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 …

You might know Plaquemines Parish, Louisiana, for ’60’s political boss-segregationist Leander Perez. or maybe for its role in launching Huey Long’s political career after the New Orleans city fathers blew a hole in the levee in order to save the Queen City from the 1927 flood. (The Kingfish would go on to terrorize out-of-state oil companies until he was assassinated in 1935. You can still see marks from the shots that missed in the marble walls of the state capitol building.)

Now, the parish that separates New Orleans from the Gulf of MAGA is back in the news. Dozens of lawsuits against oil and gas companies under Louisiana’s State and Local Coastal Resources Management Act will be impacted by Chevron USA v. Plaquemines Parish, Louisiana, SLCRMA creates a cause of action against parties that use Louisiana’s coastal zone without required permits. Louisiana parishes allege that the companies’ operations have caused extensive land loss and damage to Louisiana’s coastal wetlands. The decision broadens the scope of federal officer removal available to private contractors.

The exemptions

SLCRMA’s grandfather clause exempts from the permitting requirement specific uses legally commenced or established prior to the 1980 effective date of the program. The 2018 “Rozel expert report” opined that certain of Chevron’s pre-1980 oil production activities were not lawfully commenced because they did not comply with prudent industry practices at the time, thus denying those companies (to-wit Chevron) the exemption and placing WWII-era conduct at issue. Examples of the challenges to Chevron’s production activities are failure to use steel tanks instead of earthen pits, its use of vertical-drilling methods, and use of canals instead of roads.

Federal officer removal
The federal officer removal statute  authorizes removal to federal district court of any civil action or criminal prosecution commenced in state court against “any officer (or any person acting under that officer) of the United States or of any agency thereof, in an official or individual capacity, for or relating to any act under color of such office.” In interpreting the statute the Court held that Chevron’s World War II-era crude oil production in Plaquemines Parish’s coastal zone “related to” Chevron’s performance of its federal contract to refine aviation gasoline for the U.S. military during that time, thereby satisfying the “for or relating to” requirement of the statute.

After Chevron removed the case, the federal district court (and its Western District counterpart in Cameron Parish v. Apache) granted the parishes’ motion to remand, ruling that even though Chevron and other vertically-integrated companies had federal avgas refining contracts, those contacts said nothing about how defendants were to obtain crude oil. They could purchase it on the open market, for example. Thus, crude oil production activities were not sufficiently “connected or associated with” the refining activities.

The Fifth Circuit consolidated the appeals and affirmed, holding that the “connected or associated with” element was not met for two principal reasons.

  • The refining contracts gave defendants complete latitude to forego producing any crude and instead buy it on the open market, so crude production was not directed by the contract, and
  • The Petroleum Administration for War’s (PAW) crude oil allocation system—under which the federal government, not the companies, determined which refineries received which crude—severed any connection between Chevron’s production and its refining operations.

The “relating to” standard

The Supreme Court read “relating to” broadly, to mean “to stand in some relation; to have bearing or concern; to pertain; refer; to bring into association with or connection with”. The Court noted that one thing can relate to another even if the connection is “indirect”; even if it was “not specifically designed to affect” the other; and even without a “strict causal relationship”. A removing defendant need not show that its federal duties specifically required or strictly caused the challenged conduct. The Fifth Circuit’s approach was too narrow.

In finding that the parish’s suit was closely connected to Chevron’s wartime activities, the Court rejected both of the Fifth Circuit’s principal grounds for affirming the remand.

  • The ordinary meaning of “relating to” does not requrre that the defendant show that his federal duties specifically invited his conduce, and
  • An act can relate to its consequences even when the causal chain includes actions by intermediaries.

Plaquemines argued that removal requires the defendant to have been “acting under” a federal officer in taking the specific actions challenged in the suit. The Court rejected this as inconsistent with the statutory text.

The Supreme Court vacated the judgment and remanded the case for further proceedings. Whether the Rozel report carries the day is not the issue at this stage. That question will be resolved in federal court and not the (defendants likely assume) home-town friendly state court just down the river.

Your musical interlude

… and one for Mom

Co-author Caleb White

In Fasken Oil and Ranch, Ltd. v. Puig the Supreme Court of Texas resolved whether a deed conveying a non-participating royalty interest “free of costs forever” relieved the royalty owners from bearing postproduction costs for minerals sold downstream. Under the language in the deed in this case, it did not.

The facts

The Puig’s own an NPRI in a mineral estate located in Webb County reserved in a 1960 deed in which their predecessor in interest sold ranchland to Palafox Exploration Company. Fasken is the successor in interest to Palafox, and operates oil and gas wells on the leaseholds.

The Puig deed provides:

There is SAVED, EXCEPTED AND RESERVED, in favor of [Puig] an undivided … 1/16 of all the oil, gas and other minerals, …  in, to and under or that may be produced from the above described acreage, to be paid or delivered to [Puig] … free of cost forever.

 After Fasken produces minerals from the wells, it transports, treats, processes, and sells them as condensate and natural gas. In calculating the Puigs’ royalty on produced minerals Fasken deducts costs incurred between the wellhead and the point of sale from the price obtained for the processed gas.  

Puig challenged this method of calculation and sought a declaration that their royalty was free of PPCs, and should be based solely on the price obtained on the processed minerals in sales at the downstream market. Puig pointed to the deed language: The royalty was “free of cost forever.” As such, Fasken should be precluded from deducting PPCs prior to calculating the royalty. Fasken responded that Puig’s royalty was calculated based on the value of the gas “produced from the above described acreage”, not a downstream sales price.

The analysis

The Court began with the default rule: Unless the parties agree otherwise, an NPRI is subject to PPCs incurred to prepare the raw oil or gas for sale downstream. The Court noted two primary ways parties may free a royalty interest from bearing PPCs.

  • setting the valuation point of the royalty downstream of the well, or
  • employing explicit terms that add some or all PPCs to the royalty base.

 The Puig deed did neither. The deed described a geographic location: minerals “produced from the above described acreage.” The Court explained that production is the process of bringing minerals to the surface, and production of raw gas occurs at the wellhead. While parties to a deed can set the valuation point and method independently, absent contrary language, a royalty in minerals “produced” and nothing more is a royalty valued at the well.

The Court likened “produced from the above describe acreage” as the functional equivalent of an at-the-well designation. The Court reasoned that this language identified the physical location at which the Puigs’ interest is created, indicating that the royalty interest is in minerals as they come out of the ground, not after PPCs have increased the minerals’ value.

The Court concluded that “free of cost forever” does not change the valuation point or formally relieve the royalty of PPCs. Instead, “forever” merely refers to the temporal duration of the royalty interest. Absent a reference to another valuation point or calculation method in the deed, the cost-free language merely restates the rule that a royalty interest is free of cost incurred in exploring for and producing raw minerals.

The Result

The Court determined that the Puig deed provided for a royalty that is free of costs incurred in exploring for and producing minerals. “Free of costs forever” did not change the valuation point of the royalty interest from the wellhead to the fully processed minerals downstream. Fasken was correct to deduct PPCs from the downstream sales price in calculating the Puigs’ royalty.

David Alllen Coe RIP. He made it famous, remember it was written by the late great Steve Goodman.

Way back in 2023 it was predicted that the Supreme Court of Texas’ decision in Van Dyke v. Navigator would spawn years of litigation. How right the predictions were!

In Boren Descendants and Royalty Owners v. Fasken Oil and Ranch, Ltd,, consolidated with Mabee Ranch Royalty Partnership v. Fasken Oil and Ranch Ltd., the Court granted petitions for review of a single judgment from the 11th Court of Appeals and returned the cases to the 11th court.    

As the supreme court reiterated recently in Clifton v. Johnson, in instruments granting or reserving a royalty expressed as a double fraction, there are two distinct paths to establish ownership of the interest: Construction of the original deed and the presumed grant doctrine. These cases implicate both paths. The 11th Court reviewed only the deed construction path.

At issue is a 1933 deed in which Fasken holds an “undivided one-fourth (1/4) of the usual one-eighth (1/8)“ nonparticipating royalty interest. Fasken sued alleging the NPRI floats with current leases and is not a fixed fraction. The trial court granted partial summary judgment for Fasken agreeing there was no evidence that the presumed grant doctrine applied. The court of appeals affirmed, holding that the deed reserved a floating 1/4th NPRI and affirmed as to affirmative defenses of estoppel, waiver, ratification, and limitations, but concluded it lacked jurisdiction to consider the presumed grant doctrine because it was not included within the list of issues the trial court identified in its order permitting an interlocutory appeal. The supreme court reversed the trial court’s denial of Mabee Ranch’s summary judgment motion on Fasken’s cause of action for breach of contract.

The supreme court noted that for 85 years the parties and their successors treated the instrument as reserving a fixed 1/32nd NPRI. Fasken admitted it treated the royalty as fixed during that entire time, it paid taxes on 1/32nd and no greater interest, and it was not aware of its predecessors treating the NPRI as anything other than 1/32nd.

The court of appeals’ concern that its jurisdiction was lacking was misplaced. The presumed grant issue was among fairly-included subsidiary and ancillary issues in the trial court’s order. The essential question in all of these appeals is, who owns this property today? To answer that question the presumed grant doctrine could not be severed from an appeal involving textual analysis of the deed.

Citing Clifton as a clarification of the law, the supreme court reversed the court of appeals’ opinion on jurisdiction, vacated the judgment on the merits, and remanded the cases for a fresh consideration of the merits because that court did not consider the presumed grant doctrine. The parties will be allowed to present Clifton-related arguments to the court of appeals.

Is a fact issue hiding somewhere in this judicial forest that will send the cases back to the trial court for yet another round? We will see. Full disclosure: My Gray Reed colleagues and I represent royalty owners on the losing side.

RIP Dave Mason, Traffic … songwriter, … guitar player

Co-author David Pruitt

Davis v. Aethon Energy Operating LLC is more for lawyers than business people but it is worth noting. A Texas court of appeals affirmed a take-nothing judgment against lessors who sued over the lessee’s failure to provide required information on check stubs. The question asked of the jury did not match the requirements of the statute the lessor was suing under. The court measured the sufficiency of the evidence against the charge as given.

The Facts

Lessors Lud and Charlotte Davis sued lessee Aethon and several related entities. The Davises’ leases required them to bear their portion of post-production costs, including a transportation fee that Aethon-related entity Scona charges for marketing gas.

During 2020, each check stub to the Davises listed the transportation charge as “$0.00.” The Davises suspected Aethon was embedding the fee in the total sales price and concealing the charge through its accounting methods. After an unsatisfying explanation from Aethon’s general counsel, the Davises concluded that Aethon was artificially inflating post-production costs. They sued in March 2021.

Also in that month, Aethon serendipitously changed its accounting practices and began separately itemizing the transportation fee, maintaining the change was unrelated to the lawsuit and was made in order to automate payout calculations for cost-free royalty owners.

The statute

Texas Natural Resources Code § 91.501 requires a payor to include information specified in § 91.502 “on the check stub, an attachment to the payment form, or another remittance advice that accompanies the payment.” Among the required disclosures are “any other deductions or adjustments.”

At trial the jury charge didn’t track the statute. Question Six asked whether Aethon failed to provide the Davises with the information “to which they were entitled each month” — not on “each check stub.” The court held that because no objection was made to the charge, the sufficiency of the evidence was measured by the charge as given, even if it is an incorrect statement of the law.

Under the language in the charge, the jury concluded that Aethon satisfied its statutory duty by disclosing the required information at some point in time other than on the check stub. Thus, an email from Aethon’s general counsel explaining the fee, combined with the fact that the fee was separately itemized beginning in March 2021, gave the Davises enough information from which to calculate the charge for the pre-March 2021 period, and allowed Aethon to satisfy its legal obligations as stated in the question. It probably helped Aethon that Lud Davis was a sophisticated royalty owner who had the information to calculate the fee at least two years before trial.

Bottom line – the jury charge

Questions to be answered by the jury are important. The Davises may have had a strong case under the text of § 91.502, but the jury evaluated the evidence against the question actually posed, not the as-written language of the statute. The evidence was legally and factually sufficient to support the jury’s verdict.

Your musical interlude.