Articles Posted in Oil and Gas Law

The Texas Supreme Court has just issued an opinion in Point Energy Partners Permian LLC v. MRC Permian Co., ___ S.W.3d ___, 2023 WL ___, (Tex. Apr. 21, 2023) that involves the application of the force majeure language in an oil and gas lease.

Force majeure is a legal doctrine that excuses performance under a lease for certain unforeseen circumstances or “Acts of God”. In this case, the oil and gas lease required the oil company to commence drilling a new well by a certain date in order to prevent the lease from terminating at the end of the primary term. The oil company scheduled the drilling of a well, but for a date three weeks after the primary term of the lease had expired. (Presumably the lease was not being held by production).

The lease had a force majeure clause that said “[w]hen Lessee’s operations are delayed by an event of force majeure,” the lease shall remain in force during the delay with ninety days to resume operations. The oil company sent the lessor a letter invoking the force majeure clause in the lease, stating that they had to use their drilling rig to remedy wellbore instability on another (and unrelated) lease and that this prevented them from drilling the new well before the primary term expired. The problem was that a new oil company executed a new lease with the lessor after the primary term on the original lease expired.

The Texas Supreme Court recently issued an opinion in a case in which royalties were calculated on more than gross proceeds. Specifically, the Court approved royalty language that calculated royalty on the total of gross proceeds (which by definition does not include expenses) and post-sale expenses.

In Devon Energy Prod. Co. v. Sheppard, ___ S.W.3d ___, 2023 WL ___ (Tex. Mar. 2023) [20- 0904], the leases being considered provided for royalty payments based on gross sales proceeds. However, in what is frankly unusual language for leases, the leases stated that if “any reduction or charge for [postproduction] expenses or costs” has been “include[d]” in “any disposition, contract or sale” of production, those amounts “shall be added to the . . . gross proceeds.” (Emphasis added.) In other words, the leases actually required Devon Energy to add postproduction costs incurred by third-party purchasers to the gross proceeds from sale before calculating Sheppard’s royalty.

Devon disagreed that any amount should be added to the gross proceeds. The Court noted that the contracts that were used to determine gross sales proceeds used publish index prices at market centers downstream from the point of sale.

The Texas Supreme Court interpreted yet another confused mineral reservation in a deed in the case of Van Dyke v. Navigator Grp., ___ S.W.3d ___, 2023 WL ___ (Tex. Feb. 17, 2023). The 1924 deed contained a reservation of “one-half of one-eighth” of the mineral estate. The question was: did the grantor reserve a one-half interest in the minerals or a 1/16 interest in the minerals?

The evidence in the case reflected that the grantor and the grantees and even third parties for decades had treated the deed as having reserved a one-half interest in the mineral estate to the grantor and conveyed one-half to the grantees. However, in 2013, the grantees filed suit claiming that the grantor had reserved only a 1/16 interest (multiplying 1/2 times 1/8). The trial court granted the grantees’ motion for summary judgment and held that the deed reserved only a 1/16 mineral interest to the grantor and that the grantees received 15/16 of the mineral estate. The Court of Appeals affirmed.

The Texas Supreme Court reversed the decision of the trial court and the Court of Appeals. The Court reasoned that the meaning of the reservation depended on whether the use of the “one-eighth” in the double fraction was meant in a mathematical sense or was due to an estate misconception. The estate misconception happens because people mistakenly used to use the 1/8 fraction as a stand-in for the entire mineral estate, rather than a fractional share of the mineral estate.

Texas oil and gas companies can engage in a variety of procedures as part of their exploratory process before they drill an oil and gas well. One such procedure is seismic testing or a seismic survey. Seismic testing is a process that results in an image of the subsurface of property. The kind of seismic testing done most often in Texas uses a “thumper truck” which contains a large plate in the center of the truck that is thumped on the ground. The shock waves emanating from the thumping result in data that can be collected digitally and result in a map of the subsurface. Seismic testing can also be done by drilling shot holes into the ground, placing dynamite into the holes and then covering the holes over. When the dynamite is set off, the sound waves from the explosions generate data that, when collected, result in a map of the subsurface.

If you own the surface and the minerals, and you have not executed an oil and gas lease for the minerals, you do not have to allow seismic testing. However, if you sign an oil and gas lease, or if you don’t own the minerals and the mineral owner has signed an oil and gas lease, many leases allow for seismic testing. Of course, if you own the minerals and are signing an oil and gas lease, it may be important to limit or eliminate any right by the lessee to do seismic testing when you are negotiating the terms of that lease.

If a seismic test is going to be performed, it’s important to educate yourself about the test. Don’t sign the permit the testing company gives you. Instead, negotiate a permit that provides protections for the property. Things to consider include (but aren’t limited to):

In a case last year before the Texas Supreme Court, BPX Operating Co. v. Strickhausen, 629 S. W. 3d. 189 (Tex. 2021), the Court addressed whether the acceptance of royalty checks by a lessor constituted a ratification of the oil company’s pooling of the leased premises in violation of the anti-pooling clause in the lease.

Margaret Ann Strickhausen signed and oil and gas lease with BPX Operating that specifically prohibited pooling without the express written consent of the lessor. BPX sent her a ratification of pooling which she refused to sign. BPX pooled her property anyway. BPX continued to send her royalty checks, totaling over $700,000, which she deposited. BPX claimed that Ms. Strickhausen had therefore impliedly ratified the pooling of her property.

The Supreme Court stated: “Ratification is the adoption or confirmation by a person with knowledge of all material facts of a prior acts which then did not legally bind him and which he had the right to repudiate”.  In this case, there were a number of objective facts which indicated that Ms. Strickhausen did not agree with or consent to the pooling and that she accepted the royalty checks believing that these were the royalties she was entitled to without the pooling taking place. The Court further stated that “ratification is not a game of ‘gotcha’ ” and ruled that the lessor’s acceptance of royalty checks under these circumstances was not a ratification of the pooling by the BPX.

The Texas Supreme Court recently issued its long-awaited opinion in Terrance J. Hlavinka et al v. HSC Pipeline Partnership, LLC, —S.W.3d— (Tex. May 27, 2022). There were two important issues in this case: (1) whether a pipeline company transporting polymer-grade propylene can be a common carrier with condemnation authority under Texas Business Organizations Code Section 2.105 and (2) whether a property owner may testify during condemnation proceedings about recent arms’-length transactions with other pipeline companies as evidence of the current highest and best use of the property in determining the market value of the new easement.

The Court held that Section 2.105 does grant condemnation authority and that polymer-grade propylene is a qualifying product under that section. That makes sense since propylene is a petroleum by-product. The Court also held that one of the conditions for eminent domain, that the pipeline will be a common carrier for public use, is a legal question for a court to decide, and is not a fact question for the jury.

Finally, the Court held that “a property owner may testify to arms’-length sales of easements to other pipeline companies as evidence of the condemned property’s highest and best use”. (The trial court had excluded this evidence).

In a recent case decided by the Eastland Court of Appeals in Texas, Foote v. Texcel Exploration, Inc., the Court held that the operator of an oil well was not liable for cows apparently killed by an oil and salt water spill.

The Plaintiff leased property for grazing 650 head of cattle. Texcel Exploration Inc. operated an oil and gas lease on the property. The lease did not require Texcel to fence off the well and associated equipment, however Texcel had installed an electric fence around the tank battery (where produced oil and gas and salt water produced along with the oil and gas were stored). There was evidence that the cattle were breaking the fence each day and getting inside the fenced area and ultimately broke a PVC pipe on one of the tanks. Salt water and oil was found on the cows and eventually 132 cows died. The Plaintiff requested reimbursement for the value of the 132 dead cows, veterinary bills, special feed costs, shipping cost to relocate cattle, and lost profits from the surviving cattle being sold under expected weight.

The Court first sets out what is pretty well settled law in Texas for this situation: “[T]he owner/lessee of the surface estate in order to recover against the mineral lessee or operator for injury to his cattle must plead, prove and obtain a jury finding on one of the following:

The Texas Supreme Court recently issued its decision in Nettye Engler Energy L.P. v. BluStone Natural Resources II, LLC, Cause No. 20-0639, which has added to the Texas jurisprudence on the frequently litigated subject of post-production costs that can be deducted from a royalty interest.

The deed that conveyed the mineral interest to the grantee reserved a nonparticipating royalty interest “in kind,” which as the Court notes, differs from the standard monetary royalty because the grantor retained ownership of a fractional share of all minerals in place. The deed required delivery

of the grantor’s fractional share “free of cost in the pipe line, if any, otherwise free of cost at the mouth of the well or mine”.  The question became which pipeline does the deed refer to: the gathering lines or the interstate transportation line?

The Texas Supreme Court, in the recent decision of BPX Operating Co. et al. v. Margaret Ann Stockhausen, denied an oil company’s claim that acceptance of royalty checks by the mineral/royalty owner ratified the oil company’s illegal pooling of her property.

Strickhausen owned property in LaSalle County, Texas. She negotiated a lease that strictly prohibited pooling under any circumstances without her express written consent. Notwithstanding this lease provision, BPX Operating Co. (formerly BP) pooled her property without her consent. As soon as she learned that BPX had pooled her interest, Ms. Strickhausen had her lawyer write BPX reminding them of the anti-pooling clause in the lease and asking for the authority by which they pooled her property. The oil company responded by acknowledging the anti-pooling provision and requesting a ratification of the pooled unit. The oil company also threatened to put her royalties in suspense if she did not sign the ratification.

Ms. Strickhausen did not sign the ratification. She continued to get royalty checks, which were based on the pooling unit allocations, which she cashed. The oil company then offered to settle her wrongful pooling claim. Ms. Strickhausen rejected that offer and countered with a different settlement offer. Ms. Strickhausen apparently believed the royalty checks were the royalty she was entitled to under the lease without pooling.

Production sharing and allocation wells have been drilled in Texas for some time, and have been used almost exclusively for horizontal wells. (An allocation well is a horizontal well drilled across two or more lease lines without creating a pooled unit that includes the leases. A production sharing well is an allocation well for which production sharing agreements have been signed by mineral owners in all tracts that are crossed by the well.) However, the Texas Railroad Commission has never adopted a formal rule for issuing permits for these types of wells, by using the procedure in the Texas Administrative Code that all Texas agencies are supposed to follow when they want to adopt a new rule. The Administrative Code requires publication of proposed rules and opportunities for public comment before they are adopted. At first, the Commission approved a permit for these wells if the operator obtained signed production sharing agreements for at least 65% of the mineral owners. In recent years, the Commission began to approve permits for these wells even though no mineral owners had signed production sharing agreements.

In this case, two mineral owners in Karnes County, Texas, the Opielas, contested the granting of an allocation well permit by the Commission  to Magnolia Oil & Gas. On May 12, 2021, the 53rd District Court in Travis County reversed an order of the Texas Railroad Commission denying the mineral owners contest.  ( Elsie and Adrian Opiela v. Railroad Commission of Texas v. Magnolia Oil & Gas Operating Inc., Cause No. D-1-GN-20-000099). The Court held, in part, that “(t)he Commission erred in adopting rules for allocation and Production Sharing Agreement (“PSA”) well permits without complying with the requirements of the Administrative Procedure Act, Tex. Govt Code § 2001.001 et seq., and further erred in applying those rules by issuing well permits for the Audioslave A 102H Well (the “Audioslave Well”)”. The Court sent the case back to the Railroad Commission for “further proceedings consistent with this judgment.”

Texas oil and gas attorneys have been scratching their heads for some time at the Commission’s practice of granting permits for these types of wells without a formal rule. We don’t know whether the Railroad Commission will appeal this decision or not. If it does not, or if it does and the appellate court upholds the district court decision, what is the status of the many allocation and production sharing wells already drilled? Are they all void? Alternatively, are just the allocation wells permitted and drilled without mineral owner consent void? To be determined.