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.

Co-author Emily Morris *

One of the questions raised in 1776 Energy Partners, LLC v. Marathon Oil EF, LLC was whether Marathon as operator could apply revenues owed to non-operator 1776 under one joint operating agreement to satisfy unpaid debts owed on another. Unfortunately, we don’t have an answer. (FWIW, this is the same “1776” from a recent post, whiffing at the plate again with runners in scoring position.)

The litigants were parties to the Culberson, Longhorn and Bordovsky JOAs. 1776 stopped paying its share of expenses under the Culberson and Longhorn JOAs and advised it was going to drill a well on Bordovsky, in which it was the operator. Marathon questioned how 1776 could fund a new well when it owed millions on other wells. 1776 responded that the new well would be funded by outside investors.

Marathon began cross-netting revenues against expenses and sent an AFE proposing three wells under the Culberson JOA along with a $9.4 million cash call. 1776 had 30 days to elect whether to participate and if it elected to participate, 15 days to pay the cash call or it would be deemed non-consent.

1776 elected to participate in the new wells but would not pay the cash call. The parties engaged in a series of complicated negotiations over two years in an attempt to resolve the situation. The negotiations failed.

Practice tip

One tactic that probably should have been avoided was an employee of 1776 responding to Marathon’s notice of default by emailing a picture of a man pulling out empty pants pockets.

Litigation ensued. Witnesses at trial disagreed on pretty much everything, including, for example, whether a certain phone call ever even happened.

The court entered a final judgment for Marathon based on the summary judgment order and evidence presented at trial showing principal and interest owed under the Bordovsky JOA and credits owed on the Culberson and Longhorn JOAs.

What about cross-netting?

The trial court declared that the Culberson JOA did not require 1776 to pay debts under other JOA’s in order to participate in the drilling of the three proposed wells under that JOA. This was based on Marathon’s refusal to assure 1776 and its outside funders that it would not cross-net the new wells’ cash call under one JOA against debts on the others.  The court of appeals agreed with Marathon that the ruling resolved a hypothetical question rather than a live controversy. It was an advisory opinion because 1776 never paid the Culberson cash call.

1776 had one last bottom-of-the-ninth opportunity on cross-netting. After partial summary judgment in favor of Marathon for $1.9 million plus interest for breach of the Culberson and Longhorn JOAs, 1776 moved to amend its counterclaim to assert that Marathon’s cross-netting was a repudiation and anticipatory breach of the Culberson JOA and to seek a declaration that cross-netting was not allowed. The trial court denied the amendment on the basis that it was not timely filed. That ruling was upheld on appeal.  Result: No answer to the cross-netting question.  

Procedural issues

In addition to reversing 1776’s declaratory judgment, the court of appeals overruled challenges by 1776 to the final judgment on issues including admissiblity of expert testimony, the jury charge, fraud by nondisclosure, calculation of damages, the effect of an “alternative judgment”, and segregation of attorneys’ fees.

Your musical interlude. Our regretfully tardy remembrance of D-Day!

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

Co-author Blake Bryan *

Tips on litigation avoidance: Not making promises you don’t intend to keep is easy enough. Stating a fact or making a promise and things change, you could be a fraudster if you don’t come clean before closing.That’s the takeaway in Baxsto, LLC v. Roxo Energy Co., a Texas Court of Appeals reversed a summary judgment dismissing fraud claims by a mineral owner-lessor against defendants the lessee and its financier. For details we refer you to the 47-page fact-intensive opinion.

The facts

Mineral owner Baxsto negotiated with Roxo and Vortus for a lease and potential sale of its minerals in Howard and Borden Counties.

After the transaction Baxsto discovered actions and statements by Roxo and Vortus that conflicted with representations in negotiations and promises in the parties’ letter of intent. Baxsto sued asserting fraud and derivative claims, alleging they locked it into a lease and an agreement to sell the minerals at a price lower than the true market value. The trial court granted summary judgment in favor of the defendants on all claims. Baxsto appealed.

For simplicity we combine the allegations and findings in no-evidence and traditional summary judgment motions. The questions of fact were about knowledge of falsity, intent to induce, and duty to disclose. The court of appeal ruled that at least a scintilla of evidence raised a genuine issue of material fact on all three elements.

Knowledge of falsity

  • Defendants knew their representations about a most-favored-nations clause for lease bonuses were false because they paid a lease bonus to a third party that exceeded Baxsto’s.
  • Roxo knew that it never intended to drill and develop the interests it acquired.
  • Defendants knew that their funding commitment of $200–250 million was false when made.
  • Roxo knew that its promise not to record the lease until after the lease bonus was paid was false.

Intent to induce

  • Knowledge of the falsity of representations was enough evidence to create a fact issue on intent to induce.

Duty to disclose

  • The defendants had a duty to disclose that several representations that might have been true when made were no longer true. 

Justifiable reliance

The issue was whether Baxsto could have plausibly relied on defendants’ representations.  Three clauses in the contract relied upon by the defendants did not directly contradict their oral representations. Thus, they failed to meet their burden of identifying conditions in the contracts. The Court also determined that there were no red flags making reliance unwarranted.

Statute of frauds

Defendants’ duty to Baxsto arose independent of the parties’ contract regardless of whether the damages sought were solely for economic losses. The economic lass doctrine did not bar the claims.

The recovery that Baxsto sought was akin to a claim for out-of-pocket damages for being induced to part with its mineral interests at a price lower than their true value. Fraud claims seeking out-of-pocket damages—the difference between the value parted with and the value received—are not barred by the statute of frauds, unlike benefit-of-the-bargain damages.

Derivative fraud claims

Evidence was sufficient to create genuine issue of material fact on Baxto’s claims for

  • Beneficiaries of fraud,
  • Civil conspiracy,
  • Constructive trust, and
  • Joint enterprise.

The facts are complicated, there are lots of them, and they will be hotly contested (A sham affidavit claim was overruled). Who knows if Baxsto can prove its claims to a jury.  The parties will return to the district court for a trial.

Your musical interlude, new band, ancient theme.

*Blake is a Baylor Law 2-L and a summer associate at Gray Reed.

Freeeport-McMoRan Oil and Gas, LLC and Ovintiv USA Inc. v. 1776 Energy Partners LLC  presented a recurring question faced by Texas oil and gas producers:  When can proceeds of production be withheld by the operator without liability for interest?

Ovintiv and its predecessor operator, Freeport-McMoRan, represented by Gray Reed partners Jim Ormiston and David Leonard, suspended proceeds it was contractually obligated to pay to non-operator 1776 in reliance on the safe harbor provisions of Section 91.402(b) Texas Natural Resources Code.

Upon learning that a Final Judgment had been entered in an unrelated case in favor of Longview Energy Company and against 1776 (then called Riley-Huff Energy), awarding title to leasehold interests and production proceeds to Longview, Ovintiv placed the disputed proceeds in suspense pending resolution of the underlying title dispute.  Ovintiv advised Longview and 1776 that it would deliver the proceeds to their rightful owner once the title dispute was resolved.  The Texas Supreme Court issued its mandate reversing the Longview Judgment and Ovintiv promptly paid the suspense funds to 1776, but 1776 continued to prosecute its claims for statutory interest and attorney’s fees.

Section 402(b) permits a payor (operator) to withhold payment of production proceeds without interest under several circumstances, including when “there is … a dispute concerning title that would affect distribution of payments” or if “there is… a reasonable doubt that the payee… has clear title to the interest in the proceeds of production.”

The trial court granted summary judgment for Ovintiv. The safe harbor statute applied as a matter of law to Ovintiv’s suspense of the proceeds.  The final judgment also awarded Ovintiv and Freeport-McMoRan legal fees against 1776 pursuant to a prevailing party clause in the Joint Operating Agreements.

The Court of Appeals reversed finding that there were fact issues regarding whether the safe harbor statute applied, even though the underlying facts were not disputed.   

The Supreme Court reversed and reinstated the trial court’s judgment, finding the safe harbor statute applied as a matter of law and Ovintiv was entitled to suspend the proceeds without liability for interest or attorney’s fees.   

1776 argued that the Longview Judgment did not “affect distribution of payments” because 1776 retained legal title to the leasehold interests and proceeds or held them as trustee under the constructive trust for the benefit of Longview.  1776 also argued that its $25 million supersedeas bond in connection with the appeal of the Longview Judgment entitled it to continue to receive proceeds during the appeal.  The Supreme Court rejected both arguments, reasoning that the plain meaning of “would,” as “expressing a contingency or possibility,” and the plain meaning of “affect,” as “to produce an effect on,” justified application of the safe harbor statute as a matter of law.   

The Court also analyzed whether Ovintiv had a reasonable doubt that 1776 had clear title to the proceeds as an independent ground for safe harbor protection.  Although reasonableness sometimes is a fact question, the Court reasoned that Ovintiv’s reasonable doubt must be determined based on an objective standard premised on persons of ordinary sensibilities. Because the underlying facts were undisputed, Ovintiv’s reasonable doubt presented a question of law where only one rational inference can be drawn.

The Court held as a matter of law that Ovintiv had reasonable doubt that 1776 had clear title to the proceeds of production. The Longview Judgment imposed a constructive trust over the subject leasehold interests and associated proceeds, which clouded 1776’s title. Thus, the very existence of the underlying title dispute, so long as it was not frivolous, clouded the title even though the Longview Judgment was ultimately reversed.

Tina Turner, RIP

Co-author Derek Younkers *

And what a difference it was! In Apache Corp. v. Apollo Expl. LLC et al, Apache and others acquired an oil and gas lease on 100,000+ acres in the Texas Panhandle. The primary term was three years. The effective date was January 1, 2007, “from which date the anniversary dates of this Lease shall be computed”.  Extension beyond the primary term required a producing well and the creation of three blocks of equal acreage from which the lessees would drill wells to a combined depth of 20,000 feet per block per year.

The parties recorded a Memorandum of Lease in the public records. The Memorandum recited that it was “subject to other provisions of the Lease” and “the Primary Term thereof expires on the 31st day of December 2009.”

The other lessees sold 75% of their working interest to Apache by a series of substantially identical purchase-and-sale agreements. Section 2.5 granted each Seller a back-in working interest for up to one-third of the interests it conveyed to Apache once the wells reached “Two Hundred Percent … of Project Payout.”

Section 4.1 required Apache to offer “all of [its] interest in the affected Leases (or parts thereof) to Seller at no cost to Seller” should Apache’s drilling commitment for the year result in the loss or release of any of the leases.

In 2014, Apache bought lessee Gunn’s remaining interest of the leases and its PSA rights.

In 2015, Apache failed to drill 20,000 feet in the North Block of the lease.

The question for the Court: Did the North Block expire on December 31, 2015, or January 1, 2016?  The day the North Block expired determined whether Apache breached the contract by failing to offer the lease back to Sellers or had until the end of 2016 to drill the 20,000 feet.

The Sellers sued for breach of contract and declaratory relief. Apache filed four motions for summary judgment asking the Court to rule that:

(1) Apache complied with § 4.1;

(2) § 2.5’s 200% provision meant that Apache had to reach a 2:1 return on investment before Sellers could exercise their back-in option;

(3) the North Block expired on January 1, 2016; and

(4) § 4.1 required Apache to only offer back each Seller’s original interest, not all of the interests.

The Court applied the common-law default rule for describing time when parties use the words “from” or “after.” Under the rule, the date from or after a period is to be measured is excluded in calculating time periods. Thus, a period of years ends on the anniversary of the measuring date, not the day before. No language in the lease manifested a clear intent to displace the rule.

The Memorandum stipulated the lease would expire on December 31, 2009, but by its terms the Memorandum was subordinate to the lease. The lease was not ambiguous, so the Court ignored extrinsic evidence of the December date and found the primary term ended on January 1. Thus, the North Block expired on January 1, 2016.

The Court found that Section 4.1 only required Apache to offer back to each seller its original interest. A contrary interpretation would require Apache to offer each seller 100% of the same interests. (The court of appeal decision focused more on this issue.)

Finally, Section 2.5 meant a 2:1 ratio of profits to expenses. The Sellers’ argument that they could back in when profits equaled expenses would render the 200% language meaningless.

The Court remanded the case for further proceedings.

Your musical interlude.

* Derek is a rising 2-L at Baylor Law School and a Gray Reed summer associate.

You might recall our posts on litigation by states, counties, and cities blaming a host of calamities, real and imagined, past and future, on Big Oil. The producers tried their best to remove the cases to federal court. In a two-sentence ruling, the United States Supreme Court refused to consider defendants’ Hail-Mary to have the cases remain in federal court. This was the City of Baltimore case but it is expected to affect all climate litigation in which the plaintiffs assert only state law claims. The jurisdictional mud-wrestling is over and it’s back to the state courts for resolution.

In the future, you can follow climate litigation at this site: U. S. Climate Change Litigation sponsored by Columbia Law School and Arnold and Porter.

In the meantime, the breathless MSM celebrated the decision, likening these cases to the Big Tobacco litigation from years back.

Is the push to electrify the world at the expense of oil and gas achievable and if so, at what cost? Is government moving dangerously fast? Let’s hear from those who know more about the subject than I:

Daniel Markind in Forbes focuses the legal and financial challenges faced by New York State’s natural gas ban (60% of New York’s energy comes from fossil fuels). It’s probably pre-empted by federal law anyway.

The Wall Street Journal observes that the government doesn’t have to actually implement regulations that are destructive to the economy, the threat itself drains the life out of investment in whatever the government is targeting.

https://www.wsj.com/articles/power-plants-environmental-protection-agency-rule-epa-biden-administration-fossil-fuels-60f06bd0

According to E.J. Antoni in the Daily Signal, Biden’s Push for electric vehicles is expensive and unrealistic.

What the push will do to economy it will also do to the birds.

Finally, a two-fer: over-regulation and offshore wind turbines in the Northeast could endanger your Friday fishsticks say some Maine fishermen.

BUT WAIT!

Misguided ideology is a two-way superhighway. Here in Texas, the wind capital of the free world, our erstwhile laissez-faire Legislature loads the deck against alternative energy, says Texas Monthly.

RIP Chris Strachwitz, founder of Arhoolie Records. A musical interlude from one of his first discoveries.

Imagine these facts in a force majeure dispute (as presented in Point Energy Partners Permian LLC et al. v. MRC Permian Company).

Lessee (MRC) invokes the force majeure provision of an oil and gas lease, asserting that “wellbore instability” on a well on an unrelated lease requires the lessee to effectively redrill portions of the other well, setting back its rig schedule for the lease at issue. The event results in a 30-hour slowdown in the drilling of the other well. The lessee’s deadline to spud a new well on the lease to avoid lease termination is May 22, which it mistakenly records as June 19. Lessee schedules the spud date for June 2. Lessee discovers the error after the deadline has passed. Lessee could have spudded the well by the May 22 deadline but decides to drill the other well first. Before lessors receive a June 15 force majeure notice from MRC they sign new leases with Point Energy. 

MRC sues Point Energy and the lessors for trespass to try title, repudiation and civil conspiracy to tortiously interfere with the existing lease. Point Energy counterclaims for trespass to try title, accounting and constructive trust.

Who wins?

The force majeure discussion

The Court described a force majeure clause as a “contractual provision allocating the risk of loss if performance becomes impossible or impracticable, especially as a result of an event or fact that the parties could not have anticipated or controlled”. The Court observed that force majeure clauses “come in many, shapes, sizes and forms” and may vary according to

  • The definition of force majeure,
  • the causal-nexus requirement,
  • the remedial-action requirement,
  • the notice requirement, and
  • the grace period excusing or delaying performance.

The Court focused on the “causal-nexus” requirement that is a necessary predicate to properly invoke the force majeure clause and decided that MRC did not satisfy the predicate.

As for remedial-action requirement, the lessee must use its “best efforts” to overcome the problem, which would not have been satisfied even if there had been no delay because the drilling of the new well as scheduled (i.e., after the lease termination deadline) would not have satisfied the continuous drilling requirement to perpetuate the lease.

The Court also determined that MRC would have had enough time to move the rig to the well on the lease at issue and to commence drilling by the termination date but chose to drill other wells first.

MRC’s proposed definition of the meaning of “delay” was not persuasive. The Court cautioned against taking literalism too literally and adopting of wooden construction of a word foreclosed by the context of the document at issue. That’s a mouthful, but the lesson is the Court will not allow a party to focus on the meaning of one wordd at the expense of the entire document.

The Court concluded that the ordinary person using the phrase “Lessee’s operations are delayed in by an event of force majeure”, given its textual context, would not understand those words to encompass a 30-hour slowdown of an essential operation that was already destined to be untimely due to a scheduling error.

The Court conclujded that the force majeure clause did not save the lease, and the Court rendered a take nothing judgment on MRC’s tortious interference claims to the extent those claims were predicated on application of the force majeure clause to save the lease.

Other issues preserved but not reached by the Supreme Court, such as the extent of acreage that would be held under a retained-acreage clause, were remanded to the Court of Appeals. 

Your post-Jazz Fest musical interlude

In TotalEnergies E&P USA, Inc. v. MP Gulf of Mexico LLC. the Supreme Court of Texas resolved the chaos created by conflicting dispute resolution regimes in three contracts for ownership and operation of an offshore unit and gathering system. The essential question: Did the parties agree that an arbitrator, rather than the courts, must determine the arbitrability of the disputes.

The Court held that the parties clearly and unmistakably allocated arbitrability issues to the arbitrator when they agreed to arbitrate their controversies in accordance with the AAA Commercial Rules, and their agreement to arbitrate some controversies but not others did not affect the delegation of the arbitrability decision to the arbitrator.

There were three contracts: the Chinook Unit Operating Agreement, a System Operating Agreement, and a Cost-Sharing Agreement for a common system to secure and transport production from the Chinook Unit and another unit. There were three procedings:

  • TotalEnergies sued in district court for a declaration construing the Cost-Sharing Agreement, which had no arbitration clause. That dispute required the court to look at the Chinook Operating Agreement but no one asked the court to determine the parties’ rights under the Chinook Operating Agreement,
  • TotalEnergies initiated an arbitration seeking determination of the parties’ rights under the Chinook Operating Agreement, which required arbitration of any controversy arising between the parties.
  • MP Gulf initiated an arbitration under the American Arbitration Association Commercial Rules, alleging that TotalEnergies breached the System Operating Agreement, which required arbitration of any controversy arising out of the agreement

The Court summarized the state of arbitration law in Texas:

  • Arbitration is a creature of contract, not coercion. Parties will not be forced to arbitrate unless they agreed to it.
  • When a party challenges the validity of a contract, but not of an arbitration agreement within the contact, the courts must enforce the arbitration agreement and require the arbitrator to decide the challenge to the broader contact. …
  • But when a party challenges the scope of the arbitration agreement, the courts must resolve that challenge ….
  • UNLESS the parties agree that the arbitrator will decide.
  • Courts will enforce an agreement to delegate arbitrability to the arbitrator if that agreement is “clear and unmistakable”.
  • The general rule is that an agreement to arbitrate under the AAA rules is a “clear and unmistakable” agreement that the arbitrator is the one to decide whether the disputes must be resolved through arbitration.

The Court referred to American Arbitration Association Rule 7(a). As it existed at the time the arbitrations were initiated the rule empowered arbitrators to “rule on his or her own jurisdiction.”  The rule changed in September 2022 to specifically designate the arbitrator as the arbiter of the scope of the arbitration.

What about a contractual carve-out of issues? It didn’t matter. Delegation to arbitrability to the arbitrator included the decision on the scope of the issues to be arbitrated and those that would not be.  … That is, unless the parties agreed more specifically than in this situation what would be arbitrated and what would not be.

Interested in the history of Texas, federal and other state court decisions on this subject? You are invited to read the opinion, all 50 pages of it. These meager 500+ words cannot do justice to all of that history.  And you don’t want a treatise anyway, so we are in accord.

Your mid-Jazz Fest musical interlude.