Davenport v. EOG Resources, Inc. is an appeal of a temporary injunction. The title of this post tells you the result.

Davenport owned four tracts comprising 5,000 acres in Webb County that were originally part of a larger tract burdened by the 1967 Garner oil and gas lease. EOG has operated the lease since 1999 and its chief point of entry had been the Krueger Road gate on the east side of the ranch. In 2022 Davenport and EOG negotiated a water purchase agreement allowing a large frac pond and for EOG to purchase fresh water and have the right of ingress and egress on designated roads for the purpose of taking the water.  

EOG informed Davenport of its plans to drill new wells and to access the ranch from the west via a new gate using a new road. Davenport objected and sued, arguing that EOG already had access to the proposed sites via Krueger Road, and if a road was needed there was a better route.

EOG’s witnesses at the temporary injunction hearing testified:

  • The unpaved Krueger Road with its four wooden bridges and below-grade water crossings could not support the heavy equipment needed for its planned nine 12-well pads and associated production facilities.
  • EOG had been accessing the Garner lease from an adjacent ranch north and west of the Davenport Ranch.
  • EOG planned new roads would run primarily east-west across the northern portion of the ranch.
  • Irreparable injury would occur because of unrecoverable loss of hydrocarbons based the delay in offsetting production.

Davenport’s witnesses testified:

  • EOG did not express any concerns about Krueger Road
  • EOG had been running large trucks and other equipment over that road and the wooden bridges with no problem.
  • EOG’s planned route for the new road would damage a new asphalt road and waterlines running across his property.
  • The new entrance is visible from his home, and
  • He was concerned about the safety of his children from passing vehicles.

Davenport argued that in the water agreement EOG agreed to use the Krueger Road gate. EOG responded that the agreement pertained only to activities in getting water from the frack pond and relied on its pre-existing rights of access under the Garner lease.

The trial court found that Kreuger Road was not capable of sustaining EOG’s operations and enjoined Devonport from interfering with EOG’s access to the ranch. The status quo ante was EOG’s previously unhindered access to the ranch for its oil and gas operations.

The law

The purpose of a temporary injunction is to preserve the status quo of the litigation’s subject matter pending a trial on the merits. To prevail on an application three elements must be pled and proven:

  • a cause of action against the defendant
  • a probable right to the relief sought, and
  • probable imminent and irreparable injury in the interim.

The court of appeals cannot overrule a trial court’s decision unless the trial court acted unreasonably or in an arbitrary manner without reference to guiding rules or principles. That is a high hurdle for any appellant.

EOG proved all three elements: its cause of action under the oil and gas lease, a probable right to recover because the trial court gave greater weight to the credibility of EOG’s witnesses, and EOG needed to timely develop planned facilities and forcing it to access the ranch through the Krueger Road gate would delay or deny development which would harm future production, the reservoir damage could be permanent, and hydrocarbons could be irretrievably lost. Thus, damages would be difficult if not impossible to calculate.

Your musical interlude. Jimmy Buffet RIP.

Co-author Stephen A. Cooney

In Cactus Water Services LLC v. COG Operating, LLC., a divided Texas court of appeals answered the question this way: The oil and gas producer prevails over the purchaser of the surface owner’s right to own and sell produced water.

The majority discussed the composition of produced water. To be scientific, it’s got a bunch of nasty s$%^ in it that needs to be gotten rid of. But recent water treatment technologies have made what was once a cost for operators into a new industry in which treated wastewater can be sold back to operators.

The contracts

Along with its rights under oil and gas leases, COG has agreements with surface owners giving it the right to gather, store and transport oil and gas waste, lay lines on the surface for freshwater and produced water, and lay pipelines for transportation of oil and gas, produced water and other oilfield-related liquids or gases. Under the leases COG is not allowed to sell produced water to third parties for off-premises use.

The surface owners granted Cactus Water the right to own and sell all water produced from oil and gas wells on the property, defining water as all water produced from geologic formations.

COG sued for declaratory judgment that it has the sole right to the produced water by virtue of its leases and surface use agreements and common law. Cactus Water counterclaimed that it had ownership of produced water under its own agreements.

The court

The regulatory scheme governing handling and disposing of produced water includes these provisions:

  • Texas Natural Resources Code 91.1011: oil and gas waste includes salt water and other liquids.
  • TNRC 122.001(2): Fluid oil and gas waste is water containing salt or other mineralized substances from hydraulic fracturing, including flowback water, produce water, etc.
  • Water Code 27.002(6): Oil and gas waste includes saltwater, brine and other liquid or semiliquid waste material.
  • 16 Texas Administrative Code 3.8(a)(26): Oil and gas waste includes saltwater, other rmineralized water and other liquid waste material.
  • Water Code 27.002(8): Freshwater means water having properties that make it suitable for beneficial use.
  • Water Code 35.0029(5): Groundwater is water percolating below the surface.
  • 16 TAC 3.8(a)(29) Surface or subsurface water is groundwater, percolating or otherwise.

The majority concluded that in the regulatory lexicon, produced water cannot be groundwater. There is a clear distinction in the law between the two. And industry practice characterizes produced water as oil and gas waste rather than groundwater.

Given the legal framework, produced water is categorized within the former and places the burden of safe disposal on operators. For years operators have had the rights and duties associated with processing, transporting, and disposing of oil and gas waste, including produced water.

COG’s leases were executed before the parties saw produced water as having value. The majority concluded that parties’ knowledge of the value or even the existence of a substance at the time a conveyance ia executed is irrelevant to its inclusion or exclusion from a grant of minerals.

The dissent thought otherwise:

  1. Water recovered from operations was not conveyed by the leases’ granting language. It is well settled that groundwater is part of the surface estate that can be severed and conveyed similar to the mineral estate.
  • Characterizing produced water as waste does not automatically make it subject to the granting clause in the leases. Under case law, even deep, mineralized water produced from a well belongs to the surface estate and is only transferred by specific conveyance.  “Water by any name, even mixed with other substances, still remains water.”
  • The Texas Supreme Court “has not distinguished between different types of groundwater indicating that some water does not belong to the surface estate.”
  • The regulatory framework and industry practice should have nothing to do with ownership of produced water. Just because an operator has a duty dispose of this waste does not mean it has ownership.

Stay tuned. This debate is not over.

Your musical interlude.

Rhetorical Question: When will Texas be done with fixed/floating royalty cases such as Johnson et al v. Clifton et al?

Rhetorical Answer: When scriveners of deeds that are open to eight conceivably plausible meanings have completed their remedial scrivening courses.

How did it happen?

In 1951 Young and others conveyed to Clifton and others several thousand acres in Reeves County by a deed reserving a 1/128 interest in oil, gas and other minerals. It was stipulated that the land was under lease with a 1/8th royalty and grantees shall receive 1/16th of the royalty provided for in the lease, but grantees would not be entitled to receive any of the bonus for future leases, would not have executive rights, and would only receive in subsequent leases a “1/128th (1//16th of the usual 1/8th royalty)”. The title “Mineral Deed was crossed out and substituted with ”Royalty Deed”, handwritten. Current lease royalties are 25% or 22.5%.

 Grantees’ descendants sued, arguing that the deed conveyed a floating 1/16th NPRI. COG and other defendants argued limitations, waiver, estoppel, payment, laches, and trespass to try title.

The trial court ruled that plaintiffs take nothing, leaving them with the 1/128th royalty they had historically received.

Possible outcomes

According to the litigants, the deed conveyed:

  • A nonparticipating 1/16th mineral interest and a floating 1/16th royalty
  • A fixed 1/128th nonparticipating mineral interest and a floating 1/128th royalty in future leases
  • A 1/128th mineral interest and a fixed 1/128th in future leases
  • If there was a NPRI and not a mineral interest, then also a fixed 1/128th royalty in future leases
  • A floating 1/128th royalty interest
  • A floating 1/16th royalty interest
  • A fixed 1/128th royalty interest, or
  • Two separate estates, a 1/128th mineral interest and a fixed 1/128th royalty in future leases.

Title examiners can debate whether some of these constructions end up at the same place, but the court deemed them different enough to discuss each.

The result

The court of appeal reversed, granting judgment that the deed conveyed a nonparticipating 1/16th mineral interest and floating 1/16th royalty. The deed conveyed a mineral interest shorn of all attributes but for the right to receive royalty payments.

The court could reconcile the entire deed only by interpreting the granting clause as conveying a mineral estate and the remainder of the deed as clarifying that the grantors intend to strip all attributes of the mineral estate but for the royalty interest.

Each unsuccessful interpretation suffered more or less the same defect:  failing to consider, or ”harmonize”, all aspects of the deed.

Estate misconception in a different scenario

The court applied the Van Dyke v. Navigator estate misconception doctrine even though there was no double fraction in the granting clause. Discussing the “legacy of the 1/8 royalty”, the court concluded that 1/8th had acquired a special meaning in the standard royalty contract. Parties used 1/8th as a placeholder for future royalty without understanding that reference to set an arithmetical value. 1/128th is a multiple of 1/8th raised the presumption that the grantors believed they only owned 1/8th of the mineral estate. Rather than conveying a 1/128th interest, they intended to convey 1/16th of what they believed they owned. The result was a 1/16th mineral interest conveyance which has a corresponding 1/16th floating royalty interest. This interpretation reconciled the granting, existing-lease, and future-lease clauses. Use of the double fraction “1/16th of the usual 1/8th” is consistent with the description of a floating 1/16th royalty.

The court declined to address the presumed grant theory because it was not raised at trial or in appellate briefing. That affirmative defense must be pleaded at the trial court to preserve the issue for appeal.

Your musical interlude.

In Smart v. 3039 RNC Holdings LLC, the court reminds us that it will harmonize all parts of a contract, even one that “is not a model of clarity”, to reach the correct result.

RNC owned the surface and 50% of the mineral estate in a 45.6 acre tract in Karnes County. RNC agreed to convey and Smart agreed to purchase the surface and part of the mineral estate. Nancy, part owner of RNC and a real estate agent, used the then-in-effect TREC Farm and Ranch Contract and an Addendum for Reservation of Oil, Gas and Other Minerals to memorialize their agreement.

Paragraph 2F of the Contract said any reservation … “is made in accordance with the attached Addendum or Special Provisions”. The parties addressed the percentage of minerals in the Addendum. Paragraph 11 of the Contract, Special Provisions, said, “Seller to convey 10% mineral interest (of what the seller owns – 50%) to Buyer, see mineral reservation.”

The Mineral Reservation Addendum checked the box, “Seller reserves an undivided 40% interest in the mineral estate owned by Seller. NOTE: If Seller does not own all of the mineral estate, Seller reserves only this percentage or fraction of Seller’s interest.“

Nancy filled in the blanks and everyone signed. The title company prepared a Warranty Deed providing that “Sellers reserve an undivided 2/5ths of all oil, gas … “. The deed did not mention or account for the 50% of the mineral estate that was not RNC’s to convey.

The parties agreed that on its face the deed appeared to convey 3/5ths of the entire mineral estate and also agreed to reform due to a scrivener’s error. The parties disagreed on the division of the mineral estate.

Smart’s position: The Addendum unambiguously conveyed 30% of the total mineral estate and reserved 20% to RNC. RNC’s position: When read as a whole and properly harmonized, the contract unambiguously provided that RNC would reserve 40% of the total mineral estate and convey 10%.

30% to Smart and 20% to RNC.

Smart argued:

  1. The court should disregard Paragraph 11 and rely on the Addendum. That would render Paragraph 2F of the contract meaningless, so it failed.
  • Paragraph 11 should be subordinated to the Addendum because the Addendum attributes most essentially to the agreement. But the Addendum did not contain any essential terms that Paragraph 11 lacked.
  • The court may elevate one contractual provision over another without attempting to harmonize the two. No. That is contrary to principles of contract construction.
  • The parties intended for the Addendum to control because Paragraph 11 instructed the reader to “see the Addendum”.  No. The contract did not acknowledge the precedence of the Addendum.
  • Doubt as to the proper construction must be construed against RNC because Nancy drafted the agreement. No. Courts should not rely on that principle in determining whether the agreement is ambiguous or when construing an unambiguous agreement.

5% to Smart and 45% to RNC.

Paragraph 11 was subject to two potential meanings. 10% of RNC’s 50% or 5% of the total to Smart is a reasonable interpretation of Paragraph 11 in isolation, but that would require the court to ignore the Addendum. Thus 5% to Smart and 45% to RNC was not a reasonable conclusion.  

40% to RNC and 10% to Smart – Bingo!

Paragraph 11 and the Addendum could be harmonized to give effect to both. The result was the parties’ intention that 40% of the total mineral estate would be reserved to RNC and 10% conveyed to Smart. This was a reasonable construction of the contract as a whole.

The contract was not ambiguous. Summary judgment for RNC was proper.

Your musical interlude. Sinead O’Conner RIP.

The plain, ordinary, and generally accepted meaning of a word doesn’t mean “anything goes”. It depends on context, says the Supreme Court of Texas in Finley Resources Inc. v.  Headington Royalty Inc., a dispute over the meaning of “predecessors”. For the underlying facts see our post on the court of appeals decision.

The release

The release in an acreage-swap agreement between Petro Canyon Energy and Headington said that “Headington [ releases, etc.] Petro Canyon and its affiliates and their respective officers, directors, shareholders, employees, agents, predecessors and representatives… [for all claims, etc.]… related in any way to the Loving County Tract.”

The parties carved out Petro Canyon’s agreement to plug the wells and restore the property. Finley was not named anywhere in the agreement.

The discussion

Headington sued Finley for $54 million in damages related to Finley’s operation of wells on the Arrington lease on the Loving County Tract. The question: Did “predecessors” include Finley such that Headington’s claims against Finley arising from termination of the Arrington lease were released?

A release will discharge only those persons “named” or “identified” “with descriptive particularity” and that their identity or connection to the released claims “is not in doubt”. Stated another way, could a stranger readily identify the released party?

The court gave “predecessors” its plain, ordinary, and generally accepted meaning. But it wasn’t that simple. The word need not carry every meaning to which it is naturally susceptible. A primary determinant of meaning is context, said the court.

Finley/Petro Canyon’s broad view was that the release included all forms of predecessors given:

  • the ordinary meaning as one who precedes,
  • the absence of a modifier,
  • otherwise broad and encompassing language, and
  • surrounding circumstances. Thus, “predecessors” naturally referred to predecessors in title.

Headington’s narrow view:

  • the meaning was informed by its antonym;
  • “successors” of a business entity classically refers to legal succession such as merger or consolidation and;
  • by including “predecessors” in a categorical list of entity-related groups, that is how the release uses the term.
  • Also contextually, predecessors could not refer to preceding well operators because the release expressly excluded liability for plugging the Arrington wells.

The release described what was being released: claims related in any way to the Loving County Tract; and who was being discharged: by categorical language the parties intended to extend the benefits to classes of unnamed individuals and entities. The identity of constituent class members turned on the meaning of the categorical terms.  

The court acknowledged the “predecessor” often is shorthand for predecessor-in-title. So, the court asked, what is the grammatical use? “Predecessors” grammatically referred back to the entities released. The syntactic use of “predecessors” connoted a prior connection to corporate entities themselves and not the land.

The court concluded with respect to surrounding circumstances that even when an agreement is unambiguous, context that informs the meaning of the language includes objectively determinable facts and circumstances that contextualize the transaction.

Finley was not named in the agreement despite the looming threat of litigation and Headington’s proximal demand for information bearing on termination of the Arrington lease. Evidence of surrounding circumstances cannot contradict, change, enlarge or supplement the contract language and instead may only give the chosen words a meaning consistent with that to which they are reasonably susceptible.

The result

“Predecessors” bore the narrower meaning Headington ascribed to it. but that followed not from any rule requiring leases to be construed narrowly or for want of descriptive particularity, but rather from the plain meaning of the term as constrained by the linguistic and grammatical context in which it was used.

Your musical interlude.

California has passed Senate Bill 1137, which will prohibit drilling of new oil and gas wells and reworking of existing wells in certain areas.

Here is SB 1137 in legislativese (analysis comes first, then the text):

Here, in small part, is what the Bill does:

The Bill defines “sensitive receptors” as Hollywood A-listers and Stanford law students and their VP of DEI scolding who cannot tolerate voices they don’t agree with “residences, education facilities, day care centers, colleges and universities, community resource centers, healthcare facilities, live-in housing, prisons and detention centers, and any building housing any business open to the public.” The Bill is silent on porta-potties.

A “health protection zone” is any street in San Francisco not covered in syringes and human fecal matter a 3,200-foot radius around any sensitive receptor.  

The state’s oil and gas regulatory agency is prohibited from approving a permit to drill or rework a well within a health protection zone except for very limited circumstances.

An applicant for a permit to drill or rework a well within a health protection zone must include a sensitive receptor inventory map of the area and a myriad of other plans and information.

The Bill unleashes the full weight and authority of the Air Resource Board and State Water Board to adopt, implement and enforce a host of what one would expect to be burdensome and costly regulations.

Indemnity bonds, in addition to the current blanket bond, will be required.

Failure to comply to the new law will be a crime.

Reaction to the Bill

The Legislature passed it by a substantial margin; Governor Newsom heartily supports it; OPEC+ hasn’t said, but one would suspect they are in favor; the usual suspects support it: Natural Resources Defense Council, Central California Environmental Justice Network, EarthJustice, Sierra Club of California, and Voices in Solidarity Against Oil in Neighborhoods.

The industry has raised millions of dollars in support of a referendum to veto the Bill that will be voted on in the general election ballot in 2024. The referendum is supported by the California Independent Petroleum Association, the Construction Trades Council of California, and scores of small producers, service companies and royalty owners.

CIPA warns “If implemented SB 1137 we increase California’s already high gas prices by decreasing our energy supply and replacing it with expensive imported foreign oil that tankers must transport from countries that do not uphold the same environmental or labor standards.”

Having paid $3.25 for a gallon of regular in Dallas last month and $4.75 the next week in LA, I sympathize with the middle class whose energy bills will become even more unaffordable.

Greenpeace and the MSM blame the veto effort on their reliable villain, “Big Oil”.

And the MSM gets it wrong in several ways. Texas did not impose buffer zones and MSNBC omitted the ban on reworking permits.

What of the future?

According to the California Chamber of Commerce, good-paying oil and gas-related employment in the state will be lost; wealth for small operators, service companies and royalty owners will be destroyed; tax revenue will diminish.

According to the Wall Street Journal in 1982 California produced 61.4% of its oil consumption and imported 5.6%. Those numbers in 2019 were 29.7% and 58.4%.

California’s oil imports come mostly from the Middle East and South America, unregulated  producers of dirty oil such as human-rights abuser Saudi Arabia and Amazon forest destroyer Equador. These are places with policies Californians claim to disdain. California will be potentially greener and cleaner, and definitely poorer, and the exporters will be dirtier and richer.

Your musical interlude.

Co-author Taylor Hall*

The Texas Legislature has created a new Texas Business Court (the TBC) with jurisdiction over cases involving certain qualified (as in “big-dollar”) business transactions. HB 19 could affect large oil and gas cases; how and to what extent is to be determined. The consequences, intended and unintended, will be good and bad, depending on your point of view.

The Bill

A party can opt to remove certain suits from a district or county court to the TBC, which will have concurrent jurisdiction in civil disputes, if the amount in controversy exceeds either:

  • $5 million in derivative actions on behalf of an organization, business-related actions alleging a breach of duty, or actions regarding governance and other internal affairs of an organization, or
  • $10 million in minimum aggregate value (but not for loans by financial institutions).

The court would have the authority to grant the same relief as a district court but would not have jurisdiction over suits for legal malpractice, personal injury and against government entities without government consent.

The Governor, with the advice and consent of the Senate, will appoint the judges to the TBC. There will be two judges from certain appeals courts and one from certain others. Each judge will serve a term of two years and must be:

  • at least 35 years old,
  • a U.S. citizen,
  • a resident of the county within the division of the TBC to which the judge is appointed, for a minimum of five years before appointment, and
  • licensed in Texas with at least ten years of experience either (1) practicing complex civil business litigation or business transaction law, (2) serving as a judge of a Texas court with civil jurisdiction, or (3) a combination thereof.

The Act will apply to suits filed after September 1, 2024.

Comparison with the Delaware Court of Chancery

The new court has been compared to the Delaware Court of Chancery. One difference is that in the TBC, juries rather than the judge would decide questions of fact. In Delaware, fact questions are resolved by the court. Query: Is that a bug or a feature?

The Delaware court was established in 1792 and has over 200 years of precedent to rely upon. The TBC will take years to develop firm and consistent precedent. And TBC judges only serve two-year terms, contrasting with Delaware court’s twelve-year terms.

This bill creates a Fifteenth Court of Appeals that operates independently from other state appellate courts. This court will hear all appeals from the TBC unless the Texas Supreme Court has concurrent or exclusive jurisdiction.

There are more than a few opponents of this new system who see the purpose of the new court of appeals as protection of business cases from Democratic judges that now preside in existing appellate courts in Dallas and Houston. This contrasts with the Delaware court, where direct appeals are taken solely to the Delaware Supreme Court.

Ultimately, the TBC does not directly emulate the Delaware court because it adopts a jury system, lacks centuries of precedent, adopts shorter terms for judges, and has a separate court of appeals. It will take time to see the full effect of this law.

For more on the Act, see this more detailed report, prepared before the Act became final and signed by the Governor. DISCLAIMER: This post and the attached report do not reflect the opinions of Gray Reed or any of its clients.

Your musical interlude.

*Taylor is a rising 3L at University of Houston School of Law and a Gray Reed summer associate.

PS: The title wasn’t clickbait. We have no better idea than you how the new court will affect oil and gas suits. What do you think?

The Austin Court of Appeals has ruled in Texas Railroad Commission et al v. Opiela, the dispute over a permit for a horizontal well under a Production Sharing Agreement.  We reported on the result in the trial court. Here are some highlights of the appeal.

Where did the 65% rule come from?

The court traced the Commission’s authority to a 2008 minute entry in which two of the three commissioners approved a permit while directing staff that wells that are permitted based on PSA’s should be approved when the operator certifies that at least 65% of the working and mineral interest owners in each component tract have signed a PSA.  That announcement did not say that multiple different PSA’s could be signed or that other documents, such as a lease pooling clause, could be the equivalent of a PSA for purposes of the 65% threshold.

Pooling and PSA’s

The court examined the relationship between pooling and PSA’s and determined that Magnolia’s assertion of right to drill under a PSA did not infringe on the anti-pooling clause in the Opiela lease. The Commission ignored the anti-pooling clause as irrelevant to the well permit.  The court concluded that a permit for horizontal drilling under a PSA is not pooling under Texas law and thus the Opiela lease’s anti-pooling clause was not implicated.

RRC authority over title questions

The court affirmed that Commission does not have the authority to adjudicate questions of title or rights of possession when it grants a drilling permit. The Commission’s conclusion that Magnolia made the requisite showing of a good-faith claim of right to operate the well rested on satisfaction of the 65% threshold that is not found in the Texas Administrative Code.

Is a PSA required?

The evidence showed that only 15.625% of the interest owners signed a PSA. The other written agreements Magnolia relied on included consents to pool and pooling ratifications. Substantial evidence did not support a finding that 65% of the interest owners signed a PSA.

Even while granting deference to the Commission’s expertise in regulating the industry, the court was not persuaded that a consent to pool can substitute for a PSA absent a good-faith showing that consents and the PSA’s call for the same sharing of production for a well across tracts that are not pooled. Magnolia did not so certify and the Commission did not make such a finding.

The definition of a PSA from the Commission’s 2019 Form P-16 allows proof of a PSA to include certification that 65% of interest owners have signed an agreement as to how proceeds will be divided. But Magnolia’s permit was based on applications predating that definition. Neither the form nor the instructions used to complete the application contained the expanded definition of the agreements that would make a 65% threshold.

The rulings

The court:

  • reversed the trial court judgment that the Commission erred in concluding that it had no authority to review whether an applicant seeking a permit has authority under a lease or other relevant title documents
  • reversed the trial court judgment that the Commission erred in failing to consider the pooling clause of the lease in deciding that Magnolia had a good-faith claim to operate the well.
  • affirmed the trial court judgment that the Commission erred in finding that Magnolia showed a good-faith claim of right to drill the well.
  • remanded the case to the Commission for further proceedings.

The dissent

Justice Kelly would conclude that an operator’s certification that the requisite owners from each tract have agreed on how production would be shared, when supported by signed agreements, is sufficient to show a good-faith claim to operate. Because royalty calculations are specific as to each lease, the exact share or method for dividing proceeds under any particular agreement is immaterial. He would resolve whether the 65% threshold standard complies with the APA.

Your musical interlude

LSU 3B Tommy “Tanks” salutes energyandthelaw at the Men’s College World Series.
Co-author Cahill Maffei*

Can a non-operating working interest in a Texas oil and gas lease be adversely possessed? The Amarillo Court of Appeals said yes in PBEX II, LLC v. Dorchester Minerals, L.P.

In 1989, Torch Oil & Gas succeeded to a working interest in two producing gas wells. The next year, Torch conveyed that interest to Dorchester Minerals L.P.’s predecessor. Not long after, Torch signed a division order acknowledging that its interest was 0 percent.

At all times between 1990 to 2016, Dorchester and its predecessors performed all the functions of a non-operating working interest owner: paying their share of the costs of production, receiving revenues from the sale of the working interest’s share of the gas, paying royalties to the lessors under the lease, and making elections required under the joint operating agreement.

In 2016, Torch assigned its interest to PBEX. Dorchester informed Torch that it no longer had an interest in the lease. Torch filed suit. Dorchester counterclaimed and brought in PBEX. The trial court granted summary judgment in favor of Dorchester. Torch and PBEX appealed.

On appeal, Torch and PBEX asserted that Dorchester could not establish adverse possession as a matter of law. The court found that Dorchester adversely possessed the working interest by exercising the rights of the working interest owner for over 26 years, exceeding the 25-year statute of limitations.

Torch and PBEX asserted four arguments, each of which the court found unpersuasive.

First:  As a non-operator, Dorchester could not have a possessory interest sufficient for adverse possession. The court disagreed. There was no meaningful distinction between operating and non-operating working interests. On that basis, the court held that oil and gas leasehold interests are possessory interests because a working interest owner is granted the right to possess all the oil, gas, and other minerals underlying the lease.

Second: Dorchester could not meet the actual, visible appropriation requirement for adverse possession because only the operator engages in operations. But Dorchester need not be the one to literally remove the gas from the ground to establish adverse possession. By openly usurping all the benefits, liabilities, and obligations of the working interests, Dorchester held itself out to the world as the owner sufficient to establish adverse possession.

Third: Dorchester could not rely on the operator’s operations for adverse possession. The court responded that an operator can adversely possess the working interest on behalf of the owners. The court analogized this situation to a landlord-tenant relationship, in which the working interest owner is the landlord and the operator is the tenant, noting that in Texas it is well-settled that adverse possession can occur through a tenant and reasoned that the same applied here.

Fourth: Dorchester’s predecessors were “non-consent”, interrupting their adverse possession. A working interest owner goes non-consent when it elects not to participate in the costs of drilling a well. The election requires the working interest owner to relinquish its share of production. The court dismissed this argument because, in reality, Dorchester’s predecessors continued to deplete the wells, and the plaintiffs presented no evidence that a non-consent penalty was ever applied.

The court affirmed summary judgment in favor of Dorchester’s adverse possession of the working interest.

Your musical interlude

… a two-fer. Phil Lesh: The base that doesn’t lay behind the beat.

*Cahill is a rising 3-L at Texas A&M University School of Law and a Gray Reed summer associate.

Co-author Kamal Omar*

Texas, famously, does not tax individuals’ income, but it does impose franchise taxes on “taxable entities”, such as limited liability companies. Federal tax law treats them as partnerships unless they elect to be treated otherwise. In Hibernia Energy LLC v. Hegar, a Texas court addressed how Hibernia, a non-taxable entity under federal law, is taxable under Texas law. 

The franchise tax

Hibernia sold leasehold interests. Its franchise-tax reports to the Comptroller in 2013 and 2015 reported gains that were almost entirely attributable to the sale of the interests. The gains were included in the determination of its total revenue and corresponding liability for franchise taxes. Hibernia paid the taxes.

Hibernia later sought a refund for the two tax years and attached two key documents to its request:  Amended franchise tax reports removing the gains from the sale of the interests previously reported, and a “Statement of Grounds” explaining that it had “overstated” its total revenue by erroneously including the gains from the sale when such an inclusion is not required under law.

The Comptroller disagreed, disallowed the proposed adjustments, and denied the requested refund.  

The federal tax

Partnerships are not subject to federal income taxes but still must file informational returns on Form 1065, which allocates to partners their proportional share of gains, losses, and other information necessary to calculate and report individual income-tax liability. An entity’s Texas franchise tax liability is based on amounts “reportable as income” on federal tax return line 11, Schedule K, where the partnership must report “any other item of income” not reported elsewhere on the return. Hibernia left the line empty.

The Texas court’s conclusion

On appeal from the Comptroller’s decision to deny Hibernia’s refund, the court of appeals addressed whether Hibernia was required by federal tax law to include its net gains from the sale of the leaseholds on line 11, Schedule K.

Hibernia advanced two arguments for why the gains were not “reportable as income” on line 11. First, Form 1065’s instructions expressly exclude gains on the disposition of an interest in oil or gas properties because the applicable instruction states merely “disposition of an interest” rather than “gains (loss) from the disposition of an interest.” The instructions direct the partnership to “enter any other item of income or loss not included on lines 1 through 10” and further require the partnership to “identify the type of income” in the space next to line 11 and describe the type of income using one of several codes. The instructions twice mandate the partnership to list on Schedule K “any other” item or type of income not otherwise disclosed. The Court concluded that Hibernia’s proposed construction of the instructions runs counter to the Internal Revenue Code’s requirement that a partnership must report all items of gross income. The court further concluded that the instructions must be construed in a way that avoids hyper-technical readings.

Second, Hibernia claimed that it could not determine its “gain” because the adjustments depended on elections unknown to the partnership. In rejecting the argument, the court considered evidence that Hibernia did in-fact calculate its gains on its original franchise-tax reports. Furthermore, because depletion adjustments were unavailable to Hibernia, its gains on the leasehold sales were simply the amount realized on the sale less its cost to purchase them.

Hibernia was required to report its gain from the sale of the leasehold interests on line 11 and include those gains in its total revenue for Texas franchise-tax purposes. Hibernia was not entitled to a refund.

Your musical interlude

*Kamal is a rising 3L at SMU Law School and a Gray Reed summer associate.