2023 recap: important US oil and gas decisions

Adverse possession of a non-operating working interest

In PBEX II, LLC, et al. v Dorchester Minerals, L.P. et al., the court was confronted with a novel issue: can a non-operating working interest be acquired by adverse possession in Texas? The ruling confirmed that it is possible, notwithstanding that many would consider a non-operating working interests to be non-possessory in nature.

Torch Oil & Gas Company (“Torch”) held a 25% interest in an oil and gas lease covering a tract of land in Midland County, Texas. The lease was subject to a Joint Opening Agreement ("JOA"). Torch then assigned this interest to a predecessor of the defendant in 1989, and immediately thereafter Torch signed a division order issued by the operator under the JOA that reflected Torch’s 0% interest after the assignment. The defendant then participated as a non-operating working interest owner for over 25 years, including making elections (including elections to “non-consent” operations) and contributing and receiving its share of costs and revenues attributable to the 25% working interest.

Torch did not dispute or otherwise interfere with the defendant’s interest during this time, but in 2016 Torch made another assignment that included the very same interest that was ostensibly assigned to the defendant in 1989, and upon making such subsequent assignment, Torch notified the defendant that it disputed the initial assignment (over 25 years ago). Setting aside whether the initial assignment actually included the 25% working interest, the focus for the court was whether the defendant adversely possessed the non-operating working interest over the 25-year time period.

The general requirements for establishing adverse possession are well established; the adverse possessor must possess the property exclusively, continuously, openly and in a hostile manner for the statutory period of time. Texas has various adverse possession statutes of limitations depending on nature of the adverse claimant, and these rules apply to oil and gas interests. There must be actual, visible appropriation of the interest, and in this case, the non-operating working interest. Could this be established without physical entry onto the lands, or without doing the actual drilling and/or production of the minerals?

Torch argued that a non-operating interest cannot be subject to adverse possession on the basis that the interest is non-possessory. The court disagreed however, noting that the act of participating as a non-operating working interest owner (including making elections, paying for development costs, and receiving production revenues) was a hostile act capable of satisfying the necessary requirements to establish adverse possession. In essence, the court did not draw a distinction between an operated and a non-operated working interest in terms of possession (i.e., it is not necessary for someone to do the actual drilling and production activities to establish adverse possession of the non-operating interest).

The outcome of this case should not be considered a surprise. Texas courts have demonstrated a willingness to rule in favor of adverse possession when it comes to oil and gas interests, even going so far as to rule that expired oil and gas leases can be revived if the operator continues to pay royalties on production. That said, adverse possession can involve a subjective analysis, so the facts of each case should be examined carefully. Here, it was clear that the non-operating working interest owner actively possessed the non-operating working interest by responding, electing, receiving and paying for over 25 years, all in accordance with a typical non-operating working interest owner.

Cost deductions from royalties

The next case, H.L. Hawkins, Jr., Inc. v. Capitan Energy, Inc., builds on the growing case law around permissible cost deductions from the gross proceeds used to calculate royalty payments. Typically, a royalty owner will not share in the production cost burden with the lessee. Postproduction costs, on the other hand, are generally included in the calculation of royalty payments. However, this commonly held principle can be altered by the parties’ intent, as evidenced in the lease language.

The lease in this case contained the following provision:

“Lessor’s royalty shall not bear or be charged with, directly or indirectly, any cost or expense incurred by Lessee, including without limitation, for exploring, drilling, testing, completing, equipping, storing, separating, dehydrating, transporting, compressing, treating, gathering, or otherwise rendering marketable or marketing products, and no such deduction or reduction shall be made from the royalties payable to Lessor hereunder, provided, however, that Lessor’s interest shall bear its proportionate share of severance taxes and other taxes assessed against its interest or its share of production.”

The lessee, Capitan, sold production under various sales contracts at the well. The sales contracts provided that the purchaser will deduct from the price all costs of transportation, fractionation and other downstream post-production costs. This resulted in Capitan receiving a lower price for the production that took into account the postproduction costs incurred by the purchaser. Capitan then paid the landowner royalty to Hawkins (the lessor) based off the lower amount received by Capitan under the sales contracts.

Hawkins took the position that the royalty calculation clause in the lease forbade Capitan from deducting post-production costs from the royalty calculation. In support of its argument, Hawkins relied on Devond v Sheppard, No. 20-0904. I covered this case in my prior analysis. For ease of reference, the lease in that case included the following clause:

“If any disposition, contract or sale of oil or gas shall include any reduction or charge for the expenses or costs of production, treatment, transportation, manufacturing, processing or marketing of the oil or gas, then such deduction, expense or costs shall be added to the market value or gross proceeds so that Lessor’s royalty shall never be chargeable directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes.”

The court ultimately did not feel bound by the decision in Devon v Sheppard, noting a distinction between the royalty clause in this case, which only speaks to “any cost or expense incurred by Lessee…”, whereas the clause in Devon v Sheppard specifically contained a requirement to add back costs charged by the purchaser of production. Even though the lessee here ultimately received lower net proceeds on account of the post-production costs charged under the sales contracts, the court ruled that receiving lower revenue is not the same as actually “incurring” an expense.  

Therefore, since the purchaser of production incurred the post-production costs, Capitan was permitted to calculate the royalty based off the net proceeds received by Capitan under the sales contract. Had Capitan incurred the post-production costs itself, or had the lease contained an “add-back” provision related to any post-production costs incurred by purchasers of production, the outcome may have been different.

The lesson here is that if the intent is to forbid deduction of any post-production costs, then the royalty calculation clause should not be limited to costs incurred by the lessee, and to be extra clear, there should be a separate “add-back” clause akin to that in Devon v Sheppard. Absent this, lessors face exposure to lower royalty payments.

Cessation of production clause

The Colorado Supreme Court recently issued a decision in Boulder County v. Crestone Peak (Colo. 2023) that involved the interpretation of two cessation of production clauses. The leases in question included similar habendum and cessation of production clauses. The habendum clauses set forth the duration of the leases, bifurcating between customary “primary” and “secondary” terms, with the secondary term continuing so long as oil and/or gas are produced from the leased land. The cessation of production clauses worked to modify the habendum clauses by extending the secondary terms of the leases if production ceased “for any cause” so long as the lessee resumed operations for drilling or reworking a well within the period of time proscribed under each clause (60 and 90 days, respectively).

After the leases were in their secondary terms, the lessee was forced to shut-in otherwise commercially viable wells to allow maintenance to be performed on the sales pipeline that was connected to the wells. The shut-in lasted for 122 days, which was well in excess of the permitted cessation periods under each clause. At no point during the shut-in did the lessor take the position that the leases had terminated, and the lessor continued to accept royalty payments after production resumed. Nearly four years later, the lessor sued the lessee for trespass and unjust enrichment, alleging that the leases had terminated under the cessation of production clauses when production ceased for 122 days.

From a plain reading of the clauses, it would be reasonable to presume that the leases did in fact terminate. After all, the clauses provide that cessation of production may occur “for any cause”, and the cessation of production lasted longer than the permissible periods without the lessee conducting any drilling or reworking operations.

The court, however, focused on both the common law temporary cessation of production doctrine and the parties’ intent behind the cessation of production clauses, noting that (i) courts will generally adhere to the common law principle that a temporary cessation of production in the secondary term will not cause termination of a lease and (ii) the parties must have intended for the cessation of production clauses to only become operative if a production cessation could only be remedied by drilling or reworking operations. If a plain reading were given to these cessation of production clauses, then the lessee would be required to conduct drilling or reworking operations even though well-productivity was not the issue, which would lead to economic waste. This would also ignore the fact that cessation of production clauses are intended to be “savings” clauses that work to extend the lease, not clauses intended to eliminate the protections afforded to lessees under the temporary cessation of production doctrine. A more reasonable interpretation, according to the court, would be to interpret the cessation of production clauses to refer not to a temporary cessation of production, but to a cessation of production that would be permanent unless corrected by drilling or reworking operations. Accordingly, the leases did not terminate due to the shut-in.

More than anything, this case illustrates the different approaches taken by courts in different oil producing states. Courts in Texas tend to focus more on a strict interpretation of the lease or contract language, without considering intent absent drafting ambiguity. The Colorado Supreme Court took a different approach here by harmonizing the parties’ intent with the wording of the relevant clauses, with the aim of avoiding what the court classified as an “absurd and unintended” result.