class under Federal Rule 23?
The Fifth Circuit reversed and remanded to determine “commonality” and to analyze “predominance”, both of which are required for class certification.
This opinion supercedes an earlier opinion from the same panel. This reversal was for a different reason than the first.
The Devon arrangement
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Co-author Chance DeckerBurlington Resources Oil & Gas Company, LP. v. Texas Crude Energy, LLC et al is another chapter in the back-and-forth over deduction of post-production costs from royalty payments. In “clarifying” (royalty owners might say “retreating from”) Chesapeake Exploration & Production, LLC v. Hyder, the Texas Supreme Court held that a royalty delivered into the pipeline or tanks is akin to a royalty delivered “at the wellhead.” The lessee was entitled to deduct post-production costs from its royalty calculation, notwithstanding that the calculation was based on the “amount realized” from downstream sales.
Don’t read too much into it?
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Co-author Ethan WoodLet’s begin with a quiz. True or false:
If you answered “false” to all four, congratulations. In each category the latter companies are reputable independent oil and gas producers. The former are … well, let’s just call them “mineral buyers” (seemingly coordinated in their efforts in some murky way), one of which was the winner – for now – in Ridge Resources, LLC et al v. Double Eagle Royalty, LP
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Co-author Ethan Wood
Coke or Pepsi? Elvis or the Beatles? Should there be a designated hitter? Fixed or floating royalty? Among the great debates of recent decades, few have proven quite as frustrating as the great “Fixed v. Floating” royalty debate in Texas jurisprudence.
A royalty can be conveyed or reserved in two ways: as a fixed fraction of total production (fractional royalty interest) or as a fraction of the total royalty interest (fraction of royalty interest). The fractional interest is “fixed” because it is untethered to the royalty in a particular oil and gas lease. A fraction of royalty is “floating” because it varies depending on the royalty in the lease.
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