City of Crowley, Texas v. TotalEnergies E&P USA, Inc., TotalEnergies E&P Barnett USA, LLC, TotalEnergies E&P USA Barnett 1, LLC, and TotalEnergies E&P USA Barnett 2, LLC

In the Court of Appeals Second Appellate District of Texas at Fort Worth ___________________________ No. 02-24-00088-CV ___________________________

CITY OF CROWLEY, TEXAS, Appellant

V.

TOTALENERGIES E&P USA, INC.; TOTALENERGIES E&P BARNETT USA, LLC; TOTALENERGIES E&P USA BARNETT 1, LLC; AND TOTALENERGIES E&P USA BARNETT 2, LLC; Appellees

On Appeal from the 96th District Court Tarrant County, Texas Trial Court No. 096-000003-15

Before Kerr, Birdwell, and Walker, JJ. Memorandum Opinion by Justice Birdwell

MEMORANDUM OPINION

This gas-royalty dispute turns on a single question of contract interpretation: Does the parties’ mineral lease (the Lease) require the relevant gas-royalty payment to be calculated based on the market value of the gas at the point of sale—here, the wellhead—or based on the combined sum of the wellhead market value plus post-sale postproduction costs?

Appellant City of Crowley, Texas (Lessor) advanced the latter interpretation, but Appellees TotalEnergies E&P USA, Inc.; TotalEnergies E&P Barnett USA, LLC; TotalEnergies E&P USA Barnett 1, LLC; and TotalEnergies E&P USA Barnett 2, LLC (Lessees)1 advanced the former, and all parties moved for summary judgment on the issue. Lessor argued that, because the wellhead sales price was tied to the third-party buyer’s post-sale postproduction costs and downstream proceeds, Lessees effectively “realize[d] proceeds of production after deduction for [postproduction] . . . expense[s]” within the meaning of the Lease, and thus, under the Lease’s terms, “the deductions [must] be added” to the gas’s wellhead market value for purposes of the royalty calculation. Lessees disagreed, pointing out that there were no postproduction expenses prior to the point of sale—the wellhead—so there was

1 TotalEnergies E&P USA Barnett 1, LLC and TotalEnergies E&P USA Barnett 2, LLC are the two current co-lessees. TotalEnergies E&P USA, Inc. is a former lessee; it conveyed its interest to TotalEnergies E&P Barnett 2, LLC in 2020. TotalEnergies E&P Barnett USA, LLC, meanwhile, is the lease operator. Nonetheless, all four entities’ fates rise and fall on the same legal argument, so for ease of reference, we refer to them collectively as Lessees.

nothing to “deduct[]” and no “deductions [to] be added” to the “realize[d] proceeds.” The trial court agreed with Lessees, and Lessor, in its sole appellate issue, seeks our review of the interpretive question.

This question is rendered significantly easier by the fact that we have answered it before in a substantially similar context. In Shirlaine, we interpreted nearly identical lease language, and we held that because the lease unambiguously “fixe[d] the wellhead as the valuation point” for the royalty, no royalty was due on post-sale postproduction costs—the lessee was not “realiz[ing] proceeds of production after deduction for [postproduction] . . . expenses.” Shirlaine W. Props. Ltd. v. Jamestown Res., L.L.C., No. 02-18-00424-CV, 2021 WL 5367849, at *1, *6 (Tex. App.—Fort Worth Nov. 18, 2021, pet. denied) (mem. op.). Although Lessor attempts to distinguish Shirlaine by arguing that a separate provision unique to the present Lease converts the wellhead-market-value royalty into a market-value-plus royalty, its attempts are unsuccessful; Shirlaine is on point, binding, and sound. Cf. Devon Energy Prod. Co. v. Sheppard, 668 S.W.3d 332, 348 (Tex. 2023) (interpreting leases and holding that the leases were “‘proceeds plus’ leases that employ[ed] a two-prong calculation of the royalty base”).

Because the trial court’s summary judgment aligns with Shirlaine, we will affirm.

I. Background

A royalty payment represents a lessor’s fractional share of mineral production from a lease. BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 386–87 (Tex. *4 2021). Generally, the amount of the royalty payment turns on how the production is valued—the valuation “yardstick[,] e.g., market value, proceeds, price” and “the location for measuring the yardstick[,] e.g., at the well, at the point of sale.’” Id. at 387. The valuation yardstick and location are often intertwined, and in the absence of an agreement to the contrary, these parameters often dictate whether the royalty is burdened by postproduction costs, i.e., the costs incurred to prepare the minerals for downstream sale. See id. at 386–90; see Burlington Res. Oil & Gas Co. v. Tex. Crude Energy, LLC, 573 S.W.3d 198, 203 (Tex. 2019) (clarifying that the term “postproduction costs” refers “to processing, compression, transportation, and other costs expended to prepare raw oil or gas for sale at a downstream location”).

If a royalty is based on gas’s market value at the wellhead, then the value is determined “before [the gas] is transported, treated, compressed or otherwise prepared for market.” Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 125, 129 (Tex. 1996) (Owen, J.) (plurality op. on reh’g);2 see BlueStone, 620 S.W.3d at 388–89. But even though postproduction occurs beyond the point of valuation, the wellhead royalty is considered to bear its share of postproduction costs because the market value at the wellhead can be—and frequently is—estimated by taking the downstream market price and subtracting the postproduction costs incurred between the wellhead and that point. See Carl v. Hilcorp Energy Co., 689 S.W.3d 894, 896 (Tex. 2024) (noting that

See BlueStone, 620 S.W.3d at 388 n.29 (explaining how Justice Owen’s 2

concurring opinion became the plurality opinion on rehearing and citing it as such). *5 “[o]ften, . . . minerals are not sold until after post-production” so “the workback method permits an estimation of wellhead market value by using the proceeds of a downstream sale and subtracting postproduction costs”); BlueStone, 620 S.W.3d at 388–89 (noting that “[w]hen comparable sales data is unavailable, . . . the ‘net-back’ or ‘workback’ method” provides “an estimation of wellhead market value”); Burlington, 573 S.W.3d at 206–07 (clarifying that “a wellhead valuation point . . . generally requires the royalty holder to bear post[]production costs”); Heritage, 939 S.W.2d at 130 (Owen, J.) (plurality op. on reh’g) (noting that market value “can be proven by the so-called net-back approach, which determines the prevailing market price at a given point and backs out the necessary, reasonable costs between that point and the wellhead”).

But if the valuation yardstick is gross proceeds, then “the valuation point is necessarily the point of sale because that is where the gross is realized or received.” BlueStone, 620 S.W.3d at 391. The relevant inquiry is the amount the lessee actually receives for the minerals, regardless of whether that amount is the market value. Id. at 389. And when the sale occurs at a point downstream from the wellhead—after at least some postproduction has occurred—then the gross-proceeds royalty is free from postproduction costs, meaning that the royalty holder “share[s] in the enhanced value of production but not the expenses incurred to make it so.” Sheppard, 668 S.W.3d at 336–37, 348 (noting that “gross proceeds . . . by definition must be free of postproduction costs”).

The valuation yardstick, the point of valuation, and the allocation of postproduction expenses are “frequently litigated issue[s].” BlueStone, 620 S.W.3d at 387; see Sheppard, 668 S.W.3d at 337 (describing such litigation as “common”); Shirlaine, 2021 WL 5367849, at *4 (describing case as “yet another episode in the endless struggle . . . between lessors and lessees in the allocation of post[]production costs”). Such disputes come down to the specific language used in the parties’ mineral lease. Cf. Sheppard, 668 S.W.3d at 348 (emphasizing that “different royalty provisions have different meanings,” that lease disputes “must ultimately be based predominantly on the particular clause at issue,” and that the court’s interpretation of a lease is limited to “the specific language of the provisions before [it]”).

II. The Lease and Dispute

Here, the parties’ Lease dedicates numerous paragraphs to the topic of royalties. Some paragraphs apply to all royalties, others to royalties paid on a subsection of minerals, and still others to specific situations, e.g., when gas is processed in a Lessee-affiliated facility. This appeal focuses on just four of the royalty provisions. A. Key Lease Provisions

The first key provision establishes the yardstick and point of valuation for Lessor’s royalty; it requires Lessees to pay, “[o]n gas produced from the Land and sold by Lessee or used on or off the Land . . . , the Royalty Fraction of the market value at the point of sale, use, or other disposition” (Valuation Provision). The Valuation *7 Provision goes on to clarify the parameters for valuation, stating that “[t]he market value of gas will be determined at the specified location by reference to the gross heating value (measured in British thermal units) and quality of the gas.” It is undisputed that this Valuation Provision governs the parties’ dispute and that, in this case, the “point of sale, use, or other disposition” is the wellhead.

But the Lease then makes three other royalty-related statements that the parties interpret differently.

First, the Lease discusses the market value for all royalties and how that market value relates to Lessee’s total proceeds (Total-Proceeds Provision):

The market value used in the calculation of oil and gas royalty will never be less than the total proceeds received by Lessee in connection with the sale, use, or other disposition [of] the oil or gas produced or sold.

Then, in the same paragraph, the Lease states that certain amounts may be added to the “total proceeds” just mentioned (Add-On Provision):

For purposes of this paragraph, if Lessee receives from a purchaser of oil or gas any reimbursement for . . . taxes, or if 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 received by Lessee.

And finally, later in the Lease, it provides another comment on postproduction costs (Postproduction Provision):

Lessor’s royalty will never bear, either directly or indirectly, any part of the costs or expenses of [postproduction] . . . or any part of the costs of construction, operation, or depreciation of any plant or other facilities or equipment used in the handling of oil or gas.

B. Dispute and Litigation

According to Lessor, the Total-Proceeds, Add-On, and Postproduction Provisions require Lessees to calculate Lessor’s royalty payment based on not just the gas’s wellhead market value but on the wellhead market value plus post-sale postproduction costs that are taken into account in calculating that market value. Lessor reasons that, although Lessees sell the gas at the wellhead before postproduction occurs, the wellhead sales price is determined by taking the buyer’s downstream resale price and adjusting it to account for the buyer’s postproduction costs. Therefore, according to Lessor, “Lessee[s are] realiz[ing] proceeds of production after [the third-party buyer’s effective] deduction for an[] expense of [postproduction],” so “the deductions [must] be added to the total proceeds received by Lessee[s].”

Lessees do not share this interpretation of the Lease; they understand the royalty payment to be based on the market value at the point of sale—period. Because Lessees do not incur any postproduction costs prior to the sale at the wellhead, they assert that they do not “realize[] proceeds of production after deduction for an[] expense of [postproduction],” and they consider the Total-Proceeds, Add-On, and Postproduction Provisions inapplicable.

When Lessees made royalty payments based on their interpretation of the Lease, Lessor sued for breach of contract, arguing that Lessees were underpaying. On *9 cross-motions for summary judgment,3 the parties presented their competing interpretations of the Lease, and the trial court agreed with Lessees. The court granted traditional summary judgment in Lessees’ favor and dismissed Lessor’s breach of contract claim.4

III. Standard of Review

A mineral lease is, at its core, a contract, and as with any contract, its interpretation is a question of law we consider de novo. BlueStone, 620 S.W.3d at 387; see Sheppard, 668 S.W.3d at 343. The plain language of the contract controls, and we aim to effectuate the intentions of the parties as expressed in the document. Burlington, 573 S.W.3d at 202–03. We construe the contract as a whole, give the language its ordinary meaning, and presume that the parties did not intend for any provision to be meaningless. See Sheppard, 668 S.W.3d at 343; BlueStone, 620 S.W.3d at 387; Burlington, 573 S.W.3d at 203; Shirlaine, 2021 WL 5367849, at *3–4.

When, as here, the trial court’s contract interpretation resolves the parties’ cross-motions for summary judgment on a given element or claim, each party bears the burden of proving its entitlement to judgment. See Sheppard, 668 S.W.3d at 342–43;

3 Lessor sought only partial summary judgment, requesting resolution “as to liability on its breach of contract claim against [Lessees].” 4 The trial court also granted summary judgment for Lessees on Lessor’s claim under the Texas Natural Resources Code. Lessor does not challenge that portion of the judgment.

Maverick Nat. Res., LLC v. Glenn D. Cooper Oil & Gas, Inc., No. 02-23-00183-CV, 2024 WL 2970845, at *2 (Tex. App.—Fort Worth June 13, 2024, no pet.) (mem. op.).

IV. Analysis

The dispositive Lease provisions and interpretive dispute are strikingly similar to those in Shirlaine. 5 See generally Shirlaine, 2021 WL 5367849, at *1–7. A. Shirlaine is on point.

In Shirlaine, the lease provided for a royalty payment based on the gas’s “market value at the point of sale, use[,] or other disposition”—language nearly identical to that in the Valuation Provision here. 6 Id. at *1, *5–6 (emphasis removed). The Shirlaine lease’s version of the Valuation Provision also included the parameters outlined in the Lease, stating that “[t]he market value of all gas shall be determined at the specified location and by reference to the gross heating value (measured in British thermal units) and quality of the gas.” 7 Id. (emphasis removed).

Furthermore, the Shirlaine lease had Total-Proceeds and Add-On Provisions like those in the present Lease. Shirlaine’s analogue to the Total-Proceeds Provision stated that “[t]he market value used in the calculation of all royalty . . . shall never be

5 Shirlaine and this case stem from the same multi-district litigation. 6 The quoted phrase differs from the Valuation Provision only in its omission of a serial comma. See Shirlaine, 2021 WL 5367849, at *1, *5–6. 7 The present Lease states that “[t]he market value of gas [in Shirlaine, “all gas”] will [in Shirlaine, “shall”] be determined at the specified location by [in Shirlaine, “and by”] reference to the gross heating value (measured in British thermal units) and quality of the gas.” Id. at *1, *5–6 (emphasis removed).

less than the total proceeds received by Lessee,” differing from the present Lease only in its use of “shall” rather than “will.” Id. at *1, *6. As for the Add-On Provision, the Shirlaine lease provided that “[i]f Lessee realizes proceeds of production after deduction for any [postproduction] expenses . . . then the proportionate part of such deductions shall be added to the total proceeds received by Lessee.” Id. Again, such language resembles that before us here, with only immaterial differences such as the Shirlaine lease’s reference to “proportionate” expenses and its use of “shall” over “will.”8 See id. Overall, the key Lease provisions—the Valuation, Total-Proceeds, and Add-On Provisions—are substantially similar to those in Shirlaine.

Additionally, Shirlaine’s factual setup was similar to the parties’ circumstances here. In Shirlaine, as here, the “point of sale” was at the wellhead, and the wellhead sales price was calculated based on the third-party buyer’s post-sale postproduction costs and downstream sales price. Id. at *2.

Even the “central dispute” in Shirlaine was the same as the central dispute here. Id. at *6–7. There, the parties’ dispute revolved around the comparable Total-Proceeds and Add-On Provisions, and the lessor argued that, by “selling the gas to [the buyers] with postproduction costs deducted from the purchase price”—meaning, by subtracting the buyer’s postproduction costs from the downstream resale price to

8 The relevant portion of the Add-On Provision in the present Lease states that, “if 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 received by Lessee.”

calculate the wellhead sales price—“Lessees realize[d] proceeds after deduction for expenses identified in [the Add-On Provision], and Lessors [we]re therefore entitled to have these expenses added back into the ‘total proceeds’ to be used for calculating royalties.” Id. at *7. Lessor makes the same argument here.

But we rejected that interpretation in Shirlaine. Id. at *6–7. We explained that the Valuation Provision was what “set the direction for the ultimate outcome of the dispute” and that it “fix[ed] market value as the measure of value and set the location of the value at the point of sale.” Id. at *5–6. Such point of sale was—as here—“at the wellhead,” and “[r]oyalties that are calculated based on market value at the wellhead generally burden the lessor’s royalty with a proportionate share of postproduction costs.” Id. at *4–6. This “burden[ing],” we reasoned, was part of what distinguished a wellhead-market-value lease from a gross-proceeds lease. See id. at *5–7. We noted that, if we had adopted the lessor’s interpretation and construed Shirlaine’s Add-On Provision to require a royalty on post-sale postproduction costs, then we would have “convert[ed] a market-value-at-the-well lease into a ‘total proceeds’ lease, which [wa]s not consistent with precedent.” Id. at *7.

Shirlaine thus interpreted lease language substantially similar to the disputed Lease language here, it addressed factual circumstances substantially similar to those here, it resolved an interpretive question substantially similar to the one raised here, and it rejected an argument substantially similar to the one presented by Lessor here. Id. at *1, *5–7. The case is on point. Cf. Sheppard, 668 S.W.3d at 346 (“To assure *13 ‘continuity and predictability’ in oil-and-gas law, it is incumbent on the courts to construe commonly used terms in a uniform and predictable way.” (footnote omitted)); Heritage, 939 S.W.2d at 129–30 (Owen, J.) (plurality op. on reh’g) (“In construing language commonly used in oil and gas leases, we must keep in mind that there is a need for predictability and uniformity as to what the language used means.”). B. Shirlaine is not distinguishable, nor is Sheppard controlling.

Lessor attempts to distinguish Shirlaine by pointing to three differences between the Shirlaine lease and the one before us. Lessor argues that, rather than following Shirlaine, we should follow Sheppard because the Sheppard lease differed from the Shirlaine lease in the same three ways. See generally Sheppard, 668 S.W.3d at 335–49.

The first two differences that Lessor identifies are of no moment. Lessor points to two phrases unique to the Shirlaine lease—one stating that any “costs which result in enhancing the value of the marketable [minerals] . . . may be deducted from Lessor’s share of production so long as they are based on Lessee’s actual cost of such enhancements,” and the other stating that, “in no event shall Lessor receive a price that is less than, or mare [sic] than, the price received by Lessee.” Shirlaine, 2021 WL 5367849, at *1. But we did not rely on these provisions for our holding in Shirlaine. See id. at *5–7. Indeed, we concluded that they were “surplusage”—they were neither among the provisions that “set the direction for the ultimate outcome” nor the source of “the central dispute.” Id. (numbering sentences for identification and stating that *14 sentences 1 and 2 “set the direction,” sentence 7 was the “central dispute,” and sentences 5 and 6—containing the two phrases relied upon—were “surplusage”).

That brings us to the third difference that Lessor identifies—and the primary one it relies upon to distinguish Shirlaine. Lessor notes that the Shirlaine lease lacked an analogue to the Postproduction Provision, and it emphasizes that the Postproduction Provision frees its royalty from “direct[] or indirect[]” postproduction costs. Lessor claims that this reference to “indirect” costs is alluding to post-sale costs, and because of this reference, Lessor claims the case is controlled by Sheppard—a case which, according to Lessor, construed similar language regarding “indirect[]” costs and held that the leases required royalty payments on post-sale postproduction expenses.

It is true that, in Sheppard, the leases each contained analogues to the Postproduction Provision that freed the royalty interests from “bear[ing] or be[ing] charged with, either directly or indirectly, any part of the costs or expenses of [postproduction].” 9 668 S.W.3d at 338. In fact, the Sheppard leases included this “indirect[]” language not only in their Postproduction Provisions but also in each lease’s version of the Add-On Provision. Id. at 337–38. And there, the Texas Supreme Court held that the leases required the lessees to pay a royalty on certain post-sale, postproduction costs. Id. at 343–48.

9 Unquoted portions of Sheppard’s Postproduction Provisions reveal further differences from the Postproduction Provision here. We need not explore such differences, though, because the Postproduction Provisions were not the basis for the Sheppard court’s holding. See Tex. R. App. P. 47.1.

But Lessor’s reliance on Sheppard is misplaced. Not only did the Sheppard leases use a gross-proceeds yardstick rather than a wellhead-market-value yardstick, and not only was the gross-proceeds yardstick a key component of the Sheppard court’s interpretive analysis, but also the holding in that case focused on each lease’s Add-On Provision—not their Postproduction Provisions. Id. at 339, 345–49 (emphasizing that the lease’s version of the Add-On Provision was “atypical” and that “there [wa]s nothing common, usual, or standard about the language in [it]”). And the language in Sheppard’s Add-On Provisions was materially different from that in the Add-On Provision here. See id. at 337–38.

In Sheppard, each Add-On Provision stated that “[i]f any disposition, contract[,] or sale of oil or gas shall include any reduction or charge for the expenses or costs of [postproduction],” then the “deduction, expense[,] or cost shall be added to . . . gross proceeds so that Lessor’s royalty shall never be chargeable directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes.” Id. (emphasis removed). In construing this language, the Sheppard court highlighted that it applied to “any reduction or charge” included in any disposition or sales contract and that it required the amounts to be “added to” the gross proceeds so that the lessors “never” bore those costs, even “indirectly.” Id. at 345. The court noted that the relevant sales contracts set the prices—and lessees’ gross proceeds—by taking an indexed market value downstream and deducting the buyers’ postproduction costs. Id. at 339. And it further noted that, because each lease’s analogue to the Valuation *16 Provision provided for a royalty based on “gross proceeds,” the Valuation Provisions had already “free[d] the royalty from all pre-sale costs,” meaning that the Add-On Provision analogues “serve[d] no purpose at all if not to allow the amount on which the royalty payment [wa]s calculated to exceed gross proceeds.” Id. at 337, 345 (emphasis removed). Given the gross-proceeds yardstick for valuation and the “inescapably broad” language of the Add-On Provisions, the court concluded that the Sheppard leases were “‘proceeds plus’ leases” that “unambiguously contemplate[d] royalty payable on an amount that may exceed the consideration accruing to the producers.” Id. at 345, 348.

It was thus the Add-On Provisions—not the Postproduction Provisions—that were the linchpin in Sheppard. 10 Id. at 345–48. And although Sheppard’s Add-On Provisions referenced “indirect[]” costs, they did so in the context of clarifying what expenses could be “added to . . . gross proceeds”—which by definition already included pre-sale postproduction expenses. Id.

But a gross-proceeds royalty is fundamentally different from a wellhead-market-value royalty. See BlueStone, 620 S.W.3d at 391 (noting that “the terms ‘gross

10 In fact, the Sheppard court noted that the Postproduction Provisions, “by citing and disclaiming the holdings in Heritage[, 939 S.W.2d 118,] and Judice [v. Mewbourne Oil Co., 939 S.W.2d 133 (Tex. 1996)] . . . manifest[ed] an intent to prohibit deductions for postproduction costs incurred by the producers.” 668 S.W.3d at 347. So although the Sheppard Postproduction Provisions did not “override the ‘added to’ language in [the Add-On Provisions],” the Postproduction Provisions’ references to indirect costs did not provide a separate basis for requiring royalties to be paid on post-sale postproduction expenses. Id.

proceeds’ and ‘at the well’ [used in the same lease] give[] rise to ‘an inherent conflict’”); Judice, 939 S.W.2d at 136 (similar); Heritage, 939 S.W.2d at 130 (Owen, J.) (plurality op. on reh’g) (similar). And whether a “disposition, contract[,] or sale . . . include[s] any reduction or charge for the expenses or costs of [postproduction]”—the condition in each Sheppard lease’s Add-On Provision—is a different question from whether “Lessee realizes proceeds of production after deduction for any [postproduction] expense”—the condition in the Add-On Provision here. Sheppard is not on point. See Sheppard, 668 S.W.3d at 337–38, 348 (emphasis removed) (reiterating that “different royalty provisions have different meanings” and that the court’s holding was limited to “the specific language of the provisions before [it]”).

Meanwhile, as already noted, the Shirlaine lease provided for a wellhead-market-value royalty like the one here, and it contained an Add-On Provision nearly identical to the one here. See Shirlaine, 2021 WL 5367849, at *1, *5–7. And in Shirlaine, because the lessee realized proceeds at the wellhead, we recognized that the Add-On Provision was “simply not applicable.” Id. at *7.

Thus, Lessor’s attempt to distinguish Shirlaine and rely on Sheppard is unavailing. Shirlaine controls and is binding. See Mitschke v. Borromeo, 645 S.W.3d 251, 256–57 (Tex. 2022) (explaining that “[h]orizontal stare decisis, . . . addresses ‘the respect that [a c]ourt owes to its own precedents,” and under that doctrine, “three-judge panels must *18 follow materially indistinguishable decisions of earlier panels of the same court unless a higher authority has superseded that prior decision”). C. Shirlaine is logically, legally, and linguistically sound.

Moreover, even if Shirlaine were not binding, we would reach the same conclusion because its reasoning is logically, legally, and linguistically sound.

Lessor’s argument seizes on the idea that, even before postproduction occurs, postproduction expenses play a role in determining the wellhead market value because the buyer anticipates incurring the postproduction expenses and reselling the gas downstream. Lessor interprets these marketplace considerations as “deduction[s]” under the Lease such that Lessees “realize[] proceeds of production after deduction for [postproduction] expense[s].” But this interpretation of “deduction[s]” twists commonsense economics into something it is not, and it ignores the case law and Lease language to the contrary.

“Market value means the price a willing buyer under no compulsion to buy will pay to a willing seller under no compulsion to sell.” BlueStone, 620 S.W.3d at 388 (internal quotation marks omitted). Both logic and experience confirm that, if a company is buying an item for resale—say, a banana—the company will charge the end customer enough to cover both the cost it pays the supplier for the good and any transportation costs incurred to get the good to market. A banana has a lower market value at the plantation—where H-E-B buys it from the farmer—than it does at the final point of sale—where the hungry customer buys it from H-E-B. And, relatedly, *19 the price that H-E-B is willing to pay the farmer is influenced by its anticipated transportation costs and grocery-store banana pricing. So in a sense, the banana farmer is burdened by H-E-B’s transportation costs, having received a lower price than that paid by the H-E-B shopper.

These often-unspoken, commonsense principles are the premises underlying the workback method, i.e., the estimation of wellhead market value by subtracting post-sale costs from the downstream price. Id. at 389 (recognizing that “[t]he workback method is based on the premise that . . . production is less valuable at the wellhead” because the buyer will “have to incur the costs to remove impurities . . . , to transport it from the wellhead, or otherwise to get it ready for [downstream] sale”); see Heritage, 939 S.W.2d at 130 (Owen, J.) (plurality op. on reh’g) (describing net-back approach). And the wellhead royalty interest “bears its usual share of postproduction costs” in the same sense as the banana farmer. BlueStone, 620 S.W.3d at 389.

But the workback approach is merely “a market-value proxy.” Id.; see Heritage, 939 S.W.2d at 130 (Owen, J.) (plurality op. on reh’g). The banana farmer does not actually “realize[] proceeds . . . after deduction” of H-E-B’s transportation costs. See Potts v. Chesapeake Expl., L.L.C., 760 F.3d 470, 475 (5th Cir. 2014) (rejecting similar argument as contrary to case law and “mathematically unsound”). Nor does the lessee who sells gas at the wellhead actually “realize[] proceeds . . . after deduction” of postproduction costs. At the end of the day, because a royalty paid on “[m]arket value ‘at the well’ means the value of gas at the well, before it is . . . prepared for market” *20 via postproduction, “logic and economics tell us that there are no marketing [i.e., postproduction] costs to ‘deduct’ from value at the wellhead.” Heritage, 939 S.W.2d at 129–30 (Owen, J.) (plurality op. on reh’g); see Deduction, Merriam-Webster, https://www.merriam-webster.com/dictionary/deduction (last visited July 10, 2025) (defining “deduction” as “an act of taking away” or “something that is or may be subtracted”). Indeed, the very language of the Add-On Provision recognizes that, for a cost to constitute a “deduction,” Lessees’ realization of proceeds must come “after” it. And post-sale expenses are—as the descriptor implies—post-sale.

Thus, when the Supreme Court of Texas interpreted a wellhead-market-value lease in Heritage, a plurality concluded that the lease’s version of the Add-On Provision was “surplusage.” Heritage, 939 S.W.2d at 130–31 (Owen, J.) (plurality op. on reh’g) (explaining that, because “‘market value at the well’ [wa]s the benchmark for valuing the gas, [the] phrase prohibiting the deduction of post-production costs from that value d[id] not change the meaning of the royalty clause” and was “surplusage”). “The concept of ‘deductions’ of marketing costs [i.e., postproduction expenses] from the value of the gas is meaningless when gas is valued at the well.” Id. at 130.

Here, then, because the Valuation Provision fixes the point of sale as the valuation location, and because that point of sale is the wellhead, Lessees do not “realize[] proceeds . . . after deduction for any [postproduction] expenses.” See Shirlaine, 2021 WL 5367849, at *1, *5–7. The Add-On and Postproduction Provisions may come into play in other situations, but they are “simply not applicable” to the *21 facts before us. See id. at *7 (holding similarly and noting that, because lease provided for royalty to be calculated based on the “market value . . . at the point of sale, not necessarily at the well, other potential sales at other points might appropriately fall within the ambit of [the lease’s Add-On Provision]”).

Therefore, Lessees did not breach the Lease by calculating Lessor’s royalty payment based on the gas’s market value at the wellhead without adding in post-sale postproduction costs, and the trial court did not err by granting summary judgment on that basis.

We overrule Lessor’s sole issue.

V. Conclusion

As in Shirlaine, the Lease is unambiguous, and Lessees did not breach it. See id. at *1, *6–7. We affirm the trial court’s take-nothing summary judgment in favor of Lessees. See id. at *7.

/s/ Wade Birdwell

Wade Birdwell Justice

Delivered: July 17, 2025