Anadarko Petroleum Corporation v. Alternative Environmental Solutions Inc. addressed a Master Services Agreement for environmental services. The busy Fifth Circuit decided what law should apply, excused Anadarko for failing to raise issues in a previous suit, partially reversed an attorney’s fees award, denied punitive damages, and ignored a failure-to-give-notice defense.

The MSC chose General Maritime Law or Texas law, and venue would be in Harris County, Texas. AES would “ … be responsible for and assume all liability for and… defend, release, indemnify and hold harmless Anadarko from and against claims arising in connection with AES’s violation of Applicable Laws.” AES’s work was performed in Wyoming and Louisiana.

Pawlosky, an owner of AES, sued his former co-owner in Louisiana state court for a scheme in which Anadarko was defrauded by overbilling. Pawlosky also sued Anadarko for vicarious liability for the participation by Howard, an Anadarko employee, in the scheme. After several years of litigation in Louisiana state court, Anadarko sued in the Southern District of Texas for a declaration that AES had a duty to defend and indemnify Anadarko. This is the case as issue here. On appeal, a trial court judgment for Anadarko was affirmed in part and vacated in part.

Which law to apply?

Louisiana law could override the contractual choice of law only in limited circumstances. Texas law won out. Texas’ connection with the contract was a bit more significant than Louisiana’s in light of the factors courts consider when determining that question, and Louisiana did not have a materially greater interest in the dispute.

Application of Texas law would not be contrary to the fundamental policy of Louisiana. AES argued that the Louisiana Oilfield Indemnity Act voided the contract. The LOIA addresses indemnities for bodily injury; this was a contract dispute. AES then argued the indemnity was for an illegal purpose because Howard took part in the illegal scheme and Anadarko could not seek indemnity for its own actions. The court rejected that argument as well. The contract itself was not for an illegal purpose, and Anadarko was seeking indemnity for AES’s violations, not Howard’s.

Judicial estoppel

Denied. The Fifth Circuit disagreed with AES’ assertion that litigating in Louisiana state court without raising the choice-of-law or indemnity provisions estopped Anadarko from invoking them in federal court. AES offered no evidence that Anadarko ever took an inconsistent position in the Louisiana case and the new claims need not be raised as compulsory counterclaims in the Louisiana litigation. The Court suggested that AES could have argued waiver or forfeiture.

Punitive damages

The District Court’s judgment by its wording could have allowed for recovery of exemplary and punitive damages, indemnity for which were excluded by the MSC. The Fifth Circuit vacated that portion of the judgment and remanded for the district court to modify its judgment to explicitly exclude punitive and exemplary damages.

Failure to give notice

AES argued Anadarko failed to give notice of its claims as required under the MSC. Denied. A notice provision has to be employed when it is useful to do so. To require notice in this case would have been futile.

Attorney’s fees

The District Court erred in awarding attorney’s fees to Anadarko. The award included fees for both the declaratory action and the Louisiana lawsuit. Attorney’s fees incurred in a separate lawsuit because of a breach of a duty to defend are actual damages to be proven at trial. The award of attorney’s fees for the declaratory action itself was affirmed.

Your musical interlude. Peggy Lee and an inventive drummer.

Co Author: David Pruitt

In re Shale Oil Antitrust Litigation considers whether the nation’s largest shale producers conspired to restrain domestic shale oil production to artificially increase the price of crude oil and its derivative products throughout the United States. The U.S. District Court for the District of New Mexico concluded that the allegations against the defendants are plausible, which is sufficient for the case to move forward.

The Court granted in (small) part and denied in (large) part motions to dismiss the 54-count consolidated class action alleging that eight shale oil producers: Permian Resources, Chesapeake (now Expand Energy), Continental Resources, Diamondback Energy, EOG Resources, Hess, Occidental Petroleum, and Pioneer Natural Resources, along with former CEOs Scott Sheffield and John B. Hess, conspired to restrain domestic shale oil production and artificially inflate prices.

The facts

Plaintiffs are end-payors: individuals, businesses, and political subdivisions who purchased gasoline, diesel, heating oil, and other petroleum products at allegedly inflated prices. Their theory: during the “Shale Revolution,” defendants became “swing producers” capable of materially influencing crude oil prices and beginning around 2021 collectively throttled production growth even as prices soared past $120 per barrel and their breakeven costs hovered around $30. Plaintiffs pointed to private dinners between defendants and OPEC officials at the annual CERAWeek conference in Houston, public statements touting “discipline” over growth, and FTC consent decrees that barred Sheffield and John Hess from joining the boards of their companies’ acquirers based on evidence of years-long price-fixing efforts.

The issues and the ruling

Political question and act of state

Defendants argued the case was nonjusticiable because it would require the court to evaluate OPEC’s conduct. The court disagreed, holding that plaintiffs’ central theory targeted a domestic conspiracy among domestic defendants, none of whom are OPEC members or foreign sovereigns.

Parallel conduct and plus factors

The court held that plaintiffs plausibly alleged parallel conduct – not through absolute production cuts, but through reduced relative growth rates compared to pre-pandemic levels. The “plus factors” pushing the claim from possible to plausible included a top-heavy market structure with inelastic demand; interfirm communications and opportunities to collude (CERAWeek dinners, etc.); the FTC investigations; horizontal shareholding through overlapping institutional investors such as BlackRock, Vanguard, and State Street; and actions against economic self-interest, namely withholding production despite falling breakeven costs and rising prices.

Antitrust standing

Defendants argued that end-payors who never purchased crude oil directly from them lacked standing. The court found that plaintiffs plausibly alleged a direct throughline: defendants restrained shale oil production, which inflated crude prices, which predictably inflated gasoline and derivative product prices paid by consumers.

A handful of state-law claims were trimmed. Alabama’s antitrust statute, for example, does not reach interstate conspiracies. The vast majority of claims survived.

Bottom line

The case will move forward. Allegations of coordinated “discipline”, tied to the OPEC dinners, public statements eschewing production growth, and institutional investor overlap survived the motions to dismiss. In considering a motion based on Rule 12(b)(6) the court accepts the allegations as true. So, whether any conspiracy to violate antitrust laws can be proven remains to be seen.

 Answer to last week’s quiz

David Duke. Notorious white supremacist, KKK grand wizard, serial political candidate, and target of the “Vote for the crook; it’s important” campaign slogan.

More codger-defying musical interludes:

Caamp

Florence + the Machine

Red Clay Strays

Our blog doesn’t often opine on politics; it can be bad for business. But the voters’ options for Railroad Commission compel a comment. I’m voting for the Democrat Joe Rosenthal. These opinions are mine alone. I don’t know what my law partners, clients and friends think about this race, Bo French, or Republicans and Democrats generally.

Bo French claims he is not a politician. He’s just, he protests, a rancher and oil and gas investor steeped in the honorable, Christian and manly pursuits of a real Texan, the kind they don’t make enough of anymore. If he really is a politician, which is what you are when you are a candidate for a powerful statewide office, he is the wrong kind of politician. He abused his platform as chair of the Tarrant County Republican Party to widely broadcast his xenophobia. This post by my friendly competitor John McFarland provides details.

DO NOT VOTE FOR BO FRENCH! — Oil and Gas Lawyer Blog — August 31, 2026

Mr. French’s campaign promised during the primary:

  • Stop “an Islamic invasion of Texas” from stealing oil and gas resources. (Huh?)
  • End Diversity, Equity and Inclusion initiatives, funding and practices at the Texas Railroad Commission. (Our solidly Republican RRC leadership leans woke left? Who knew?)
  • Establish a “pro-family credentialing program” for oil and gas operators. (Take-your-kid-to-work-day … on the rig … steel-toed boots, drug tests and hard hat required).

At an industry event this past summer he was questioned about his paranoid worldview and asked whether his attitudes were the look that reflects well on Texas and its public officials. His response: He was merely “repeating what Texans think”. His comments, he said, were “taken out of context by a far-left reporter” (from the Fort Worth Star-Telegram?)

Do you want a shameless bigot and political opportunist as your commissioner? I’d rather have Mr. Rosenthal the Democrat; could be too liberal for the average Texan but at least he’s honest and knows the business. Mr. Rosenthal promises he isn’t a California, New York or Colorado Democrat. Maybe. We might get to see.

There’s more!

This week, as reported by the Texas Tribune, Cornyn calls out Bo French over racist social media post Mr. French proposed to deport 100 million people and denigrated minority University of Texas students.

Heaping more shame on the Republican voting base, when asked for a comment the morally and ethically challenged Republican nominee for the U.S. Senate elected not to criticize French’s latest bigotry.

If it weren’t so important it could be written off as fremdschämen.

Your musical interlude.

Quiz: Can you identify the recent historical figure in the photo? Look for the answer in the next post.

Co-author: David Pruitt

If a Texas operator commits to minimum throughput volumes to secure pipeline capacity and ends up paying “deficiency fees” when production falls short, can it deduct those fees from overriding royalty interest payments as a post-production cost? In Burlington Resources Oil & Gas Company LP v. Texas Crude Energy, LLC, the answer was yes.

 The facts

Texas Crude owns overrides in oil and gas leases under wells operated by Burlington. Texas Crude’s affiliate Amber Harvest receives the royalty payments. The underlying agreements do not address post-production costs. For nine years, Burlington calculated royalty payments due Amber Harvest by subtracting the royalty owner’s proportionate share of PPCs (incurred between the wellhead and the point of sale).

This is Round Two of the litigation. In 2019, the Supreme Court of Texas held that the parties’ Prospect Development Agreement and Joint Operating Agreement permitted Burlington to charge Texas Crude (and Amber Harvest) their proportionate share of PPCs and remanded the case to determine the amount. On remand, the parties agreed to stay the litigation so Texas Crude could audit Burlington’s royalty payments.

Then things got interesting. Texas Crude claimed Burlington stonewalled the audit, and in 2024 the trial court awarded $287,000+ in attorney’s fees and expenses under Rule 215 for “discovery abuse”—even though the parties had agreed to halt discovery. Meanwhile, Texas Crude amended their petition to challenge Burlington’s deduction of “deficiency fees” under four transportation and supply agreements. Burlington moved for summary judgment on that issue and won. Both sides appealed.

 The deficiency fees

The central question: Were the deficiency fees deductible from Amber Harvest’s royalty payments as PPCs?

Burlington’s transportation agreements required ConocoPhillips (Burlington’s parent) to pay minimum throughput fees regardless of actual volumes delivered. When production fell below the contractual minimums, the shortfall was billed as a “deficiency fee.” A similar mechanism existed under a supply agreement with BP Products – sell less than the agreed amount and sales proceeds are reduced.

Burlington’s uncontroverted affidavit evidence established that without committing to pay these fees, Burlington could not have secured the pipeline and terminal capacity needed to move oil from the Sugarloaf Wells to market. Texas Crude submitted no controverting evidence.

The Court found virtually no judicial authority analyzing deficiency fees, and thus turned to the Manual of Oil and Gas Terms and prior authority on firm transportation charges. The conclusion: the deficiency fee is an actual cost “of transporting oil or gas to a market,” and the label on the invoice, whether it be “throughput” or “deficiency”, does not change that reality. 

The rationale

PPCs “applies to processing, compression, transportation, and other costs expended to prepare raw oil or gas for sale at a downstream location.” After PPCs have been expended, the product’s value is enhanced, making it more valuable than straight out of the well. Id. Thus, royalties on products at their downstream point of sale are more valuable than royalties on the same products at the well.

 Discovery sanctions

The court made quick work of discovery sanctions against Burlington. Rule 215 applies to discovery. But here the parties asked the trial court to stay all discovery and the court obliged. There were no discovery requests and no motions to compel. The court concluded it was arbitrary and unreasonable to find “discovery abuse” when there was no discovery to abuse. Reversed and rendered: Texas Crude takes nothing on sanctions.

Takeaway

If the operator was required to commit to a deficiency fee in order to get product from the wellhead to the point of sale, it is a deductible PPC – regardless of whether actual volumes met the contractual minimum.

This is a day of several musical interludes. When the codgers say there is no good music after … (pick a date, usually before 1973) … suggest that they burn the worn-out tie-dyed t-shirts that no longer fit, bury the roach clips they haven’t used since the kids came along, and listen:

Aaron Lee Tasjan

Elle Cordova

Saint Paul and the Broken Bones

Co-Author: David Pruitt

Why should related companies lawyer-up to protect themselves when entering a contract to manage an oil and gas property? The question is not rhetorical. Mesquite Energy, Inc. v. Sanchez Oil & Gas Corporation is a cautionary tale about what can happen when affiliated entities don’t sort out, until it’s too late, who owns intellectual property they create together.

The facts

The Sanchez family operated Sanchez Energy Corporation (“SN”), a public E&P company, and Sanchez Oil & Gas Corporation (“SOG”), the family’s private company. Under a Services Agreement, SOG employees provided management and operational support to SN, executives routinely held the same titles at both companies, and SOG’s personnel directed day-to-day operations that SN funded. In 2014, SN acquired the Catarina Asset for $639 million. Facing declining commodity prices, SN and SOG jointly developed “Zero Dark Forty,” a cost-reduction program that significantly slashed drilling and operational costs at Catarina.

In 2016, three SOG employees left for a competitor, Terra Energy Partners, absconding with thousands of proprietary files, including Zero Dark Forty data. SOG, SN, and a related partnership, SNMP, sued Terra and the disloyal employees. (SNMP is not relevant to the outcome or this discussion.) SN paid the legal fees. The Terra litigation eventually settled in 2024, and the net proceeds went into escrow while SOG and Mesquite (SN’s post-bankruptcy successor) fought over how to split up the proceeds.

The question

Who owned the Zero Dark Forty trade secrets – the company that wrote the checks or the company whose employees built the program?

The law and the ruling

Mesquite argued: Because SN funded Zero Dark Forty, it owned the trade secrets. SOG countered: Its employees developed the program under its operational control and the effect of the Services Agreement was to vest ownership in SOG.

The Texas Business Court determined that neither party was entitled to sole ownership. Funding is probative of contribution but not dispositive of exclusive title, especially where the parties operated as an integrated enterprise. And the Services Agreement itself contained no express language assigning newly developed trade secrets to either party. With executives wearing two hats and employees holding concurrent roles at both companies, the court found the relationship was anything but arm’s-length. The trade secrets were jointly developed, and the settlement proceeds were split 50/50.

The court also invoked unjust enrichment to order SOG to reimburse Mesquite for half of the pre-contingency legal fees SN had paid. SOG passively received a benefit, half a settlement, that would not exist but for SN’s sole funding of the litigation. One cannot sit on the sidelines and then claim a full share of the rewards without contributing to the cost.

Takeaway

It is probably not realistic to expect related parties, especially family-affiliated companies sharing officers, employees and office space, to negotiate as though they were strangers, each suspicious of the other guys. At the time the arrangement was established it didn’t matter, everyone being on the same team. But when the relationship changes, whether through bankruptcy, a sale of one entity or the other, the passage of time or whatever no one was thinking about happens, it matters a great deal.

Draw your own lessons from Mesquite. Maybe its not that affiliated entities should treat every intra-family collaboration as it would if the counterparty were a stranger. Perhaps the question should at least be considered: If we create something valuable together, who owns it if, for example, an unanticipated but not unimaginable event occurs? (After all, how unforseeable is an oil and gas bankruptcy?) An IP ownership provision in the Services Agreement could have resolved this dispute before it started.

Your musical interlude.

Co-Author Gunner West

In Pioneer Nat. Res. USA, Inc. v. Elberta M. Royalty, LLC, a Texas court held that a lease calling for payment of royalty on the “net amount received by Lessee for the sale” of oil and gas required lessee Pioneer to pay its lessor Elberta on a cotenant’s production from first production, though the cotenant did not pay Pioneer for nearly two years. The 120-day deadline in Section 91.402(a) of the Natural Resources Code ran from the first sales from the well, not from the day Pioneer’s check arrived.

The facts

Pioneer’s Upton County lease pays 22.5% of the net amount the lessee receives for the sale; Pioneer paid royalty on its own wells without incident. Henry Resources, a cotenant holding leases from other owners in the same land, drilled the Pearl wells, which began producing in January 2021; Henry did not pay Pioneer its share until November 2022. Elberta, the lessor under Pioneer’s lease, sent a statutory 30-day notice in January 2022; Pioneer did not respond and paid two years of accrued royalty only in January 2023. The trial court dismissed Henry for lack of a payor-payee relationship and held Pioneer liable under the lease and Chapter 91 of the Texas Natural Resources Code.

The lease

Pioneer argued that the royalty is owed on the net amount “received by Lessee,” and it personally received nothing until Henry paid. On that reading, its royalty obligation and the statutory deadline both waited until Pioneer received payment from Henry.

The court rejected Pioneer’s assertions for two reasons.

  • The “net amount received by Lessee for the sale” sets how the payment is computed (proceeds, net of post-production costs) and says nothing about who must make the sale. The same clause deducts post-production costs “incurred by Lessee,” yet Pioneer never personally incurred those costs; Henry did. Pioneer offered no reason “received by Lessee” should be more personal than “incurred by Lessee.”
  • A royalty is an interest beginning with first production, free of the costs of production. Under Pioneer’s reading, Elberta would collect nothing on the Pearl wells until the wells reached payout. That describes a payout interest, not the interest this lease creates in favor of the lessor.

Pioneer then fell back on practicality. Requiring a nonoperating lessee to front royalty it cannot calculate is absurd. Pioneer’s own conduct told the Court otherwise. In January 2021 Pioneer asked Henry’s division order supervisor for production data and decimal interests for the royalties it acknowledged would be owed. According to the record the calculation was not difficult, much less impossible.

The statute governs

Section 91.402(a) is triggered by the sale of production, not the payor’s receipt of proceeds. The statute draws no distinction between sale by a lessee and sales by a cotenant operator. The parties cited no prior case applying the statute to a nonoperating lessee for royalty on a cotenant’s production, and the absence of precedent did not help Pioneer. Its first payment in January 2023 came well past a deadline measured from the first sale in January 2021.

A word about attorney’s fees

Elberta was awarded damages of $17,000+. The jury awarded, and the appellate court upheld, almost $340,000 in attorney’s fees through trial. Wow! It can happen.

Your musical interlude

Co-author David Pruitt

Shorter et al. v. Coffield Family Properties, LTD. is a Texas double-fraction royalty dispute with a variation arising out of language that seems different enough from deeds previously adjudicated to be worth fighting over.

The reservation was,

  • “as a royalty interest an undivided one-half of the usual and customary one-eighth (1/8) royalty on all oil, gas and other minerals”.

… and was clarified in the document to say,

  • “the sole and only right of the grantors herein being to receive one-sixteenth (1/16) of all oil and gas and other minerals produced from said lands as a royalty interest.”

The facts

The conveyance was in a 1944 deed in which the Skeens conveyed 640 acres in Borden County to Wolf. The Coffields, successors to the grantors, sued the Wolfs, successors to the grantee, seeking a judgment declaring that the reserved interest was a floating one-half royalty rather than a fixed 1/16. On cross-motions for summary judgment the trial court agreed with the Coffields.

The question and the answer

The question for the Eastland Court of Appeals: Did the deed reserving a double fraction (“one-half of the usual and customary one-eighth”) followed by a later clause expressing a single fraction (“1/16”) reserve a floating or a fixed royalty interest? The Court concluded that the grantor kept a floating 1/2 of whatever the lease royalty would turn out to be.

The presumption was not rebutted

Under the Van Dyke presumption, when a deed contains a double fraction (x/x of 1/8), a court begins with the presumption that 1/8 reflects the entire mineral estate – meaning the reservation creates a floating royalty interest. The presumption is “readily and genuinely rebuttable” by express language showing a specific intent to reserve a fixed interest; that is, distinct provisions that cannot be harmonized if 1/8 is given its term-of-art usage, or the repeated use of fractions other than 1/8 in ways showing the parties intended that the provisions are only arithmetic.

The holding

According to the Court, “one-half of the usual and customary one-eighth (1/8) royalty” triggered the Van Dyke presumption and reserved a floating one-half royalty interest. The later “sole and only right … to receive one-sixteenth” did not rebut the presumption. The court explained that under prior Texas decisions a single-fraction clause following a double fraction is merely explanatory – illustrating what the floating interest would yield under a standard 1/8 lease, and does not override the primary reservation clause.

The court distinguished Clifton v. Johnson, where the presumption was rebutted because the single fraction appeared first in the granting clause and was then followed by a parenthetical “showing its work.” Here, the structure was inverted: the double fraction came first, and the single fraction appeared only later in a future-lease clause.

No presumed grant

The Court noted the Wolfs’ failure to complain as to the trial court’s implicit findings with regard to presumed grant supported affirmation of the trial court’s judgment. The Court also found that any evidentiary errors regarding a stipulation and a landman’s affidavit were harmless because disposition turned entirely on unambiguous deed language.

Takeaway

The trial court judgment was affirmed. The 1944 deed reserved a floating 1/2 royalty interest. If your old deed says, “one-half of the usual 1/8” and later says “1/16,” you are probably looking at a floating interest unless the text clearly shows the parties were just doing arithmetic … or another appellate court sees it differently.

Dolly, RIP. an early hit … one of her 3000 originals … harmonies with her friends.

Co-author: David Pruitt

Can a consulting agreement convey overriding royalty interests without naming the leases? The Bankruptcy court for the Southern District of Texas tackled that question in In re Barrow Shaver Resources Company, LLC. In summary, the answer is “maybe” … “sometimes” … “it depends on the proof”.

The facts

Independent operator Barrow Shaver hired geologists Kasino and Turner under identical consulting agreements in 2019. In exchange for the geologists identifying and evaluating prospects in the Hidden Rock Field in East Texas, Barrow Shaver agreed to “set aside” for each consultant an override not to exceed 1% of 8/8ths out of the ORRI Barrow Shaver retained in the property, “provided that, the lease burdens and deal terms allow.” Record title was to remain in Barrow Shaver so long as it operated the property.

For several years Barrow Shaver paid production revenues attributable to the overrides. Then came an involuntary Chapter 7 petition against Barrow Shaver in 2024 and the payments stopped. The consultants sued for a judgment declaring their ownership; Barrow Shaver counterclaimed, denying that a valid conveyance occurred.  

Statute of frauds – the property description fails

The Consulting Agreement was legally deficient on its face and could not satisfy the statute of frauds. It referenced only undefined “oil and gas properties” and “Prospects” without identifying any lease from which the overrides derive. Under longstanding Texas property law, the writing itself must furnish the means to identify the property with reasonable certainty. Extrinsic documents such as division orders, division-of-interest listings, and line ledgers cannot supply the essential elements the statute of frauds demands in the operative instrument. Summary judgment on this issue went to Barrow Shaver.

The Court reserved judgment on whether overrides supported by tax records might fall within the partial-performance exception to the statute of frauds and ordered further briefing.

Statute of conveyances – present intent

The consultants prevailed on this issue. The agreements satisfied the statute of conveyances. The phrase “set aside” evidenced a present intent to convey overrides earned both before and after execution of the agreements. The Court found the language was ambiguous enough to admit extrinsic evidence, such as division orders and pay decks reflecting override payments. These documents confirmed that conveyances did occur.

The conditional phrase “provided that … deal terms allow” did not defeat the conveyance: any override generating revenues necessarily had room under the NRI, and Barrow Shaver never executed a financing arrangement that would have extinguished that “room”. The Court declined to read the contract as illusory.

Legal title vs. equitable interest

Because Barrow Shaver retained record title under the agreements while purporting to convey overrides, the Court concluded that Barrow Shaver was left with bare legal title and the consultants with an equitable interest. This included the right to receive royalty payments, to acquire legal title upon sale, and to assign the interest. Under Bankruptcy Code §541(d), that equitable interest was excluded from Barrow Shaver’s estate.

Bankruptcy issues?

There were plenty: §§ 541(a), 544(a), 548(a)(1)(B), 550(a); which we have for the most part ignored. You lawyers and advisors who ply your trade in that environment are encouraged to navigate the decision on your own.

Takeaway

An agreement that “sets aside” an override can manifest the present intent to convey real property, but intent alone is not enough. If the instrument fails to identify the underlying leases, or even point to another writing that does, the statute of frauds will block the conveyance regardless of how many checks the operator cut.

The assignees are not out of the woods yet, but for now they are protected by the statute of conveyances and extrinsic evidence. Their challenge: Under Texas law, a valid conveyance of an interest in land must satisfy both the statute of frauds and the statute of conveyances.

Your musical interludes. Hank doing Hank. Esther Phillips: another way to do Hank.

Co-author: David Pruitt

Gringita, Ltd v. Ineos USA Oil and Gas, LLC et al is in a way a typical Texas royalty dispute in which the lessor’s royalty is “free of post-production costs” (PPCs) according to one provision of the lease, but maybe isn’t so free if one considers another provision.

The facts

Gringita owns 1,015+ acres in Dimmit County and signed a mineral lease providing for a 25% royalty. Original lessee Chesapeake assigned the lease to Ineos. Gringita alleged that Defendants were deducting PPCs from its royalty payments in violation of the lease’s terms.

The royalty clause

Here are the significant subsections:

3.A: Gringita’s “Royalty Share” was measured by “all sums and amounts of money, including but not limited to any reimbursement for [PPCs], bonuses, premiums, and all other benefits in cash, kind or otherwise, derived, received or realized by, or to inure to the benefit of, Lessee, directly or indirectly.”

3.C and 3.E: The definition of “Gross Proceeds” required that if any sales contract provided for deduction for PPCs, “such deduction shall be added to the price received by Lessee … so that Lessor’s Royalty Share shall not be charged directly or indirectly with any such expenses.”

3.I, first sentence: “[t]he royalties provided herein shall be determined and delivered to Lessor free of any development, production, post-production, gathering … transportation, manufacturing, processing, treating … marketing … or like costs, except as specifically provided for in this Lease.”

3.I, second sentence: addressed costs for “construction, operation or depreciation of any plants or other facilities or equipment for processing or treating” minerals,

3.I, third sentence: “Notwithstanding anything to the contrary, any such costs which result in enhancing the value of the marketable oil, gas or other products to receive a better price may be deducted from Lessor’s share of production so long as they are based on Lessee’s actual cost of such enhancements.”

The lease is long and complex. This summary is not the entire clause.

Lessee’s gambit

Defendants argued that “such costs” in the third sentence of 3.I referred to all costs in Section 3.I, effectively converting the royalty into a modified net-proceeds interest subject to dedduction of most PPCs.

The Court decides

Gringita’s reading was the better of the dueling interpretations. “Such costs” in 3.I referred to the immediately preceding sentence, not to the entire litany of costs listed earlier. Under Defendants’ reading one sentence would undo everything the lease otherwise accomplished, rendering the “Royalty – Free of Cost” heading and the surrounding provisions meaningless. A court construes contractual provisions to harmonize them, not render them useless.

Horror of horrors for the lessees. The Court also held that the lease required Defendants to add back any PPC deductions to the royalty base before calculating Gringita’s share (see Devon v. Sheppard and the “proceeds plus” lease model). This wording means that the lessor could be paid more for its share of proceeds than the lessees received for their share.

Takeaway

Gringita’s motion for summary judgment was granted in part, and Defendants’ cross-motion was denied. A royalty clause that is based on the price actually received by the lessee, buttressed by “free of cost” language and add-back provisions, means what it says. One sentence, even beginning with “notwithstanding”, will not be read to swallow the rest of the agreement rendering it meaningless.

Caveat

We said that “in a way” Gringita is a typical PPC dispute. But we’ve warned that highly- negotiated royalty clauses are not “standard”. It is best to consider the principles underlying the result in one decision rather than expecting the language in that decision to match the language in another.

Your musical interlude.

In Ankor Energy, LLC et al v. Merit Management Partners I, L.P. et al a Louisiana federal district court addressed a situation commonly encountered by assignors of oil and gas operating interests: You’ve given up the cheese. How do you get out of the JOA trap?

The facts

The Ankor parties sued the Merit parties to recover unpaid lease operating expenses incurred while Ankor served as operator of two federal offshore oil and gas leases The motions addressed whether a separate claim for day-to-day operating expenses was properly before the Court and whether Merit owed those expenses.

The facts

In 2002 Merit acquired record title and rights in two Joint Operating Agreements in two federal Outer Continental Shelf oil and gas leases (South Pelto 8 and South Pelto 13) located off the coast of Louisiana. Merit assigned those interests to Black Elk effective in 2011.

Ankor acquired interests in the leases and became the operator in 2012. The leases terminated in 2018. During its time as operator Ankor incurred day-to-day lease operating expenses totaling $1,493,418.29. Merit refused to pay. 

Because the South Pelto leases are located on the Outer Continental Shelf off Louisiana’s coast, the Court applied the Outer Continental Shelf Lands Act. Under OCSLA, the law of the adjacent state – Louisiana – applied as surrogate federal law. The Court therefore analyzed the parties’ obligations under Louisiana contract law and the two Joint Operating Agreements. 

Merit’s procedural defense

The Court’s first order of business was to determine whether Ankor properly pleaded a claim for operating costs. The Court had already ruled in Ankor’s favor on its claim for decommissioning expenses. Repeated references in the complaint to expenses to “operate and decommission” the leases, read liberally as required by the Federal Rules of Civil Procedure, encompassed both types of expenses. The prior summary judgment order addressed only decommissioning costs; the operating expenses claim was still alive.

The substantive issue

The question before the Court was Merit’s obligation – or not – to pay the operating expenses. Merit argued that it was released from ongoing obligations under the Operating Agreements by virtue of the 2011 assignment of its working interests to Black Elk.  Merit was not released, said the Court. Under Louisiana law, a mere assignment of an interest is not sufficient to release an assignor from obligations owed to a third party without the obligee’s (Ankor’s) express consent. The unreleased obligor remains solidarily liable with the assignee. The Court found no express release language in the relevant provisions of the Operating Agreements (Articles IV, V and XXVI). The Court found express release language in a different context (relating to well-specific assignments), so the parties knew how to effectuate a release if they had intended to.

Damages: No double recovery

The Court rejected Merit’s contention that because Ankor had recouped the operating expenses from other non-operators, it suffered no actual damages. The Operating Agreements expressly permitted the operator to look to other non-operators to cover a delinquent non-operator’s portion and also required the operator to redistribute any recovered funds to the contributing non-operators. There would be no double recovery. Ankor was abiding by the mechanism established in the Operating Agreements and would be required to distribute Merit’s payment to the non-operators who had previously paid Merit’s share. 

Other defenses

Alleged “industry practice” not to charge non-operators after assignment of their interests did not abrogate Louisiana law. An affirmative defense of waiver (by sending certain invoices for decommissioning but not operating costs) also failed.

The Court granted plaintiffs’ partial summary judgment and denied defendants’ cross-motion. Merit was solidarily liable for $1,493,418.29 in unpaid lease operating expenses. 

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