In a victory for gas producers over royalty owners, on March 1, 2019, the Texas Supreme Court issued its opinion in a significant royalty case, Burlington Resources Oil & Gas Company LP v. Texas Crude Energy, LLC (No. 17-0266). The case concerned gas royalty payments by Burlington to owners of overriding royalty interests (ORRIs). At issue was whether Burlington could deduct post-production costs from downstream, off-lease sales proceeds when calculating the ORRI payments. The Supreme Court held that Burlington could deduct post-production costs, despite a royalty clause requiring royalty payments based on the “amount realized” from gas sales, because other language fixed the royalty valuation point at or near the wellhead.
Burlington involved royalty payments by Burlington, the producer, to Texas Crude and Amber Harvest, owners of ORRI’s in producing properties. The ORRIs in Burlington were set forth in assignments to Texas Crude and Amber Harvest. The assignments provided generally that “[s]aid overriding royalty interests shall be delivered to ASSIGNEE into the pipelines, tanks or other receptacles with which the wells may be connected, free and clear of all development, operating, production and other costs.” The assignments also contained a valuation clause providing that “[t]he overriding royalty interest share of production shall be delivered to ASSIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected, free and clear of all royalties and all other burdens and all costs and expenses except the taxes thereon or attributable thereto.” The valuation clause also provided, in the disjunctive, that the assignee could elect to take royalty in cash, in which event Burlington was obligated to pay royalty based on (i) “amount realized from such sale” in the event of an arm’s-length sale on or off the lease, or, in the event of a non-arm’s-length sale, (ii) the “market value at the wells.”
In Burlington, the royalties had been paid in cash and the production sold at arm’s length. Thus, the “amount realized” valuation standard governed. Texas Crude argued, and the court of appeals agreed, that the “amount realized” language created a royalty free of post-production costs, per Chesapeake Exploration, L.L.C. v. Hyder, 483 S.W.3d 870 (Tex. 2016). The Supreme Court disagreed. The Court ruled that while the “amount realized” language “provides considerable support” for Texas Crude’s position if “[v]iewed in isolation,” the contract language as a whole supported Burlington’s position that the royalty bears post-production costs.
The Court considered as significant the “into the pipelines” language that twice appears in the royalty assignments. The Court found that a “sensible reading of this rather abstruse provision is that the ‘pipelines, tanks, or other receptacles’ are the physical spot at which Texas Crude’s interest in the product arises,” and thus the place where the royalty is to be valued. In addition, the Court was persuaded that “the pipelines … to which … wells … may be connected” referred to a location “at or near the wellhead.” Putting these two concepts together yielded a royalty valuation point at or near the wellhead, which meant that Burlington could deduct post-production costs from downstream sales prices when calculating royalties.
Importantly, the Court rejected Texas Crude’s argument that the “into the pipelines” language referred only to in-kind transfers. This argument had some appeal given the fact the assignments referred to the royalty “share of production” being “delivered” into the pipelines, language that suggests a physical delivery of product. Nonetheless, the Court believed that if the parties had “intended to create one set of rules for in-kind royalties and another for in-cash royalties,” then they would have used more express language. The Court further noted the “odd” and “implausible” results that would occur if it construed the “into the pipelines” language to apply only to in-kind transfers. For example, if this language covered only in-kind transfers, then “an in-kind transfer would give Texas Crude its royalty percentage of production at the well,” whereas “an arms-length sale off the lease would give Texas Crude a higher royalty based on the downstream price after post-production enhancements.” The Court remarked of this example: “Under this construction, Burlington would be penalized for marketing Texas Crude’s share of production, finding a third-party buyer, transporting the product, and performing other post-production enhancements. It is difficult to fathom why either party would have intended such a result.”
While the Burlington opinion does not overrule or even criticize Hyder, the opinion does, as a practical matter, limit it. Notably, when confronted with the possibility that construing the royalty at issue as cost-free could lead to a result in which the royalty owner got a far better deal simply by electing to take the royalty in cash rather than in kind, the Hyder Court had a strikingly different reaction than did the Burlington Court: “The fact that the Hyders might or might not be subject to post-production costs by taking the gas in kind [on the lease property] does not suggest that they must be subject to those costs when the royalty is paid in cash [based on sales in distant markets]. The choice of how to take their royalty, and the consequences, are left to the Hyders.” 483 S.W.3d at 875. Thus, Hyder seemed to endorse the view that the royalty valuation point (for in-cash royalties) does not by default coincide with the royalty delivery point (for in-kind royalties). Burlington now seems to embrace the opposite view.
Thus, Burlington is a favorable decision for producers. It holds that “amount realized” language does not necessarily establish a royalty free of post-production costs if there is other language in the royalty clause – even language that might appear to address in-kind royalties – indicating that the royalty owner’s interest is in the product at or near the well. “We have never held that an ‘amount realized’ valuation method frees a royalty holder from its usual obligation to share post-production costs even when the parties have agreed to value the royalty interest at the well.”
Burlington extends the holding in Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). At issue in Heritage were royalty provisions specifically prohibiting “deductions from the value of Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.” Justice Owen’s opinion, which became the plurality opinion for the Court, held that despite the foregoing language, the producer could properly deduct post-production costs from downstream sales proceeds to calculate royalties that were to be based on the market value at the well. As Justice Owen observed, deducting these costs from downstream sales proceeds to determine market value at the well was not equivalent to deducting the costs from “the value of the Lessor’s royalty” when such royalty was based on market value at the well. Burlington follows and expands the Heritage Resources holding.
Burlington now provides a basis for producers to deduct post-production costs for “amounts realized” leases just as Heritage Resources allowed such deductions for “market value at the well” leases. But Burlington would seem to require some other language in the lease or assignment that fixes a royalty valuation point at or near the wellhead before such cost deductions are allowed for “amounts realized” leases.