Texas Court Holds Nonoperating Lessee Owes Royalty on Co-Tenant’s Wells Before It Sees a Dime — Plus Attorney’s Fees for Lateness

In a case that might soon be the darling of the oil and gas plaintiffs’ bar, on August 19, 2026, in Pioneer Natural Resources USA, Inc. v. Elberta M. Royalty, LLC, No. 08-24-00133-CV,¹ the Eighth Court of Appeals in El Paso held that a nonoperator upstream lessee owes royalty on production taken by a co-tenant from the leased premises beginning at first production, not when such lessee is personally paid its share of the proceeds. The court further held that the 120-day payment deadline in Chapter 91 of the Texas Natural Resources Code runs from the end of the month of first sale of production, not from the payor’s receipt of money.

Upstream exploration and production (E&Ps) that are co-tenants with other working interest owners will want to pay attention. Based on this court’s interpretation, nonoperators in a co-tenancy not governed by a joint operating agreement or co-tenancy agreement may find themselves required to (1) pay their lessor’s royalties (2) on production volumes (3) from the other co-tenant’s wells, (4) with respect to which the nonoperator may not have adequate records or information, (5) before receiving a dime from the co-tenant and (6) potentially be subject to one-way fee shifting under Chapter 91 if they miss the statutory deadline. Additionally, the Elberta trial court dismissed the operating co-tenant outright, leaving the royalty owner’s lessee holding the bag without the operator.

The stipulated damages for accrued interest were less than $18,000. But because of statutory fee shifting under Chapter 91, Pioneer was saddled with the plaintiff’s attorney’s fees in excess of $300,000 through trial (19x actual damages) plus up to an additional $200,000 in conditional appellate fees (cumulatively, 30x actual damages). Incentives drive behavior, and potential attorney’s fees of 30x damages will certainly draw the attention of the plaintiffs’ bar.

The court was explicit that the result is a default rule the parties may contract around. Operators and nonoperators with split-ownership acreage should review their lease forms, joint operating agreements, and co-tenancy arrangements, including the royalty language at issue in a nonoperator co-tenancy situation and related information rights. Acquirors and financing
parties should also consider reviewing their diligence procedures to ensure they are not taking on unknown liabilities related to these types of claims. Where no revenues have been received from a co-tenant, an ordinary course review of suspense funds accounting will not surface this issue. Finally, Elberta reminds nonoperators of the need to take demand notices seriously and that ticking interest may, in itself, be enough to give rise to the kind of Chapter 91 fee shifting that draws the plaintiffs’ bar to the oil patch.

Background

Pioneer was lessee under an oil and gas lease reserving to the lessor a 22.5% royalty on the “net amount received by Lessee for the sale” of oil and gas. Pioneer operated and timely paid royalty on its own vertical wells. Henry Resources, LLC, a co-tenant holding a separate lease from another co-owner of the split mineral estate, drilled its own horizontal wells on some of the lands covered by Pioneer’s lease. Importantly, at the time in question, Pioneer and Henry were not party to a joint operating agreement with respect to the covered lands. And because Henry took its separate lease from other mineral owners, Henry did not have contractual privity with the lessor that was party to Pioneer’s lease.

Henry invited Pioneer to join in drilling the horizontal wells on the lands covered by the two leases. Pioneer declined to participate. The Henry wells first produced in January 2021. As is typical in a nonconsenting co-tenancy situation where there is no joint operating or similar agreement, Henry incurred the costs associated with the wells, made the sales, and did not begin remitting Pioneer’s share of revenues from the wells until November 2022.

Elberta, the successor-in-interest to the lessor party to the Pioneer lease, sent statutory notices of nonpayment to Pioneer in January 2022 and later to Henry, before any of the Henry wells had reached payout. Pioneer neither paid nor responded within 30 days. Henry responded that it had no payor-payee relationship with Elberta. Henry eventually made its first payment to Pioneer on the Henry wells in November 2022. Pioneer in turn made its first royalty payment to Elberta on production from the Henry wells in January 2023. The payment covered production back to first production and was delivered within 60 days of Pioneer’s receipt of funds from Henry but was delivered nearly a year after the Elberta notice.

The trial court dismissed Henry, granted the lessor partial summary judgment on liability, and tried attorney’s fees to a jury. The court of appeals affirmed in all respects.

The Holdings

1. “Received by Lessee” measures the royalty; it does not condition it.

Pioneer argued that the lease’s royalty provision requiring the lessee to pay based on the “net amount received by Lessee” meant that Pioneer was obligated to pay the royalty only when Pioneer had personally received production proceeds from Henry. The court, however, read “received by Lessee” as defining the basis on which the royalty was to be paid (i.e., that the lease was a net proceeds lease, with royalty due on sales proceeds, net of postproduction costs) rather than as a condition precedent to payment. The royalty clause was written in the passive voice and never identified who was obliged to produce, so “by Lessee” described the acts of whoever produced and sold the oil and gas, not a limitation to instances where Pioneer was operator.

The court’s most pointed observation was one of symmetry. The same clause described postproduction costs “incurred by Lessee,” and Pioneer did not claim to have personally incurred any of those postproduction costs; it contended instead that Henry had incurred all costs and received all sales proceeds. Because “incurred by Lessee” necessarily referred to costs incurred by someone other than Pioneer, the court saw no reason to read the parallel phrase “received by Lessee” any more personally, and it held that the term “by Lessee” referred to the acts of whoever produces and sells the oil and gas.

The court added that Pioneer’s proposed interpretation would leave the lessor with nothing until the costs of production were recouped — contrary to the settled character of royalty as an interest in first production, free of production costs.

2. The Chapter 91 clock is triggered by the sale, not by receipt.

Section 91.402(a) requires that payment of “proceeds derived from the sale of oil or gas production” be made “by payor on or before 120 days after the end of the month of first sale of production.” The lessee is the “payor” under Section 91.401(2), and the royalty owner is a “payee” as a person legally entitled to payment from the sale proceeds. Relying on Texas Supreme Court precedent, the court read “payor” broadly, consistent with the statute’s purpose of protecting royalty owners from payments delayed without legitimate reason, and held that the 120-day deadline applied to Pioneer’s royalty on the Henry wells beginning with first production, not receipt of funds by Pioneer from the operator co-tenant.

3. The operating co-tenant was dismissed, leaving the nonoperator on the hook as “payor.”

The trial court dismissed Henry on summary judgment on the ground that it had no contractual or statutory payor-payee relationship with Elberta, and that ruling was not appealed. The practical result in Elberta was that the royalty owner looked to its own lessee, not to the co-tenant that happened to drill the well for payment.

Key Takeaways

Although the decision remains subject to potential review by the Texas Supreme Court, Elberta is a shot across the bow. E&Ps should consider how to reduce their potential exposure — and attractiveness as a target for the plaintiffs’ bar — in light of the case. A few key areas for review:

• Co-tenant nonoperators with split-ownership acreage potentially carry an obligation with no matching revenue. If a co-tenant is producing from your leased premises, your royalty obligation and the statutory clock may already have started. Because there is no revenue receipt and often no accounting entry, this exposure will not surface in ordinary suspense-account review.
• Mineral lease forms can fix this prospectively. The court emphasized that oil and gas lessors and lessees remain free to contract for a different rule. In the court’s words, “A lease may expressly defer royalty on a cotenant’s production until payout or condition payment on the lessee’s receipt of proceeds” (not the co-tenant operator’s receipt). By its own terms, Section 91.402(a) applies only absent contrary lease language.
• Co-tenant data rights should be contractual, not collegial. In any co-tenancy situation, it is important to paper the relationship, responsibilities, and obligations of the parties. Where the relationship is left to common law and statute, the parties’ risks are potentially multiplied, as shown by Elberta. Among other things that should be addressed in a joint operating agreement or co-tenancy agreement, parties should secure contractual information rights, including with respect to volumes, sales proceeds, allocation decimals, and payout statements on a fixed schedule and from first sales.
• Acquisition diligence should be adjusted. Buyers of split-ownership positions should ask specifically whether the target pays royalty on nonoperated co-tenant production from first production or from payout and should review the lease bank for receipt-linked royalty language and for unanswered notices of nonpayment.

Open Questions

This is a memorandum opinion, and the court noted that the parties had not identified any prior case applying the statute or the common law to a nonoperating lessee for nonpayment of royalty on a co-tenant’s production. It noted a sister court’s dicta pointing in the same direction, alongside decisions reaching differing conclusions on whether an operating co-tenant is a “payor.” [The deadline for a petition for review has not run.]²

The opinion also does not address structures that present the same revenue-timing mismatch — joint operating agreement nonconsent and penalty recoupment periods, carried interests, farmouts, and back-in-after-payout arrangements. Whether the reasoning extends to them is unresolved. We think the question is worth asking now rather than after a demand letter arrives.

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¹Tex. App.—El Paso Aug. 19, 2026, no pet. h. (mem. op.).
²Note to Draft:  Timing check: judgment issued August 19, 2026. Under Tex. R. App. P. 49.1 a motion for rehearing is due 15 days after judgment — i.e., September 3, 2026 (today), before the proposed September 8 publication date — although an extension is available under Rule 49.8. The petition-for-review deadline (45 days, Rule 53.7(a)) would fall in early October 2026, or 45 days after disposition of any timely rehearing motion. Revised so the sentence remains accurate on the publication date. Please (i) confirm the 15/45-day periods against the current rules and (ii) check the docket on the day of publication, since a rehearing motion may have been filed, and update the 'no pet. h.' history in the citation if needed.