O’Connor v. O’Connor addresses tracing of property in a divorce proceeding and an evidentiary issue, but there are lessons for parties to mineral deeds as well. First, …

A few Texas marital property rules

  • Property acquired by either spouse during the marriage is community property unless it is separate property.
  • Property owned or claimed by a spouse during or on dissolution of the marriage is presumed to be community property.
  • The presumption can be defeated by “clear and convincing evidence” of the separate nature of the property’s ownership.
  • Separate property includes property acquired by the spouse during marriage by gift, devise or descent.
  • Texas law presumes that a parent-to-child transfer of property is a gift.

The lesson

Your mineral deed (or any written transaction for that matter) could be in jeopardy if the recitations in the document do not match the substance of the actual transaction and the intent of the parties. The deed in question used words of conveyance for consideration, not of a gift. Then husband Mike could not trace the funds for the purchase to his separate property. Did the scrivener pull out a document from the form file without thinking through the transaction? Did the parties give the scrivener accurate instructions? Did somebody grab a form off the internet? Mike could not produce sufficient records to support his claim that he used separate property. Maybe the marital relationship was suffused with such bliss at the time of the transaction that nobody (talking to you, married persons who stand to inherit valuable stuff) thought a paper trail mattered.

The facts

Mike and Shannon were married in 1995. Mike’s mother died in 2009 and Dad became trustee of a trust in her name that held mineral interests in McMullen County. By Mineral Deed effective in 2009 Dad transferred minerals to Mike and Mike’s five siblings. The deed recited that “for accurate consideration paid and received”, Dad granted, conveyed, etc.

Trial

The trial court concluded the deed was not a gift. It had no gift language; it recited that the minerals were sold for an unspecified amount of adequate consideration that was tendered at the time of the transaction.

If Mike could not trace the transaction to his separate property then the minerals and proceeds therefrom would be community property. Mike’s tracing failed. He could not establish by clear and convincing evidence that he used separate property to acquire the minerals. Clear and convincing evidence is a measure or degree of proof that will produce in the mind of the trier of fact a firm belief or conviction as to the truth of the allegations sought to be established. That burden is high.   

Mike alleged that the trial court failed to admit evidence showing his father intended to transfer the mineral interests as Mike’s separate property when he directed conveyance of the interests from the trust to Mike and gave Mike $12,000 with which to purchase the interests.

The rejected exhibit was fully redacted in the reporter’s record. It did not indicate the substance of its contents or what Dad’s intent was. The appellate court was unable to determine the harm resulting from the trial court’s refusal to admit the exhibit because there is no record of what the exhibit would have shown. The alleged error was not preserved.

Tracing methods

The court discussed the various tracing methods and explained why one applied and the others didn’t:

  • the community-out-method (applied by the trial court):
  • the clearinghouse method,
  • the identical-sum-inference method,
  • the minimum-sum-balance method.

Mixing up your musical interludes:

Diana Krall

Elaine Elias

Eric Clapton

If you are the type to be preoccupied with the nuances (drudgery if you prefer) of federal statutory and regulatory interpretation, or if you have a fetish for acronyms, I recommend that you read all 41 spellbinding pages of W&T Offshore v. U S Department of the Interior. The rest of us will dig into the U S District Court’s consideration of the so-called Auer deference (judicial deference being a hot topic these days) and the fair-notice doctrine under the Fifth Amendment and the Administrative Procedure Act. That is as deep into these weeds as we should dare to venture.

The facts

W&T deducted from royalty payments to the government a transportation allowance under federal law for costs incurred in remediation of the offshore Pluto Flowline. W&T had a Unit Operating Agreement with Mariner, the operator of the Pluto Project. Previous owners were parties to an Operations and Maintenance Agreement that was terminated after several transactions involving interests in the Pluto Project and the Pluto Flowline.

Judicial deference?

Interior (by Minerals Management Service and the Office of Natural Resources Revenue) denied the allowance and demanded an additional $4MM+ in royalties. W&T sued alleging that Interior’s disallowance ran afoul of a host of federal statutes and regulations and was therefore arbitrary, capricious, and an abuse of discretion, and that the rejection violated fair notice requirements.

The court considered Auer deference (an agency’s interpretation of its own regulation is controlling unless plainly erroneous or inconsistent with the regulation). The court performed this analysis:

  • First, determine that the regulation is genuinely ambiguous by “exhausting all the ‘traditional tools’ of construction.” (Applying Texas law, the law of the contracts).  
  • Second, determine that the interpretation is reasonable. 
  • Third, evaluate whether the character and context of the agency interpretation entitles it to controlling weight.  See pp. 9-11 of the opinion for the factors.

Under the UOA, W&T was obligated to reimburse operator Mariner for costs of unit operations, but the Pluto Flowline was not listed as joint property under the UOA.

The court found:

  • The regulation upon which the agency’s ruling was based was not ambiguous.
  • Interior’s interpretation was reasonable. Therefore, Skidmore deference did not apply (based on the interpretation’s persuasiveness, a weaker form of deference than Auer).
  • Interior’s interpretation did not invoke the agency’s substantive expertise (offshore oil and gas activities). The question whether W&T incurred the costs under an arms-length transportation contract was based on general common-law principles of contract interpretation.
  • Interior’s interpretation was not arbitrary and capricious.
  • Auer deference and Skidmore deference did not apply to the agency’s decision.

The flaw in W&T’s position was that the UOA was not a transportation contract, which was a requirement for the allowance.    

The fair-notice doctrine

So far, so good for Interior. But the agency is required to give fair notice to whomever it is regulating that certain conduct is forbidden. Interior violated the doctrine:

  • Interior had never before interpreted the regulation at issue to hold that W&T’s method of remediation was unreasonable.
  • Interior knew that terms such as ”reasonable”, “moderate” and “fair” made the regulation subject to ambiguity.
  • Mariner had obtained several layers of approval in which the procedure was described and was never put on notice that it was not reasonable.  
  • Interior did not cite any statute, regulation or prior adjudication finding the procedure was not reasonable.

There is much more to the opinion than this summary, but the result is the parties’ dueling motions for summary judgment were denied in part and granted in part, Interior’s Final Decision denying the allowance was reversed, and the case was remanded to the ONRR.

Your musical interlude

She does originals, too.

Co-author Gunner West

City of Crowley v. TotalEnergies E&P USA, is a post-production cost (PPC) case with a predictable result. The Fort Worth Court of Appeals confirmed its reasoning in Shirlaine W. Props. Ltd. v. Jamestown Res., L.L.C from 2021, that under a market-value oil and gas lease, gas sold at the wellhead means that other promises within the lease that royalties will never bear PPCs don’t matter. The lessee will bear its share of costs incurred to make the gas marketable.

Background and legal framework

The lessor’s share of production depends on two factors: the valuation metric (market value, proceeds, or price) and the point of valuation (at the well or other point of the). Together, these factors determine whether the royalty bears PPCs.

Gas sold at the wellhead is valued before PPCs are incurred and the royalty owner typically shares those costs through the workback method (which estimates wellhead value by subtracting PPCs from prices received downstream). In contrast, a gross-proceeds royalty is measured by the lessee’s actual receipts at the point of sale and is free of PPCs when the sales occur downstream.

The lease provisions

The court examined four key provisions of the royalty clause:

  • Payment will be the “Royalty Fraction of the market value at the point of sale, use, or other disposition”. The point of sale here was the wellhead;
  • The market value “will never be less than the total proceeds received by Lessee in connection with the sale  …” .
  • “[I]f Lessee realizes proceeds of production after deduction for any expense of [postproduction] . . . then the reimbursement or the deductions will be added to the total proceeds”; and
  • “Lessor’s royalty will never bear, either directly or indirectly,  . . . any part of [PPCs].”

Shirlaine controls

The court found the lease provisions to be nearly identical to those in Shirlaine. The valuation provision fixed market value at the wellhead – the point of sale. Moreover, adopting the lessor’s reading would improperly rewrite an at-the-well market-value lease into a “total proceeds” lease.

The court’s analysis

The Shirlaine reasoning was logically, legally, and linguistically sound, said the court.

The City’s argument that PPCs constitute “deductions” because gas buyers anticipate incurring them “twists commonsense economics into something it is not.”  Treating the gas buyer’s expectation of downstream costs as a “deduction” from the seller’s proceeds conflates price formation with expense recovery. While the commonly-used workback method anticipates PPCs to estimate wellhead market value, this doesn’t mean the seller actually “realizes proceeds . . . after deduction” of those costs. The workback method is merely a proxy for market value.

Market value at the well means the value before gas is prepared for market. There are no marketing costs to deduct from the value. Post-sale expenses are, by definition, post-sale. Therefore, with the wellhead as the valuation point the lessees do not “realize proceeds . . . after deduction for any [postproduction] expenses.”

The add-on and no-PPC clauses did not apply to these facts; perhaps those clauses could apply if the point of sale was a place other than the wellhead.

The court affirmed summary judgment for the lessees. The lessees did not breach the lease by calculating the lessor’s royalty without including PPCs.

Caveat

Don’t read too much into this or any other PPC case. Our Supreme Court reminds us frequently that the effect of any royalty clause depends on the language of the clause itself. Beware of general statements of the law.

Your musical interlude.

Lagniappe

Its bedtime and your stash of melotonin is depleted? We can help! Read these summaries of cases cited in the opinion to learn more about PPCs:

BlueStone Nat. Res. v. Randle

Burlington Res. Oil & Gas Co. v. Tex. Crude Energy

Devon Energy Production Co. v. Sheppard

Shirlaine

Co-author Gunner West

The Texas Supreme Court in Roxo Energy Company, LLC v. Baxsto, LLC reinforced a fundamental contract principle: when fully integrated agreements plainly conflict with prior oral representations, reliance on those inconsistent prior oral statements is unjustifiable as a matter of law. In other words, a party to a contract cannot justifiably rely on prior oral representations contradicted by written terms.

The Facts

During mineral lease negotiations, Roxo and its backer Vortus assured Baxsto that Roxo would develop the acreage “at the bit”, was not in the business of “flipping” leases, and had committed hundreds of millions to the project—promises Baxsto said induced it to sign. For all we know both Roso’s statements and Baxsto’s reliance are true, but it doesn’t matter.

The transaction documents included a paid‑up lease, an agreement granting Roxo an option to purchase the lease, and a lease memorandum to be recorded only after a $5,000‑per‑acre bonus was paid. Despite this condition, Roxo prematurely recorded the memorandum without Baxsto’s knowledge.

After receiving two option extensions—the first adding a six-month “most-favored nations” clause guaranteeing Baxsto any higher bonus Roxo might pay others—Roxo disclosed that Vortus had scaled back development funding. Roxo then paid the bonus, exercised its option, but declined to drill. Instead, Roxo negotiated to purchase Baxsto’s mineral interests before ultimately flipping the lease to another operator for $11,000 per acre.

Baxsto sued for fraudulent inducement. The trial court granted summary judgment for Roxo; the Eastland Court of Appeals reversed, finding justifiable reliance because the written agreements didn’t “plainly contradict” the oral representations nor contain sufficient “red flags.”

The Analysis

The Supreme Court thought otherwise, and analyzed the representations in three categories, applying a straightforward principle: oral representations directly contradicted by written terms cannot support a fraud claim.

Development and Assignment Promises.

Despite extensive oral assurances about drilling and avoiding lease transfers, the fully integrated written agreements gave Roso the unqualified right to assign. Roxo could transfer the lease at will, and no drilling obligations were imposed. These written terms directly contradicted any oral development promises. Because Baxsto freely agreed to a lease that expressly permitted transfers and omitted drilling requirements, any reliance on contradictory oral assurances was unjustifiable as a matter of law.

Bonus Payment Representations.

Baxsto claimed Roxo fraudulently misrepresented bonus payments by stating the competing operator received only a $3,500 per acre bonus, that Baxsto’s $5,000 per acre bonus was the area high, and that Roxo’s purchase offer constituted a “great deal.” However, the only bonus-related written term was the six-month “most favored nations” clause, which Baxsto did not allege was breached. The absence of a written promise comparing bonuses “should make it obvious to a reasonably sophisticated party like Baxsto that the previous discussions may no longer be part of the deal.”

Non-Disclosure

These claims failed on two grounds. First, Roxo and Baxsto were commercial counterparties, not fiduciaries, creating no duty by Roso to disclose premature recording of public documents that Baxsto could have independently discovered through routine title searches. Second, Baxsto offered nothing more than conjecture that Roxo’s promise to delay recording induced the ultimate sale of Baxsto’s minerals. The Court found this connection too attenuated to support the claim. Accordingly, summary judgment was proper.

What does it mean?

This decision reversed a lower court that found issues of fact sufficient to deny summary judgment for the defendants. With this decision and several others of recent vintage, litigants should now understand that the Texas Supreme Court as it is now constituted will be strongly inclined to disfavor efforts by a party to deviate from the plain meaning of a written contract, including claims that the contract was tainted by false representations during negotiations.  

Your musical interlude

Co-author Gunner West

“He who comes for the inheritance is often made to pay for the funeral”.* When heirs inherit property together and can’t agree on its use, Texas courts strongly prefer dividing the land physically rather than forcing a sale, even when one owner wants to cash out.

Atkinson v. Land Endeavors held that under the Uniform Partition of Heirs’ Property Act, courts must order partition in kind unless the party opposing physical division proves substantial prejudice to all cotenants, not just themselves.

Three Sisters, Two Sales, One Standoff

Joseph Atkinson devised the surface estate of his 152-acre tract in equal, undivided one-third shares to his three daughters. Two sold their interests to Evans and Rossi; heir Paula Atkinson held her share.

Evans and Rossi filed a partition action against Atkinson in accordance with the Act. Atkinson declined the cotenant buyout option under Section 23A.007.

At trial, Atkinson, a California lawyer appearing pro se (after running through three different counsel), requested partition by sale rather than physical division. She contended that carving the tract into smaller parcels would erode its investment value, complicate ongoing oil‑and‑gas operations, and invite surface‑use conflicts with mineral owners.

Despite her challenge, the trial court ruled that the property was susceptible to partition in kind, confirmed each party’s undivided one‑third interest, and appointed a surveyor and three commissioners to divide it into contiguous parcels wherever feasible. Atkinson appealed.

Evidence Supporting Partition in Kind

The appellate court affirmed the trial court, grounding its analysis in Section 23A.008’s directive that, in the event of an unsuccessful buyout, the court shall order partition in kind unless the court, after consideration of the seven factors listed in Section 23A.009, concludes that sale is proper. The trial court found that partition in kind would not result in substantial prejudice to the cotenants as a group.

The court applied the seven factors:

  • Practical divisibility: the property—a rectangular, fully wooded, vacant tract in an un‑zoned area—could be divided practicably; appraisal maps and testimony from Evans and Rossi confirmed workable physical boundaries.
  • Value impact: Atkinson offered no evidence demonstrating that subdividing the wooded land would depress aggregate fair‑market value below the proceeds of a unitary sale. Rather, the appraisals characterized the tract’s highest and best use as recreational, rural‑residential, or agricultural, not commercial timber.
  • Duration of ownership favored neither side, as the land had been held jointly by all three heirs before they conveyed their shares;
  • Atkinson’s sentimental attachment was outweighed by her own request to liquidate the asset;
  • Alleged interference with oil‑and‑gas operations was unsubstantiated, and minerals are presumed equally distributed absent contrary proof — none was offered;
  • No evidence showed unequal contributions to taxes, insurance, or improvements; and
  • Miscellaneous considerations (wetlands, existing easements, limited access points) did not foreclose a fair geographic split.

Because Atkinson bore the burden to prove the tract was incapable of equitable division and failed to supply contrary valuations or operational impediments, the court concluded that partition in kind would not substantially prejudice any cotenant.

Atkinson’s several other points of error were overruled. One was unpreserved because she never raised the issue or obtained a ruling in the trial court. The other, including a “laundry list of multifarious complaints,” (the legal term is “bellyaching”) lacked supporting legal authority or adequate briefing and thus was waived (which looks like what you get when you represent yourself).

Your musical interlude.

*Said to be a proverb. We got it from the internet.

Co-author Gunner West

It seems to be fairly well settled that you can’t use trespass-to-try-title to recover a nonpossessory royalty interest in Texas. What if you call the interest a “mineral interest stripped of every attribute except the right to receive royalty”? The result is the same; you can’t.

In Devon Energy Production Company, L.P. v. McClure Oil Company, a Texas appellate court held that parties seeking title to a nonpossessory interest must pursue declaratory relief, not trespass-to-try-title claims (which we will refer to as TTT). This procedural miscalculation proved fatal for nearly all parties who prevailed at the trial court. Deficiencies in the movants’ pleadings undermined the relief they obtained.

Competing Deeds

The dispute originated from two 1928 deeds from J.V. Heyser concerning mineral interests in five Glasscock County sections:

  • the “Dean Deed” (January 17, recorded February 14), conveyed a 3/8ths interest in oil, gas, and other minerals to Dean;
  • the “Boston Deed” (February 1, recorded February 4), conveyed Heyser’s remaining interest to Boston, reserving a 3/8ths NPRI and rentals under existing oil and gas leases and a 3/8ths NPRI of the standard 1/8th royalty on future leases.

Operator Laredo Petroleum (now Vital Energy) interpleaded royalties due to uncertainty over which deed controlled and how to calculate the Boston reservation’s royalty. The Boston Deed reserved a double‑fraction NPRI and current leases paid more than 1/8th. So, should the NPRI be calculated as fixed or floating?

Many successors in title joined the litigation, tracing title through one deed or the other.

  • The Dean Deed successors sought to recover their mineral estates.
  • The Boston Deed successors sought bona‑fide‑purchaser protection under the Texas recording acts and argued that the Boston Deed could not convey interests already granted to Dean.

After a marathon of summary judgment filings determining deed priority, construing the Boston reservation, adjudicating TTT claims and defenses, and awarding ownership interests—the trial court held the Dean Deed (first-executed, second-recorded) prevailed over the Boston Deed, rejected the Boston Deed successors’ affirmative defenses, and granted title and royalty rights to the Dean Deed successors.

A strategy gone wrong

Dean Deed successor SH Permian’s deed-priority MSJ argued explicit alternative theories: TTT if the Dean Deed prevailed, declaratory relief if the Boston Deed prevailed. Despite opportunities to correct course, including the trial court’s invitation to “clean up [its] pleadings,” SH Permian maintained its position.

The Dean Deed appellees – winners at the trial court – ultimately asserted claims for trespass to try title only, if the Dean Deed prevailed, and thoroughly briefed their positions before and after the deed-priority ruling. Thus, when the trial court ruled the Dean Deed took priority, those parties were bound by the parameters of the order that locked in the trespass-to-try-title theory.

The defect surfaced at final judgment. SH Permian asserted it owned “a mineral interest equal to an undivided 1/8th royalty interest,” while Devon claimed “an undivided 4% floating royalty interest.” Through summary judgment grounded in their trespass‑to‑try‑title pleadings, the trial court awarded the Dean parties nonpossessory interests.

Procedural Mismatch

On appeal by the Boston Deed successors the appellate court determined that the prevailing parties’ pleadings failed to support the nonpossessory interests awarded in the trial court’s partial summary judgment favoring the Dean Deed.

The court emphasized the procedural mismatch, reminding the parties (and anyone reading this blog) that TTT is generally not the appropriate action to be asserted when recovery is for nonpossessory interests. TTT requires possession. No possession = no trespass.

The court rejected arguments that the error was harmless. Even when characterized as “mineral interests stripped of every attribute except the right to receive royalty”, the interests at issue were “in the nature of a royalty”. Such interests cannot support possessory remedies, regardless of how they’re labeled.

The dominos fall

Once the trial court had ruled on deed priority based on TTT claims, that determination infected all subsequent proceedings. Even when SH Permian later attempted to amend its pleadings to add declaratory relief two and a half years late ( one imagines after a few sleepless nights), the court denied the motion; the amendment came too late to cure the deficiency.

The “pleadings‑relief” deficiency cascaded through the litigation, affecting the other Dean-Deed appellees as well. Devon Energy “hitched its wagon to SH Permian’s filings” by joining the deed-priority motion, and the “Birds parties” adopted SH Permian’s pleadings throughout. Vital later acquired a portion of another parties’ claimed interest and reentered the case but sought the interest through TTT.

The appellate court reversed and remanded on all issues—deed priority, affirmative defenses, and title determinations. Only one Dean Deed successor escaped reversal because its pleadings matched its prayer.

Your musical interlude.

State of Texas. V. Reimer et al. studied lawyer-nerdy questions of standing to bring a lawsuit and statutes of limitations as applied to inverse condemnation suits.  Spoiler alert: To the chagrin of the landowners, waiting over 30 years to assert your takings claim is not the best course of action.     

The facts

In 1965 the Sanford Dam created Lake Meredith, significantly reducing downstream flow of the Canadian River through the six-mile stretch at issue. The reduction exposed previously submerged land.

Beginning in 1982 the State granted oil and gas leases on portions of the riverbed to Huber. The 10-year leases were consistently renewed for decades with Huber establishing numerous productive wells. During the litigation Huber operated 21 wells in the area. The litigation began in 1993 when the State sued a Reimer forefather for trespass when he erected a fence blocking oil and gas lessee Huber’s access to producing wells. The Landowners asserted an unconstitutional taking of their oil and gas interests without compensation sometime between October 1999 and April 2000.

The Legislature at one time directed the GLO to make a survey marking the boundary of the river, which the GLO never did. Instead, Huber commissioned his own survey. In January 1982 Huber’s surveyor Shine filed his survey, which the GLO adopted. The survey identified the gradient boundary of the river locating the last natural riverbed before the dam’s completion. According to the Court, January 28, 1982, was the day when the State began taking the Landowners’ mineral interests.

Standing – constitutional or prudential?   

The state challenged the Landowners’ standing to bring the suit on three grounds:

  • they did not own the land when the taking occurred and had no assignment;
  • existing mineral leases prevented the Landowners from developing minerals themselves;
  • Huber acquired ownership through adverse possession, the Landowners had no compensable interest.

The Landowners satisfied constitutional standing by alleging concrete injuries to claimed property interests, traceable to the State’s conduct, with likelihood of redress through favorable judgment. Thus, the challenge was not to subject matter jurisdiction (Had the Court found there was none, it would be compelled to dismiss the case without addressing the merits).

The State’s challenge was to prudential jurisdiction because it involved the general prohibition on a litigant raising a claim on another person’s legal rights without proper assignment or authority. It is not standing as much as it is a substantive limitation on the landowner’s legal capacity. Regardless, the Landowners’ claim was barred as a matter of law.

Limitations

The Landowners’ claims were barred by limitations as a matter of law. Texas has no dedicated statute of limitations for inverse condemnation claims. Using the law of adverse possession as an analogy, Texas courts have concluded that inverse condemnation claims are barred by expiration of the 10-year limitations period in Texas Civil Practice & Remedies Code §16.026. The taking begins when the physical taking occurs or entry on land is made. The Landowners claimed the 25-year limitations in §16.028 governed. The 25-year limitations did not apply.

Simply put, the Court looked at the plain language of the two statutes and gave the unambiguous statutory language its plain meaning. The Court declined to judicially amend the statute by adding words that are not implicitly contained in the language of the statute.

The Court denied the Landowners’ aggregation theory (involving separate properties owned by different landowners) because it could lead to an absurd result.

The judgment

Reversing the trial court, the Court rendered judgment that the Landowners take nothing.

Your musical interludes, lady singers now and before. Pick as many as you want:

Calista Clark

Arleigh Kincheloe

The Castellows

Peggy Lee

Janice Joplin

Nina Simone

Dow Construction, LLC v. BPX Operating Company resolved a bundle of issues arising out of a drilling unit established by the Louisiana Commissioner of Conservation: who has the right to a drilling cost report, the operator’s right to deduct post-production costs, forfeiture of the operator’s right to reimbursement of drilling costs, and prescription.

The facts

BPX is operator of a drilling unit. Dow is a lessee of property within the unit. BPX was deducting PPCs from Dow’s share of production proceeds. Dow sued on several claims, arguing that BPX forfeited the right to demand contribution for drilling costs from Dow as an owner of unleased interests and BPX improperly deducted PPC’s from Dow’s proceeds. BPX responded that Dow’s interest was not an “unleased interest”, and Dow’s claims were time-barred.

The statutory scheme

Each non-operator of a drilling unit is responsible for its share of development and operating costs of unit wells. Upon request, the operator must issue a report containing sworn statements about drilling and operating costs, production volumes, and sales prices. The operator who fails to timely respond forfeits its right to recover costs. BPX was burdened by previous operator Petrohawk’s failure to respond to Dow’s requests for well cost information.

FOUR QUESTIONS

Standing and the “unleased interest”

LA. R.S. 30:10(A)(3) refers to “unleased interests” in establishing who has the right to demand a drilling cost report from the operator. The Court found the statute to be ambiguous; having different meanings depending on the context. Based on Civil Code art. 12 and the context in which the words occur and the text of the law as a whole, the Court read “unleased interests” to be unleased to the as to the operator rather than having no lease whatsoever. Dow had the right under the statute to demand a report and the operator risked forfeiture of the right to recover drilling costs if it failed to comply with the statute.

Negotiorum gestio and deduction of PPCs

Without significant comment the Court vacated and remanded the trial court’s application of the doctrine of negotiorum gestio, which would authorize the operator to deduct PPC’s from non-operators’ proceeds on the basis of Civil Code art. 2292. This was consistent with the Louisiana Supreme Court’s recent opinion in Self v. BPX Operating Company.

PPCs and recovery of costs

Per La. R.S. 30:103.2 the operator’s right to demand contribution for drilling costs from owners of unleased interests is forfeited when it fails deliver the proper reports. The question: What costs are included in drilling operations? The Court followed a Louisiana Third Circuit opinion that under La. R.S. 30:103.1 “drilling operations” refers to the total cost of drilling and completing the unit well and “all other unit costs” allocable to an owner. “All other unit costs” encompasses PPCs. PPCs should be categorized as operational costs and expenses as they form an integral part of the overall business operation.

Prescription

Whether Dow’s claims were governed by one-year or 10-year prescription depended on whether the damages were contractual or delictual. The courts treat causes of action as delictual unless the plaintiff alleges a violation of a specific contractual provision. In an action arising out of the breach of duty imposed by law damages are delictual and are extinguished by the prescription of one year. Dow’s allegation of a breach of the notice provision of 30:103.1 did not arise from a contractual obligation. Thus, the prescriptive period was one year.

Your musical interlude

Co-author Stephen Cooney

In Cactus Water v. COG Operating, the Supreme Court affirmed that mineral lessee COG, not water rights owner Cactus (who derived it rights from the surface owner), has the right to possession, custody, control, and disposition of constituent water in liquid waste – so-called produced water – from its hydrocarbon production.

Homework is recommended.  See these previous posts on the subject.  We will pick up from there.

Texas Supreme Court Will Review Produced Water Case | Energy & the Law

Who Owns Produced Water in Texas? | Energy & the Law

Ownership of produced water depended on the scope of the language employed in the granting clauses of COG’s leases, which specifically named only “oil and gas” or “oil, gas, and other hydrocarbons.”

According to the Court, resolution of the ownership question depended not on uncertainty about the lease language but on what set of established principles governs conveyance of an unnamed substance: produced water. Water is not part of the mineral estate. Unless expressly severed, subsurface water remains part of the surface estate subject to the mineral estate’s implied right to use the surface—including water—as reasonably necessary to produce the minerals. A conveyance of water is not effected by implication. But if an unnamed substance is part and parcel of an oil-and-gas conveyance, there is no need to list it separately because the substance would already be included in what was expressly conveyed regardless of whether their presence or value was known at the time of conveyance.

The Court said that there is no dispute that produced water is, and was at the time of the leases, oil-and-gas waste. That the leases did not mention or define “waste” or “produced water,” was not unexpected. The production of liquid waste is an inevitable and unavoidable byproduct of oil-and-gas operations. Granting the right to produce hydrocarbons necessarily encompasses the right to produce and manage the resulting waste.

The Court rejected Cactus’ reliance on groundwater cases, which do not address waste by-products of oil-and-gas production. The Court observed that while produced water contains molecules of water, both from injected fluid and subsurface formations, the solution itself is waste – which is “a horse of an entirely different color.”

Statutes and regulations treat water and produced water differently and distinctly because they are distinct and different. The Court relied on the same statutes and regulations cited by the lower court to conclude that Texas laws define “oil-and-gas waste” in terms that include produced water.

The Court also rejected Cactus’ argument that COG’s possession of the produced water was usufructuary in nature.  The right to destroy, dispose of, or consume property is generally inconsistent with a usufructuary right. Instead, the right to the capital value of property, including by means of consumption, waste, or destruction, is inherent in property ownership.

Several of the leases explicitly restrict COG’s water usage. From this Cactus posited that the leases are clear that no water produced from the land could have been included in the conveyance. But those express limitations further emphasized to the Court the distinction between water molecules entrained in hydrocarbon production and the common understanding of water.

Remember freedom of contract

Surface-estate owners can take comfort in the Court’s observation that parties are free to make their own contract with respect to incidentally produced liquid-waste if surface owners intend to retain ownership. Here they did not, and courts cannot employ a backward-looking construction of conveyances that is informed by new technologies that were not within the parties’ contemplation at the time of the conveyances.

In a concurring opinion three justices agreed with the result but identified questions the opinion did not resolve. In particular, the ruling does not address unleased minerals and, having held that the leases at issue include groundwater produced with hydrocarbons, the Court does not go on to address the mineral lessee’s obligations to the landowners with respect to this leased groundwater. What does that mean? Litigation over water in Texas is far from over.

Your musical interlude, change Boston to Austin and there you have it.  That one was to easy. How about a dose of optimism.

In Franklin v. Regions Bank the Fifth Circuit concluded that a royalty clause in a mineral lease resulted in a gross proceeds royalty; the royalty owners did not bear their proportionate share of post-production costs. Read on if you want to know how the Court reached this conclusion.

The form lease said,

  • Royalty on gas would be “the market value at the well of one eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one eighth of the amount realized from such sale”.

An addendum (Exhibit “A”) said,

  • “In the event of a conflict between the language as stated in Exhibit A and the language stated hereinabove, the language in Exhibit “A” shall prevail.
  • [W]henever the term one-eighth (1/8) appears in the printed lease form … said term is hereby deleted and the term 25% is inserted and substituted therefore.
  • There shall be no cost charged to the royalty interest created under this lease.  

The ambiguity

The Fifth Circuit deemed the royalty provision to be ambiguous and allowed extrinsic evidence to determine the parties’ intent. The form provided the royalties would be paid on the “market value at the well” but the addendum included inconsistent limiting language: PPC’s would not be charged to the royalty interest.

The parties’ failed by express language in the addendum to alter the royalty calculation from market-value-at-the-well to gross proceeds. That would have fixed it. And the addendum did not make it apparent at what point in the post-extraction process the royalty would be calculated. The meaning of the agreement was fairly susceptible to more than one interpretation and therefore was ambiguous.

The trial court considered conflicting testimony from witnesses, expert and otherwise, and previous lessee Petrohawk’s history of paying royalties without deducting PPC’s. Per La. CC art. 2053, Petrohawk’s course of dealing gave particular meaning to and supplemented or qualified the terms of the agreement.

The Louisiana Rule

The Court discussed Warren v. Chesapeake Exploration, and Heritage v. NationsBank, but those were Texas cases. The Louisiana default rule is that the royalty owner shares responsibility for PPC’s, but the allocation is discretionary between the parties.

According to the Court, Louisiana has identified two methods for determining market value at the well: The method that has meaning here is to reconstruct market value by starting with gross proceeds from the sale of the minerals and deducting costs of taking the minerals to the point of sale. The increase in the sales value attributable to the expenses incurred in transporting and processing the commodity ordinarily must be deducted from the royalty. But here the addendum’s controlling language demanded a different result.

The result

The District Court awarded Franklin $3.4 million in past damages and $954,000 in estimated “future royalty damages”. The Fifth Circuit affirmed the District Court’s ruling that the royalty clauses created gross-proceeds leases and reversed and remanded the rejection of evidence of actual future losses. The evidence was available at trial but ignored, which was reversible error.

There was more

No room here to discuss other issues:

  • A previous suit by Franklin against Matador to rescind a 2007 extension of a 2004 lease and a previous trip to the Fifth Circuit in this case,
  • This suit was against Regions for mishandling the lease extension which caused them to receive 20% royalties on the extended lease instead of 25% under two 2008 Petrohawk leases,
  • Region’s prescription, law-of-the=case, and exculpatory clause defenses (all failed),
  • Calculation of pre-judgment interest,.
  • The Court’s several references to Louisiana Mineral Leases: A Treatise, by Lafayette lawyer Patrick Ottinger.

Your surprising musical interlude … and the (incomparable, sorry Mick) original.