Co-Author Gunner West

In B.H.C.H. Mineral, Ltd. v. Needmore Minerals, LLP, the San Antonio Court of appeals held that a reservation of “1/32 of all oil, gas and other minerals” coupled with attribute-stripping language and a minimum royalty requirement created a non-executive mineral interest with a floating royalty. The court also declined to apply the presumed-grant doctrine.

The deed and the dispute

Ninety years ago Esperanza Livestock & Land Company conveyed a 23,513-acre Webb County ranch to John Sinclair, reserving an undivided 1/32 of the minerals, giving the grantee exclusive leasing authority, and requiring any lease to retain at least a 1/8 royalty. Sinclair’s interest ran through John Nance Garner (Speaker of the U.S. House and, under FDR, the nation’s thirty-second vice president) and his successors, who leased in 1967 at a 1/6 royalty. (This well-traveled interest was even owned for a while by golden-throated, Poteet, Texas-born George Strait.)

The royalty floats

The Esperanza successors claimed a fixed 1/32 NPRI. The court considered the deed as a whole, harmonizing the reservation, the stripping lanuage, and the minimum royalty requirement. The words “in and under said land” are classic mineral-estate language, and stripping executive, bonus, and delay-rental rights left a non-executive mineral interest. It was not a royalty interest. According to the Court, the royalty floats because a fixed 1/32 of production would render the deed’s “at least 1/8” clause meaningless. The result left the Esperanza successors with 1/32 of the 1/6 lease royalty, 1/192 of production – quite modest, to say the least.

Presumed-grant does not apply

The Court deemed presumed-grant to be a cousin of adverse possession. In Clifton v. Johnson, the Supreme Court recently allowed that the doctrine might extend to a royalty but declined to decide whether it could do so on the facts of that case. This Court came down against extension, stating that the doctrine has never reached a royalty interest. The Court reasoned that a mineral estate, being possessory, can be adversely possessed, while a royalty is incorporeal and confers no right to possess.

The parties’ predecessors and their operators had a long history of treating the interest as fixed. But the Court believed that an underpayment may reflect a lessee’s breach or mistake, but cashing royalty checks is not the open, adverse claim the doctrine requires. The Court cited Sun Oil Company (Del) v. Madeley, where lessees corrected more than forty years of overpayments and the Supreme Court refused to let the royalty owners lock in the inflated rate. It did not help that the Court believed that the Esperanza successors presented no evidence of an open claim of their own.

Equitable defenses were unavailable

The equitable defenses failed too. Estoppel by deed binds only parties and their privies, and the Esperanza successors were strangers to Garner deeds. Quasi-estoppel, waiver, and ratification cannot manufacture rights the deed withheld, and division orders distribute proceeds, not title.

The dissent

Justice McCray would have applied presumed-grant to establish a 1/32 royalty; the doctrine reached incorporeal interests long before it reached land; Clifton and Boren Descendants v. Fasken signal it can fix a royalty; and five decades of consistent treatment, including a Garner successor’s testimony that his side always regarded the interest as a fixed 1/32, at least raised a fact issue for trial.

Your musical interlude … his exes and his minerals.

Co-author David Pruitt

Our Cornucopia post was a reminder that “subject to” is a phrase that punches well above its weight. In Brown et al v. Endeavor Energy Resources, L.P., those same two words undid a $2.3 million summary judgment and returned the case to the trial court for a do-over.

 The facts

Randy Brown earned overriding royalty interests while working as a geologist in the Permian Basin. In 1998 he assigned his overrides to ARCO, Endeavor’s predecessor. The assignment was “made subject to the terms and conditions” of an unrecorded letter agreement. After Randy died in 2018 and his sons inherited his estate, Endeavor sent division orders naming them as owners and over time paid $2.3 million in royalties. Each DO required the payee to refund amounts attributable to an interest he is paid on but does not own. After finding the ARCO assignment, Endeavor concluded it owned the overrides and demanded repayment. The Browns refused. Endeavor sued for breach of contract. The trial court ruled in Endeavor’s favor. The Browns appealed.

The question

Did Endeavor conclusively prove the Browns did not own the overrides, given that the assignment it relied on was expressly subject to a letter agreement Endeavor never produced. (Spoiler Alert: No.)

The “writing” problem (the Statute of Frauds)

An override is an interest in land, and it has long been Texas law that such interests live and die by the writing that creates them. The law’s insistence on a complete writing is what made the missing letter agreement so consequential.

Two threads illustrate the point. First, Endeavor argued that the deceased Randy could not have reserved any interest because the letter agreement predated the assignment, and a reservation must be made at the time of the conveyance. The court was unpersuaded because the assignment was expressly subordinate to the writing.

Second, the contents of a lost writing cannot simply be assumed. The proponent must first prove the document was lost and account for its absence under Texas Rule of Evidence 1004 before offering secondary evidence of its terms. Endeavor did neither, so the writing that defined the transaction remained a mystery. And a party cannot carry that burden with its own interrogatory answer (that it could not find the letter agreement).

 Evidentiary issues

As is common in these title cases the trial court struck portions of an affidavit of an Endeavor landman on the basis that they constituted factual and legal conclusions.

The ruling

“Subject to” means “subordinate to, subservient to or limited by”. The assignment and the unproduced letter agreement had to be construed together, and Endeavor—bound by every recital and reference in its chain of title—took the assignment with a duty to inquire into the document it incorporated. Endeavor’s evidence painted an incomplete picture of title, supporting “multiple, equally probable inferences” about whether title ever passed.

The circumstantial evidence deepened the doubt: Endeavor kept paying the Browns, the tax rolls still showed Randy as owner, and ARCO never claimed title. There were genuine issues of material fact. The Court reversed and remanded.

 “Subject to” is not boilerplate

Those words fold the referenced writing into the purported owner’s title and charges the owner with notice and a duty to track the writing down. When the writing is missing the proponent must establish its loss under Rule 1004 and prove its whole case. An incomplete chain of title, propped up by the proponent’s own self-serving discovery responses, will not carry the day.

Your (little known) musical interludes:

Mon Rovia

Ladyva

Houndmouth

James Hunter Six

Co-author David Priutt

So says the Supreme Court of Texas in Braxton Minerals III, LLC v. Bauer. For many years there was doubt and confusion over whether a Texas court could assert its jurisdiction in a suit over mineral rights located in another state. In Braxton the Court answered with an emphatic yes, reversing the Fort Worth Court of Appeals and disapproving a line of intermediate appellate court decisions that had muddied the waters.

The facts

Robert Bauer is a Texan who buys and sells mineral rights across the country. In 2015, Bauer and an associate formed Braxton Minerals II (BM2) and partnered with EnerQuest Oil & Gas to create an Oklahoma company, Braxton Minerals III (BM3), to acquire mineral rights in Appalachia. EnerQuest put up $10 million for seventy-five percent of BM3. Through a series of draw requests, BM3 purchased mineral rights from BM2. The problem: 19 mineral deeds listed BM2, not BM3, as grantee – resulting in royalty payments to the wrong entity.

BM3 asked Bauer to fix the deeds. He refused. BM3 sued in Tarrant County seeking reformation, specific performance, declaratory relief and injunctive relief – all those claim you make when you want the property. The district court granted summary judgment for BM3 and ordered Bauer and BM2 to reform the deeds and convey the mineral rights. The court of appeals reversed. Because the minerals were in West Virginia, Texas courts lacked jurisdiction. The court applied the “gist” rule — if the crux of the suit involves adjudication of title to foreign real property, Texas courts cannot hear it. The analysis was not simple.

The new rule

The Supreme Court tossed the “gist” rule entirely, disapproving of Kelly Oil Co. v. Svetlik and its progeny. The new framework highlights the distinction between suits in personam (against the person) and in rem (against the thing). A Texas court cannot exercise in rem jurisdiction over land in another state, but it absolutely can issue an in-personam judgment compelling a party within its jurisdiction to honor contractual obligations regarding that out-of-state land.

The Court relied on precedent stretching back 130 years — Texas & Pacific Railway Co. v. Gay (1894), Holt v. Guerguin (1914), and McElreath v. McElreath (1961) — all standing for the same proposition: If a person has a contractual obligation to convey land, a court having jurisdiction over his person may compel the conveyance, no matter where the land sits. The decisive question is whether the property or the person is the object of the judgment.

The Court concluded that every category of relief BM3 received — specific performance, deed reformation, declaratory judgment, and injunction — operated in personam and was within the district court’s power. The judgment was reversed and remanded.

Practical implications

No longer will an aggrieved party to a contract involving out-of-state lands have to delve into the intricacies of the “gist rule”, hoping to get it right and knowing, as in Braxton before the clarification, that it would have to start all over in another jurisdiction if it guesses wrong.

Your musical interludes – New Orleans, son of New Orleans, New Orleans/cousin of son of New Orleans (all in one, Ziggy) and to round out the discussion, the beginning of New Orleans.

Co-author Gunner West

… at least according to the El Paso Court of Appeals. In Craddick v. Cimarex Energy Co., that court affirmed a take-nothing judgment against owners of overriding royalty interests in an oil and gas lease that were washed out when the lessee surrendered the lease to the mineral owner. The court declined to recognize a common-law claim for bad-faith washout and construed the lease surrender clause’s “good faith” language as imposing only a duty to deliver a recordable release.

Facts

When BPX acquired an old lease covering 1,440 acres in Reeves County, there was one well plugged, one shut in, and one producing intermittently. BPX personnel doubted it was still producing in paying quantities. Cimarex owned the mineral estate. Craddick and Staley held overriding royalty interests totaling 11.5625%: Craddick’s reservation included renewal-or-extension (anti-washout) language; Staley’s had none.

Cimarex proposed an acreage trade to BPX that required an 87.5% net revenue interest in the lease. BPX’s NRI was less, the difference mostly being the two overrides. In an email to Cimarex, BPX suggested that terminating the lease would eliminate the overrides and BPX’s working interest, leaving Cimarex with a 99%+ NRI. Cimarex never responded but later declared the lease terminated for lack of production. BPX delivered a release rather than an assignment burdened by the overrides. The acreage reverted, free of the overrides. Cimarex then drilled new wells as owner-operator.

No duty of good faith and fair dealing

The court denied Craddick and Staley’s argument that the fiduciary-type duty of utmost good faith and fair dealing an executive-right holder owes to NPRI owners extends to a lessee’s dealings with an override carved from its working interest. The “executive” in the NPRI cases has always been the mineral owner, not a lessee. And the two interests differ structurally—an NPRI is carved from the mineral estate and runs with the land; an override is carved from the working interest and ordinarily terminates with the lease.

The Supreme Court has declined to find such a duty by a lessee to an override owner, and once expressly reserved the question in a co-lessee dispute. Under recent precedent, any such duty requires a relationship beyond an arm’s-length transaction and the summary-judgment record showed none. Numerous intermediate assignments separated the original override from BPX, neither plaintiff ever dealt with defendants, and both plaintiffs were sophisticated industry players. The court declined to be the first to recognize the claim, leaving the possibility open on a different record (and inviting the Supreme Court to review?)

The contract claim

There was a claim that Cimarex breached the surrender provision requiring the lessee desiring to cancel the lease to “in good faith” promptly prepare and deliver a release clearing any cloud on the lessor’s title. The Court denied that the phrase barred bad-faith surrender; it modified only the obligation to prepare and deliver the release. It was a release-of-record clause governing how a surrender is documented, not whether to surrender.

What about the statute?

In 2023 while this suit was pending, Tom Craddick, plaintiff and Texas House of Representatives member, authored Chapter 31 of the Texas Property Code, creating a cause of action for bad-faith washouts. But Chapter 31 applies only to transactions after September 1, 2023; BPX recorded its release in 2017. Craddick’s statute arrived too late to help him … this time.

Apart from the statute, there is a drafting lesson: Many, possibly most, renewal-or-extension provisions address a lessee renewing or taking a new lease but say nothing about the cancellation and surrender of the lease. The careful negotiator and drafter should consider this possibility.

Your musical interlude bye and bye again.

Co-author Caleb White

In Boerschig v. Rio Grande Electrical Cooperative, Inc. the Supreme Court of Texas, in a four-justice opinion, a concurrence and four dissents, determined that an electric cooperative holds an easement by estoppel for a distribution line but, disregarding a jury finding, also found as a matter of law that a significant upgrade of that line exceeded the easement’s scope. How is one to make sense of such a mixed set of signals?

The history

In 1947 Rio Grande Electrical Cooperative and the then-owner of the 6,397-acre U-Bar Ranch in Kinney County executed a “Right of Way Easement” purporting to grant the right to construct and maintain an electric distribution line. The document was never recorded. Rio Grande constructed a distribution line crossing 1.6 miles+/- of the Ranch. The line consisted of 17 to 20 wooden poles, each rising 30 feet and carrying four wires per crossarm.  

In 2002 Boerschig purchased the Ranch and observed the existing power line, which appeared on a survey prepared in connection with the transaction.

In 2012 Rio Grande notified Boerschig of plans to upgrade the line. When completed, the upgraded line was much larger than the original: 60 poles rising 37 feet and carrying seven wires on two crossarms.

Boerschig sued Rio Grande for trespass. Rio Grande counterclaimed for a declaration that it holds a valid express easement, a prescriptive easement, or an easement by estoppel.

At trial the jury found Rio Grande does not have an enforceable written easement or a prescriptive easement, but did find an easement by estoppel. The jury answered “no” when asked whether the upgrade exceeded the scope of the easement. Thus, it did not answer the question whether there was a trespass. Trial court rendered judgment for Rio Grande and the San Antonio Court of Appeals affirmed.

The majority – easement by estoppel

There was legally sufficient evidence supporting the jury’s finding on each element required to establish an easement and thus Rio Grande possessed an easement by estoppel.

  • The easement document was competent evidence of a representation, even though it failed as a valid express easement.
  • Rio Grande believed it had a valid easement and
  • Rio Grande relied on the representation by constructing the line and maintaining it for over 60 years.

But … scope of the easement

The evidence established that the scope of Rio Grande’s easement by estoppel was not broad enough to authorize the upgrade. That, paired with undisputed evidence that the upgrades were built without Boerschig’s consent, led the Court to determine as a matter of law that Boerschig was entitled to a judgment for trespass.

The Court articulated a framework for determining the scope of an easement by estoppel, which differs significantly from the analysis for express easements. The Court explained that because easements by estoppel lack recorded writings and undermine the statute of frauds and conveyance requirements, they must be “strictly limited” and should be treated as “a last resort.”

The scope of an easement by estoppel is limited to the representations made by the landowner, narrowed by the holder’s actual uses of the easement in reasonable reliance on the representations. The scope is further constricted, when the land has been sold, by the subsequent purchaser’s notice of those representations or uses at the time of purchase.

The Court instructed lower courts and juries that they may not speculate about the unexpressed purpose behind an easement by estoppel or consider whether an expanded use would serve that purpose, nor should they assess whether a change is foreseeable or materially more burdensome to the landowner. The right to own property is “fundamental, natural, inherent, [and] inalienable,” and courts are not free to give away more of a landowner’s property rights based on a perceived societal benefit.

Applying this framework, the Court found the evidence conclusive. Rio Grande’s only actual investment in reliance on the written document was the original line. Boerschig’s only notice of the easement was the line as it existed when he purchased the Ranch; he had neither actual nor inquiry notice of the unrecorded document. Tripling the number of poles and nearly doubling the number of wires was not an activity reasonably necessary to Rio Grande’s continued enjoyment of the existing line—the upgrade’s purpose was to serve new customers, not to maintain service to existing ones.

The case was remanded for further action by the trial court.

The concurrence

Justice Hawkins wrote separately regarding his understanding of the ruling. He emphasized three points:

  • Easements by estoppel can include closely related ancillary uses such as maintenance, but such uses must be de minimis and reasonably necessary to continue the existing use—not merely harmless to the landowner.
  • Many disputes over whether the holder of an easement by estoppel has exceeded its rights will present questions for a jury to resolve.
  • This case required resolution as a matter of law because Rio Grande materially expanded its intrusion beyond the original use, and the improvements went beyond any notice attributable to Boerschig at the time of his purchase.

The dissent

The four dissenters argued:

The jury properly concluded Rio Grande did not exceed the scope of its easement, and that legally sufficient evidence supported that verdict. The majority’s narrow definition of reliance, reducing Rio Grande’s acknowledged right to operate the power line to existing poles and wires, improperly took the question out of the jury’s hands.

The scope of an easement by estoppel includes closely related ancillary activities necessary to maintain and continue the use, so long as those activities do not materially increase the burden on the landowner.

Rio Grande presented evidence that reconstruction was necessary to continue serving existing customers and to improve reliability, and that the jury credited that evidence.

The majority hands a windfall to purchasers of land with notice of a power line route and undermines the work of rural electric cooperatives.

Your musical interlude

Co-author Kealey Poole*

We at Energy and the Law solemnly swear and affirm that we will no longer report on the Van Dyke Presumption just as soon as litigants – win, lose or remand – exhaust their efforts to confirm, refute, distinguish or overcome it. Until then …

By a 1956 deed the Hoffmans conveyed 1,070 acres in McMullen County to Peeler. The deed “expressly reserved . . . an undivided three thirty-second’s (3/32’s) interest (same being three-fourths (3/4’s) of the usual one-eighth (1/8th) royalty)” in oil, gas, and other minerals. For decades, the holders of the reserved NPRI were paid royalties based on a fixed 3/32 (3/4 X 1/8 = 3/32). Simple multiplication; case closed?

The San Antonio Court of Appeals issued an opinion in this dispute that the reservation was of a floating 3/4 interest. The Supreme Court of Texas then decided Van Dyke v. Navigator Group, explaining that courts should not simply perform multiplication when confronting a double fraction reservation that contains “1/8”. Van Dyke requires courts to begin with a rebuttable presumption that the term “1/8” in a double fraction instrument is shorthand for the lessor’s entire royalty (whatever that royalty might be under the lease in effect) and not a fixed arithmetical value.  The court rejected two widespread misconceptions Texas landowners and their lawyers had been living with for generations: a lessor who received a 1/8 royalty in an oil and gas lease retained only a 1/8 interest in the minerals, and the landowner’s royalty would forever remain 1/8. Deed drafters had been using “1/8” as a placeholder for “whatever the royalty is”, not as a number to multiply.

The Supreme Court vacated the Court of Appeals’ earlier decision and directed it to apply the new Van Dyke framework. In Hoffman v. Thomson the court has reached the same conclusion as before. Applying Van Dyke, the court dispatched several arguments raised by the Peelers. The Court reasoned:

  • The presumption applies to royalty interests, not just mineral estates;
  • The presumption applies to more recent deeds (this one is from the 1950s), not just “archaic” instruments (from the 1920s, as in Van Dyke);
  • Repeated use of 3/32 elsewhere in this deed did not allow the court to overlook the double fraction that that triggered the presumption in the first place;
  • A pre-existing lease with a 1/10 royalty on “other minerals” did not rebut the presumption. Rebuttal must arise from within the four corners of the deed itself and not from extrinsic evidence.
  • A provision barring grantors from participating in future bonus payments refers to cash consideration for lease execution, not to royalty increases.

The court found none of the Peelers’ arguments were “sufficiently clear” to permit a conclusion that the double fraction was meant as simple math. The Court ruled for the Hoffmans: The 1956 instrument reserved a 3/4 floating NPRI. Once again, an appellate court has determined that after the Van Dyke presumption attaches an unhappy litigant will have a difficult time rebutting it.

Andy Rooney talks about D Day.

Bob Dylan. Happy Bob, Sad Bob

*Kealey, a rising 3L at Texas A&M School of Law, is a Gray Reed summer associate.

In WMH  Farms v. Apache Corporation the Third Circuit Court of Appeal reversed summary judgment in favor of plaintiff/landowner WMH against lessee JP Oil and dismissed JP’s third-party demand against Walter Oil and Gas.

Then the Louisiana Supreme Court reversed the court of appeal, reinstated the summary judgment, and remanded. We will report on the court of appeal opinion in anticipation that the case will end up there again, although now it looks like JP will be off to Department of Conservation and Energy to develop and implement a “feasible plan” to restore the property.

The facts

Landowner WMH Farms sued JP Oil and six other defendants seeking remediation of its property and monetary relief for environmental damage caused by exploration and production of oil and gas, as provided by La. R.S. 30:29 (“Act 312”). All defendants settled except JP who had filed a third-party demand against Walter Oil and Gas Corporation (Walter).

The court of appeal

JP appealed two summary judgments in favor of WMH and Walter: First that JP caused and is legally responsible for environmental damage to the property; second, dismissal of JP’s third-party claims against Walter, JP’s predecessor in title.

The Court concluded JP had the right to appeal (more on that later) and that WMH’s critical summary judgment evidence was inadmissible based on an affiant’s lack of personal knowledge and failure to authenticate exhibits.  

The trial court ruled that there was no genuine issue of material fact as to the existence of environmental damage as defined by Act 312 and that JP was otherwise “legally responsible for the environmental damage“. The ruling was based in part on a report by WHM’s expert ICON, but attached to the affidavit of a landman with no environmental expertise. Even if the report were admissible, WMH did not present evidence showing that the report established the property was contaminated under the requirements of Act 312.

The trial court ruled that WMH established that its property sustained environmental damage when some of the test results exceeded the ranges set forth in applicable regulatory standards. But that evidence did not establish that ICON’s test results satisfied Act 312’s requirements. Act 312 defines “contamination” as “introduction or presence of substances or contaminants into a usable groundwater aquifer, an underground source of drinking water, or soil in such quantities as to render them unsuitable for their reasonable intended purposes”.  

JPs expert also pointed out that ICON’s testing was inadequate in some respects and inconclusive in others and WMH did not rebut those opinions. This created a genuine question of material fact precluding summary judgment.

Admission of liability?

The Court rejected WMH’s contention that JP admitted liability by obeying instructions from the Louisiana Department of Conservation and Energy (by another name at the time) received with written notice of DCE’s efforts to assess soil and groundwater conditions on the property. Compliance with a DCE order was not an admission of liability.

Was the pit an ”Asset”?

Next was the question of whether a pit on the property was an asset that Walter assigned to JP.  Walter’s assignment was without warranty or covenant of any sort and JP agreed to assume all liabilities relating to ownership and operation of the transferred “assets”. Walter alleged waiver.

JP asserted that waiver did not apply because the pit had been remediated and did not exist at the time of the transfer, because Walter did not designate the pit as an assigned asset, and because the pit was not an appurtenance of the well.

The Court in general terms deemed the pit to be a portion of the property that was assigned to JP and thus an asset acquired by JP. 

Detrimental Reliance

The Court denied JP’s claim that it executed the assignment by which it acquired the lease on the property in reliance on a certificate by a third-party laboratory found in Walter’s files stating that the pit on the property had been closed and and complied with Statewide Order 29 B. A claim for detrimental reliance based on a contractual provision applies only to representations made by the parties to the contract and not representations by third parties.

Contribution

The court rejected JP’s claim for contribution from Walter. The parties were solidarily liable for obligations owed to WMH and to the State, but JP’s right to contribution was extinguished by Walters’ settlement with the landowner.

The Supreme Court

The Court granted WMH’s writ of certiorari and determined that the court of appeals did not have jurisdiction to consider the trial court’s ruling because the ruling was not a final judgment. Summary judgment reinstated, case remanded. Chief Justice Weimer dissented.

The result?

Here is an opinion from a lawyer practicing among Texas oil and gas operators. After several decades of legacy litigation, it appears that the Louisiana Supreme Court, the Legislature, and the plaintiffs’ bar do not appreciate the extent to which these cases have discouraged out-of-state companies from operating in Louisiana. How many opportunities to invest in a legacy property have been rejected because of the specter of legacy litigation? Who needs the headache and exposure when one can spend your exploration dollars in friendlier jurisdictions? Even if this litigation has largely run its course, as has been said, the reputation will linger as hard and heavy as a bad whiskey hangover.

Act 312 has been amended, effective for cases filed after September 1, 2027. The amendment is designed to clarify the law, lower costs, and simplify procedures. Maybe it will.

Your musical interlude … something to bring some joy.

Another dispute is resolved according to the provisions in a Master Service Agreement. Have you reviewed yours lately?

Jones was employed by Murphrey Oil Company. He died while working on a well operated by Texas Pacific Investment Company on a location in Winn Parish, Louisiana. Murphrey and TPIC had a MSA by which Murphrey was to perform well services and equipment repairs on TPIC’s lease.

In White v. Texas Pacific Investment Company et al  Ms. White sued TPIC and its employee Barnes in Louisiana state court on behalf of her minor child for the wrongful death of Jones. White alleged that Barnes was employed by TPIC to manage the field where the incident occurred, engaged in a host of enumerated tortious acts and omissions, and as a result was personally liable for the death of Jones.

Which court should have the case?

Barnes and White are citizens of Louisiana; TPIC is a citizen of Texas. TPIC removed the case to federal court. After White finally served Barnes, she prevailed in the defendants’ assertion that Barnes was fraudulently joined. That would have defeated federal diversity jurisdiction, which requires that the parties be citizens of different states. Query: Was Barnes sued on a longshot solely to defeat diversity? Who’s to judge. Let’s just say that such a joinder is not unusual.

To defeat federal jurisdiction the removing party must show inability of the plaintiff to establish a cause of action against the non-diverse defendant. That led the court to consider whether Barnes could be liable for Jones’ death. The answer was “no”.

According to the Louisiana Workers’ Compensation Act an employee may be personally liable to third parties only when all four of these elements are met:

  • The employer must owe a duty of care to the plaintiff, the breach of which caused injury,
  • The employer must have delegated the duty to the employee at issue,
  • The employee must have breached the duty through his own personal fault,
  • The employee’s breach must have been more than a simple breach of general administrative responsibility.

White’s case failed the second requirement. She did not identify any specific duties of care owed to Jones that TPIC delegated to Barnes, or anyone else for that matter. White’s allegations against Barnes were not factually specific enough. Remand denied.

The Master Service Agreement

That took the Court to the TPIC/Murphrey MSA and specifically, whether Barnes was TPIC’s statutory employee. An answer in the positive would limit White’s recovery to workers compensation benefits.

Under the LWCA an employee injured in an accident while in the course and scope of his employment is generally limited in a suit against his employer to workers comp benefits, not for a tort. TPIC protected itself and Barnes in the MSA by the parties specifically recognizing that the work provided by Murphrey and its employees was an integral part of and was essential to to the ability of TPIC to generate TPIC’s goods and sedrvices for the work. The parties further stipulated that TPIC was the principal or statutory employer of Murphrey. The presumption is rebuttable, which White failed to do. Under the mandated liberal interpretation of the LWCA, accepting the position would require the Court to “… throw the will of the legislature aside and be restrictive in its analysis of … ” the statute. The court refused to do that.

Summary judgment granted for TPIC.

Your musical interlude … possibly the worst song in the history of recorded music … or maybe it’s this one!

Co-author Kamal Omar

In Zarvona Energy v. Black Stone Minerals Company, a Texas Court of Appeals reiterated that the cessation-of-production clause in an oil and gas lease cannot be read in absolute terms as a lessor might want it to be. The Court also grappled with ambiguities among four different provisions in the lease. 

The Facts

Zarvona operated wells on several pooled units that included two oil and gas leases from lessors Black Stone Minerals and Sugarberry covering over 7,000 acres in Tyler and Polk Counties. The Court focused on the Black Stone lease.

The trouble began when Blackstone notified Zarvona that 1,527 acres under the Blackstone lease had terminated because wells had failed to produce in paying quantities for over 90 days. Zarvona refused to release the acreage and Blackstone filed a partial release in the county records. Sugarberry followed. Zarvona sued.   

Operative lease provisions

Several clauses were in play (paraphrased):

  • The habendum clause ¶1: The lease would be maintained after the primary term so long as oil or gas continued to be produced in paying quantities.
  • Cessation of production ¶11: A 90-day cessation of production in paying quantities would terminate the lease.
  • Continuous development ¶10: The lease would remain in force after the primary term as to undeveloped acreage as long as lessee did not permit more than 90 days to pass between the date operations ceased on one well and commencement of the next well.
  • Retained acreage ¶3: Following the 90-day continuous development provision, the lease would terminate except as to spacing units around each well or portions of lands included in pooled units.

Blackstone’s argument was straightforward: The units lost money in April, May and June of 2020—91 days—so the lease died. Zarvona countered that the paying quantities language did not replace the longstanding Clifton v. Koontz rule.

The Court sides with lessee

Clifton established that the terms “produced” and “produced in paying quantities” mean substantially the same thing. The test: Texas courts do not mechanically add up 90 days of revenue and costs in evaluating whether there has been cessation of production in paying quantities. Instead, they ask whether a reasonably prudent operator—considering depletion, oil prices, profitability of nearby wells, and other factors—would keep operating the well. An unprofitable quarter on its own does not meet the test. A bad quarter does not automatically kill the lease.

Conflicting provisions

The cessation-of-production clause began with “Unless maintained by other provisions … .” The habendum clause began with “Subject to the other provisions of this Lease … ,” Each section was subordinate to the other. That mutual subordination created an ambiguity that the Court refused to resolve in favor of forfeiture. A Texas court will not hold lease language to impose a special limitation on the lease grant unless the language is so clear, precise and unequivocal that it cannot reasonably give it no other meaning. That was not the case here.

Retained acreage

The retained acreage clause— releasing undrilled acreage back to the lessor—operated as a onetime snapshot, not a rolling mechanism applying on a unit-by-unit basis. The clause began “Following the 90-day continuous development provision …” the lease would terminate as to non-producing lands. The clause determined when it applied, but not how often. Because the clause could reasonably be read either way it was ambiguous and again, Texas courts do not readily construe ambiguities so as to forfeit leasehold interests.  Lease termination was a one-time event.

The holding

The Court rendered judgment declaring, “the retained acreage clause is a snapshot provision and does not provide for rolling lease terminations during the secondary term on a unit-by-unit basis, and … [the cessation-of-production clause] does not apply on a unit-by-unit basis and does not define the measuring period for assessing production in paying quantities when production has not ceased.” It’s back to the trial court to address unresolved questions.

Remember, this result is based on the wording of these particular leases. As we are reminded by financial advisors, personal injury lawyers, and championship-winning coaches, past performance does not guarantee future results. (But give me an extension and a big raise, anyway!)

Your Memorial Day musical interlude.

Co-author Caleb White

After reading Devon Energy Production Company, L.P. v. Oliver if you’ recall a similar post-production cost dispute, it was last week. And the result was the same. Royalties under this lease are to be calculated at the wellhead (where there are no PPC’s) and not on a downstream market price (after PPC’s are incurred).  

The Facts

The Olivers are royalty owners in two leases covering over 3,700 acres in Dewitt County from which 110 oil wells produce. The leases contained a royalty provisions in the form and in the addendum. The addendum controls where the two are in conflict. The Olivers attempted in several ways to free themselves from the burden of PPC’s.

  • Form lease Paragraph 3: Lessee, at its option, will pay lessor “ … the average posted market price of such 1/5th part of all oil at the wells as of the day it is run to the pipe line or storage tanks, lessors interest, in either case, to bear 1/5th of the cost of treating oil to render it marketable pipe line oil …. “ (emphasis ours).
  • Addendum Paragraph 15: The lessor’s royalty on hydrocarbons shall never bear, directly or indirectly, any portion of the costs to save, store, gather, transport, treat, process, refine, manufacture, or market hydrocarbons, or the costs to construct, repair, or operate any related plant or facilities, or “any other costs or expenses whatsoever …,”
  • Addendum Paragraph 38:  Lessor reserved the right to take royalty oil in kind at the wells, … pending such election, the lessee shall purchase or market the lessor’s oil “at a cash price equal to the market value on the day of sale.”
  • Addendum Paragraph 35: All royalties are to be 20% of all oil and gas produced.

The Olivers sued alleging that Devon breached the leases by underpaying royalties. They argued that the free of “any other costs or expenses whatsoever” language in Addendum 15 superseded and eliminated the “at the wells” valuation point in Form 3. Devon responded that the addendum’s free-of-costs language did not establish a new valuation point. Therefore, the “at the wells” designation remained unchanged.  

The trial court granted summary judgment for the Olivers; the royalty interest was not valued “at the well” and the correct formula was “one-fifth of market value … on the day of sale.” After a trial on damages, the jury, obeying the judge’s erroneous instruction, awarded the Olivers $15,800,937.

The Analysis

The Court of Appeals began by citing the three components of any royalty clause:

  • a royalty fraction,
  • a yardstick (the pricing mechanism), and
  • a valuation point (the location at which the yardstick is applied).

Applying the reasoning of the Texas Supreme Court’s 1996 opinion in Heritage Resources, Inc. v. NationsBank, the Court concluded that the PPC language was mere surplusage when applied at the wellhead valuation point because no PPC’s are incurred at the well.

The default rule that royalties are free of production costs but not PPC’s is freely modifiable by the parties. The Court noted the leases did not specify an additional payment model to be remitted “in addition to” the royalty payment specified at the well; nor did they draft around Heritage. HINT to drafters: Heritage can be defeated by those who are paying attention.

Addendum 38 addresses only the yardstick (“market value”) and the lessor’s right to take in kind. Its silence on the valuation point does not render it in conflict with Form 3’s “at the wells” language.

Addendum 35 provides a royalty percentage of 20%. While under Addendum 15 the royalty shall not bear PPC’s, it does not establish a different valuation point. Accordingly, it merely supersedes and replaces the language in Form 3 that follows the valuation point language.

The Result

The Court determined that the leases established an “at the wells” valuation point, and the addendum’s PPC language did not create ambiguity or move the valuation point downstream. The jury award was improper because the damages were based on the downstream price, where crude oil is most valuable. The Court reversed and remanded for further proceedings.

Your musical interludes. Instruments only today. You have your folk music,… your Cajun ,,, your Appalachian … your African … your blues … your Irish … your Scottish …