By: Bryan Cave Leighton Paisner LLP – Lexology – While the unexpected and unpredictable commodity price swings over the last year have undoubtedly captured the attention of mineral and royalty owners across the United States, careful attention should also be paid to a few recent decisions that could significantly impact their interests.
Production in Paying Quantities
The first case concerns the longstanding principle that production must be “in paying quantities” in order to extend the life of an oil and gas lease beyond its primary term. Even if a lease only requires “production”, courts have interpreted that to mean production in paying quantities. This well-established rule is rooted in the underlying economic intent of every oil and gas lease; to produce oil and gas profitably.
What constitutes production “in paying quantities” is another issue worth a separate analysis. The lessee in Thistle Creek Ranch v Ironroc Energy Partners, No. 14-20-00347-CV admitted the production under the lease was not in paying quantities. The issue, rather, turned on whether the written terms of the lease could override the implied presumption that production must be in paying quantities to sustain the lease after the primary term.
The lease contained a habendum clause setting forth a three-year primary term, with a secondary term extending as long as operations were conducted with no cessation for more than ninety consecutive days. The term “operations” included “production of oil, gas, Sulphur or other minerals… whether or not in paying quantities”.
The lessee claimed the lease was still in force because there was production under the lease with no cessation greater than ninety consecutive days, albeit (as noted above) such production was not in paying quantities. The lessor took the position that the lease had expired because such production was not in paying quantities. The lessor rested its argument on the implied presumption that production must be in paying quantities in order to sustain the lease. The court, however, determined that, absent ambiguity, it must give meaning to the specific terms of the lease. In doing so, the court focused on the italicized qualification above, which expressly and unambiguously negated the implied presumption that production must be in paying quantities to sustain a lease in the secondary term.
The takeaway here for mineral and royalty owners is simple: if a lessee proposes an unfamiliar form of lease, make sure to read the terms carefully, particularly with respect to any verbiage in the habendum clause (or elsewhere) that may allow the lease to remain in effect for an extended period without economic justification.
Post-Production Cost Deductions from Royalties
The next case, Devond v Sheppard, No. 20-0904, addresses the lessee’s ability to deduct post-production costs incurred by the purchaser of production from the lessor’s royalty.
The gating issue in many royalty calculation disputes centers on what constitutes “costs of production” versus “costs subsequent to production”, with the lessee often entitled to deduct the latter from the lessor’s royalty payments. The outcome of this issue may vary from state to state, as certain states have adopted differing rules. The more certain and favorable rule for lessees is what is referred to as the “market value at the well rule”, which stipulates that production for purposes of royalty calculation is complete when the oil or gas is captured and brought to the surface. It is possible to contract around the applicable default rule by including an express lease provision that spells out the parties’ intention to the contrary.
The lease at issue in this case applied to minerals in the Eagle Ford Shale and, therefore, was subject to the Texas market value at the well rule. The lease, however, contained the following provision:
“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 lessee was selling the oil and gas under various contracts that provided for index pricing, less certain post-production costs incurred by the purchaser of production (e.g., gathering, handling and other transportation costs). Under a typical oil and gas lease, it would be permissible for the lessee to deduct these post-production costs incurred by the purchaser of production because such costs are incurred after the oil and gas is sold.
The court, however, focused again on the specific wording of the lease, and determined the parties’ intention with the above referenced provision was to specifically prevent such deductions from the lessor’s royalty. The lessee argued that this language was “surplusage” and applied only to pre-point-of-sale expenses, but the court disagreed, noting there was nothing in the language of the lease that limited the royalty calculation to pre-point-of-sale expenses.
This case provides yet another example of how the specific wording of a lease can dictate the outcome of a case, even when the ruling is contrary to what many would consider industry norm.
The Estate Misconception
In Van Dyke v Navigator Group, the Texas Supreme Court was tasked with determining the proper mineral reservation in a century old mineral conveyance that contained a double fraction in the reservation language.
Fractionalized ownership is common (if not the norm) in the oil and gas industry. Title disputes often arise when fractional interests are conveyed or reserved that use a double fraction to describe the conveyance or reservation; an ambiguity may arise as to whether the conveyance or reservation was intended to be a fraction of the entire estate or a fraction of the interest owned.
The mineral conveyance in this case reserved to the grantor “one-half of one-eighth of all minerals and mineral rights…”. The logical interpretation of this reservation would be a reservation of a one-sixteenth mineral interest (i.e., 1/2 x 1/8 = 1/16). However, the court ruled in favor of the grantor’s successors in holding that the mineral conveyance reserved one-half of the entire mineral estate.
In doing so, the court relied in part on what is referred to as the “estate misconception”, which recognizes that at the time of the mineral conveyance, the term “1/8” was widely used to refer to the entire mineral estate. This is reflective of the mistaken belief that a lessor retained only a 1/8 interest in the minerals upon entering an oil and gas lease, rather than the entire mineral estate in fee simple determinable with the possibility of reverter. In issuing its ruling, the court went a step further to mandate a presumption that the use of 1/8 in a double fraction in the reservation language of historical mineral conveyances refers to the entire mineral estate, not just 1/8 of the mineral estate. This presumption, however, is rebuttable by other language in the conveyance that reflects the parties’ intention to convey only a fraction of the mineral estate. But absent such other language, a presumption may apply that a reference to 1/8 of the mineral estate refers to the entire mineral estate.
This decision could have serious economic consequences for those who derived or sold mineral interests subject to conveyance documents affected by the estate misconception.
RELATED: UNDERSTANDING MINERAL RIGHTS: A THREE-PART SERIES
