Unitex WI, LLC v. CT Land & Cattle Co., LLC, No. 07-23-00390-CV, 2024 WL 3249338 (Tex. App.—Amarillo June 28, 2024, pet. filed)
Mineral owners are often subject to general oil and gas lease forms that include provisions benefitting the surface estate. But, when they own no interest in the surface, who, if anyone, has the right to enforce those provisions?
In this case, CT Land and Cattle and Cattle Co., LLC sought to enforce a provision in a 1948 mineral lease requiring Unitex WI, LLC and Unitex Oil and Gas, LLC (Unitex) to bury pipelines on the ranch land surface CT Land acquired in 2013. Minerals had been developed from the property over the years, and pipelines existed on the land when CT Land purchased it. In 2019, CT Land invoked the burial provision in the mineral lease and sued Unitex for breach of the lease and for declaratory relief when Unitex refused to comply. After a bench trial, the trial court ruled in favor of CT Land, finding that CT Land had the right to enforce the pipeline burial provision and that Unitex was required to bury all pipelines constructed under the 1948 lease below plow depth as quickly as reasonably practicable. Unitex appealed this finding.
On appeal, among other things, the court examined whether CT Land could enforce the pipeline burial provision in the mineral lease. Notably, the lease specified that the “Lessee” was required to bury pipelines below plow depth when requested by the “Lessor.” CT Land was not a party to the original lease, nor a lessor. Nevertheless, CT Land argued that the surface deed from Andrew P. Fuller Revocable Trust (the Trust) to its predecessors (the Senns) conveyed the rights of the lessor, including the right to enforce the burial provision because that conveyance was made “subject to” the mineral lease. CT Land argued that by rendering the conveyance to the Senns “subject to” that lease, the Senns (and ultimately CT Land) “were ‘assigned the rights, interests, and obligations of the lessor under the Lease which pertain to the surface estate.’” The appellate court disagreed with CT Land’s interpretation of the “subject to” clause, finding that it merely limited the estate being conveyed by acknowledging the existing mineral lease but did not create new rights for the surface owners. Thus, the burial covenant remained with the lessor’s estate and did not pass to the Senns or CT Land.
Citing two Fifth Circuit cases, CT Land also argued that the burial provision ran with the land, meaning that it could be enforced by successive surface owners. After noting that federal precedent is not binding in Texas state courts, except on issues of federal law, the court explained that the cases cited by CT Land also suggested that covenants running with the land could be limited or abrogated under certain conditions, such as when the parties expressly detached the covenant.
Turning CT Land’s argument, the court emphasized that the 1948 lease specifically granted the right to require burial of the pipelines to the “Lessor,” which included the original lessors, their heirs, successors, or assigns. Importantly though, the lease did not extend this right to future surface owners. The court found that had the original parties to the lease intended for the covenant to be enforceable by subsequent surface owners, they could have explicitly used language to that effect. Their failure to do so, the court found, indicated an intent for the right to be exclusive to the lessor and those holding the lessor’s interest under the lease.
The court also found that the burial provision had been effectively detached from the surface estate through the “subject to” clause in the deed that conveyed the property to CT Land’s predecessors. According to the court, the “subject to” clause limited the estate being conveyed by making it subordinate to the existing mineral lease, but it did not transfer the lessor’s rights to the surface owners. Moreover, the court reemphasized that the Trust reserved mineral rights and the right to use the surface for mineral development, including the right to lay pipelines. This reservation of rights further indicated that the burial covenant remained with the lessor’s estate and was not passed to subsequent surface owners. If CT Land were allowed to enforce the burial provision, it would conflict with the Trust’s reserved rights to use the surface for mineral development.
In this case, the Texas Supreme Court affirmed the Railroad Commission’s rejection of 16 applications to force pool a narrow winding tract of riverbed minerals with neighboring horizontal wells pursuant to the Texas Mineral Interest Pooling Act (“MIPA”). The Court held that, because the wells would not drain the riverbed minerals, and because the applicant did not propose and prove that the wells could be drilled differently or extended to reach the riverbed minerals, substantial evidence supported the RRC's determination that the applicant failed to make a “fair and reasonable” offer to voluntarily pool as required by MIPA.
The applicant, Ammonite Oil Gas Corporation, was in the business of acquiring State riverbed leases and then getting them included in adjacent pooled units. In 2015, Ammonite acquired a lease of State minerals covering a narrow and winding stretch of the Frio River. EOG Resources, Inc. owned oil and gas leases on lands adjoining the river on both sides. EOG had permits for 16 horizontal Eagle Ford shale wells along the river banks, and was in the process of drilling the wells.
Ammonite sent EOG a series of letters proposing the formation of 16 pooled units, one for each well. Ammonite referenced “existing well[s]” and attached the plats associated with EOG’s existing drilling permits. Those plats reflected that none of EGO’s wells would reach the riverbed. Ammonite did not include any proposal or show that the wells could be drilled differently or extended to reach and produce Ammonite’s minerals. EOG rejected Ammonite’s offers.
Ammonite filed 16 MIPA applications with the Railroad Commission, one for each well. Ammonite did not put on any evidence of drainage or other technical evidence.
By the time of the hearing, all of the wells had been drilled, and it was uncontested that they were not draining the riverbed tract. EOG argued that, without evidence of drainage, Ammonite’s pooling offer was not “fair and reasonable.” EOG characterized Ammonite as seeking to obtain a share of production from EOG’s wells without contributing anything to them. EOG presented unrebutted expert testimony opining that Ammonite’s riverbed minerals could possibly be drilled and produced in the future with changes in technology or markets. EOG’s expert also testified that the wells require significant capital investment, and that any single well carried a significant risk of commercial failure, such that success must be measured at the portfolio level with optimal spacing to maximize recovery and prevent waste. The Railroad Commission rejected the applications.
The Texas Supreme Court first analyzed the “fair and reasonable offer” requirement for a MIPA application. Because that phrase is not defined in MIPA, its application is subject to the Railroad Commission’s discretion, to which courts give substantial deference. In the Court’s view, the Railroad Commission was acting within its reasonable discretion, because EOG’s wells, as permitted, did not drain the riverbed tract, and Ammonite made no effort to show that it was possible for EOG to modify its drilling plans or extend its existing wells to reach the riverbed.
The Court noted that MIPA requires pooling orders to afford each owner a “fair share,” yet Ammonite was effectively seeking a share of EOG’s production without contributing any minerals of its own. Further, the Court pointed to EOG’s unchallenged expert testimony, and reasoned that requiring EOG to give Ammonite a share of production without anything in return would increase the risk that the wells would not be commercially viable.
Ammonite made a number of arguments that were rejected by the Court, and the Court’s reasoning may be notable to practitioners. Ammonite argued that its offers were fair and reasonable when made because, at that time, “it would have required little additional drilling for each well to reach the riverbed tracts.” The Court rejected this argument, reasoning that Ammonite’s offers were based solely on the wells as they were permitted, which would not reach or produce riverbed minerals. In the Court’s view, in order to be fair and reasonable, Ammonite would have had to propose and demonstrate the feasibility of different drilling, extending the wells, or of drilling additional wells. Ammonite’s offers did neither, and therefore the Court held the Railroad Commission could reasonably hold they were unreasonable on their face.
The Court then turned to the Railroad Commission’s second basis for rejecting Ammonite’s application: its finding that Ammonite’s requested order would not prevent waste or protect correlative rights. In the Court’s view, waste is something that “reduces or tends to reduce the total ultimate recovery of oil … from any pool.” “Correlative rights guarantee a mineral interest owner an opportunity to produce a ‘fair share’ of the reserves underlying his land.” Ammonite argued that the location of EOG’s wells leaves Ammonite’s riverbed mineral stranded, thereby resulting in waste and denying Ammonite its fair share. In the Court’s view, even if Ammonite’s riverbed minerals were left stranded, a forced-pooling order would not change that because EOG’s wells were already drilled and producing at the time of the Railroad Commission’s order, and those wells cannot produce riverbed minerals. Ammonite characterized EOG’s expert testimony that future technology might allow riverbed drilling as “beyond speculative,” but the Court rejected that argument explaining that Ammonite had the burden of proof and failed to put on any rebuttal expert testimony.
Ammonite also argued that a forced pooling order at this time would still prevent waste by incentivizing EOG to drill new wells or rework existing ones to extend into the riverbed. In the Court’s view, the Commission’s refusal to stretch its “limited authority to force pooling this far” was not unreasonable and was consistent with its prior decisions of refusing to exercise MIPA authority without proof of existing drainage. The Court also cited commentary explaining that, if additional drilling is required to drain the acreage sought to be pooled, then the requested force pooling should be denied in order to avoid the drilling of unnecessary wells.
Ammonite also argued that EOG should have originally proposed the wells to extend into the riverbed. The Court rejected that argument, as there was no proof that Ammonite offered its consent to that drilling, and Ammonite made no attempt to prove that it would have been technically or commercially feasible for EOG to do so.
This lease royalty case involved a dispute over whether the lessee was permitted to deduct volumes of gas used off the premises to power post-production activities on other gas produced from the same well.
The lease provided for a royalty calculated based on the “market value at the well.” The lessor acknowledged that this “at the well” language, if standing alone, would generally entitle the lessee to deduct volumes of gas used in post-production activities. However, the lessor argued that two additional lease provisions modified that result. The Texas Supreme Court disagreed.
First, the lessor relied on a portion of the royalty clause indicating that royalty was due “on gas … produced from said land and sold or used off the premises.” The lessor argued that this meant royalty was due on all volumes produced and used off the premises, which would not allow removal of fuel gas volumes used off premises when calculating royalty. The Court disagreed, reasoning that although the lessee was obligated to pay a royalty on all gas produced, the lessee was entitled to convert its downstream sales price into an at-the-well market value by deducting from its sales price the value of the gas that was used off the premises to prepare other royalty-bearing gas for sale. In the Court’s view, when the value was calculated in this manner, the lessor was still paid on all volumes of gas produced.
The lessor also relied on a free-use clause, which provided “Lessee shall have free use of oil [and] gas for all operations hereunder, and the royalty shall be computed after deducting any so used.” The lessor argued that this meant the lessee was only allowed free use of gas for operations on the leased premises, and was therefore required to pay a royalty for gas used in operations off the leased premises. The Court rejected that argument, reasoning that it was irrelevant whether the lessee was allowed free-use of certain gas, because that would not change the fact the lessor held an at-the-well royalty which meant it must share in post-production costs.
The lessor relied on BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 387 (Tex. 2021), where the Texas Supreme Court held that a free-use clause allowing free use of gas used “in all operations … hereunder,” meant the lessee was entitled to free on-lease use of gas, but did not entitle the lessee to free use of gas off the leased premises. The Court distinguished Randle, reasoning that it involved a “gross proceeds” royalty which generally does not bear post-production costs and “so the question of how to account for post-production costs was not before the Court at all in Randle.” Further, in the Court’s view, nothing in Randle suggests that a free-use clause can change an at-the-well royalty holder’s obligation to bear its share of post-production costs.
