H.L. Hawkins, JR., Inc. v. Capitan Energy, Inc.

 IN THE UNITED STATES DISTRICT COURT FOR THE WESTERN DISTRICT OF TEXAS PECOS DIVISION H.L. HAWKINS, JR., INC., § , § § P:22-CV-00020-DC v. § § CAPITAN ENERGY, INC., § THUNDERHEAD PETROLEUM § II, LP, § . § MEMORANDUM OPINION This case involves a straightforward issue of lease interpretation. Plaintiff H.L. Hawkins, Jr., Inc. claims Defendants Capitan Energy, Inc. and Thunderhead Petroleum II, LP deducted impermissible costs from the gross proceeds used to calculate the royalties owed to Hawkins. Defendants contend that they have consistently calculated Hawkins’ royalty payments in line with the lease agreement’s language. So the key questions are what does the lease say, and the language allow? BACKGROUND In 2011, Hawkins and Thunderhead1 entered an oil and gas lease (“Lease”) that covers hundreds of acres and four operating wells—Jess Fee 40 1H, Jess Fee 40 2H, Shelly Fee 40 1H, and Shelly Fee 40 2H (“Wells”). In relevant part, the Lease states that Thunderhead, as Lessee, would pay Hawkins, the Lessor, “One-Fourth (1/4) of the gross proceeds received by Lessee” for all oil and gas “recovered, separated, produced or saved from or on the leased premises and sold by Lessee in an arms’ length transaction.” Capitan 1 Defendant Thunderhead Petroleum II, LP is the successor in interest to Defendant Thunderhead Petroleum I, LP operated the Wells and paid Hawkins its applicable royalties on behalf of Thunderhead as its agent. The Lease also contains a provision in Paragraph 3(e), titled “Royalty to be Free of Expenses,” which outlines in full: (e). Royalty to be Free of Expenses. Lessor's royalty shall not bear or be charged with, directly or indirectly, any cost or expense incurred by Lessee, including without limitation, for exploring, drilling, testing, completing, equipping, storing, separating, dehydrating, transporting, compressing, treating, gathering, or otherwise rendering marketable or marketing products, and no such deduction or reduction shall be made from the royalties payable to Lessor hereunder, provided, however, that Lessor’s interest shall bear its proportionate share of severance taxes and other taxes assessed against its interest or its share of production. The Parties’ business relationship seemed uneventful until a dispute arose on whether Capitan was properly calculating Hawkins’ royalty payments under the Lease’s terms. Hawkins thus, in early 2020, hired a consulting team to audit how Capitan was calculating and paying royalties under the Lease. In Spring 2021, Hawkins’ audit team finished its report, detailing nine areas (“Exceptions”) where Capitan’s payment of royalties from 2015 through 2019 deviated from the Lease. A year later, Capitan responded to the Hawkins’ audit, conceding two of the Exceptions but disagreeing with the rest. Because Capitan allegedly was not paying Hawkins’ its full royalty, Hawkins sued Defendants for breach of contract and violation of Texas Natural Resources Code § 91.402. The Parties have now cross-moved for partial summary judgment. Hawkins moves for summary judgment, asking the Court to adopt its interpretation of the Lease, which would establish Defendants’ liability. Defendants likewise move for summary judgment on their interpretation of the Lease, also moving for summary judgment on their statute of limitations defense. LEGAL STANDARD I. Summary judgment under Rule 56 of the Federal Rules of Civil Procedure. The purpose of summary judgment is to isolate and dispose of factually unsupported claims or defenses.2 Summary judgment is proper under Rule 56(a) of the Federal Rules of Civil Procedure “if the movant shows that there is no genuine dispute as to any material fact and the movant is entitled to judgment as a matter of law.” A dispute about a material fact is genuine when “the evidence is such that a reasonable jury could return a verdict for the nonmoving party.”3 Substantive law identifies which facts are material.4 The trial court “must resolve all reasonable doubts in favor of the party opposing the motion for summary judgment.”5 The party seeking summary judgment bears the initial burden of informing the court of its motion and identifying “depositions, documents, electronically stored information, affidavits or declarations, stipulations (including those made for purposes of the motion only), admissions, interrogatory answers, or other materials” that establish the absence of a genuine issue of material fact.6 Once the movant has carried its burden, the nonmovant must “respond to the motion for summary judgment by setting forth particular facts indicating there is a genuine issue for trial.”7 A nonmovant must present affirmative evidence to defeat 2 Celotex Corp. v. Catrett, 477 U.S. 317, 323–24 (1986). 3 Anderson v. Liberty Lobby Inc., 477 U.S. 242, 248 (1986). 4 Id. 5 Casey Enters., Inc. v. Am. Hardware Mut. Ins. Co., 655 F.2d 598, 602 (5th Cir. 1981). 6 Fed. R. Civ. P. 56(c)(1)(A); Celotex, 477 U.S. at 323. 7 Byers v. Dall. Morning News, Inc., 209 F.3d 419, 424 (5th Cir. 2000). a properly supported motion for summary judgment.8 Mere denials of material facts, unsworn allegations, or arguments and assertions in briefs or legal memoranda will not suffice to carry this burden. Rather, the Court requires “significant probative evidence” from the nonmovant to dismiss a request for summary judgment.9 The Court must consider all the evidence but “refrain from making any credibility determinations or weighing the evidence.”10 II. Lease interpretation under Texas law. When interpreting a lease under Texas law, a court’s “fundamental objective is to ascertain the parties’ intent as expressed in the leases.”11 Likewise, courts should construe “the instruments as a whole, giving the language its plain, ordinary, and generally accepted meaning unless the context indicates the parties used terms in a technical or different sense.”12 “[T]he decisive factor in each [contract-construction] case is the language chosen by the parties to express their agreement.”13 And when the lease language is unambiguous, which the Parties agree is the case here, it will be enforced as written.14 DISCUSSION Hawkins moves for partial summary judgment on the Lease’s plain language, namely that the Lease’s language establishes Defendants’ liability, reserving the question of damages for trial. In contrast, Defendants move for partial summary judgment that they are not liable (citing Anderson, 477 U.S. at 248–49). 8 Anderson, 477 U.S. at 257. 9 In re Mun. Bond Reporting Antitrust Litig., 672 F.2d 436, 440 (5th Cir. 1982) (quoting Ferguson v. Nat’l Broad. Co., 584 F.2d 111, 114 (5th Cir. 1978)). 10 Turner v. Baylor Richardson Med. Ctr., 476 F.3d 337, 343 (5th Cir. 2007). 11 Devon Energy Prod. Co., L.P. v. Sheppard, 668 S.W.3d 332, 343 (Tex. 2023), reh'g denied (June 16, 2023). 12 Id. 13 Nettye Engler Energy, LP v. BlueStone Nat. Res. II, LLC, 639 S.W.3d 682, 696 (Tex. 2022). 14 E.g., Sun Oil Co. (Delaware) v. Madeley, 626 S.W.2d 726, 728 (Tex. 1981). for Exceptions 3, 6, 7, 8, and 9 highlighted by Hawkins’ experts. The contested Exceptions can be summarized as follows: Exception 3 Transportation Fees Deducted from Oil Royalty: Capitan improperly deducted transportation costs by netting gross oil prices for transportation and other post-production costs. As a result Capitan underpaid royalties by netting the fees against the gross oil prices. Exception 6 Natural Gas Liquids Deduction: Capitan valued natural gas liquids (NGLs) at prices net of transportation, fractionation, and other downstream fees. Exception 7 Plant and Fuel Loss Deductions: Capitan did not pay royalty on volumes used as plant fuel and plant loss, resulting in underpaid royalties. Exception 8 Flared and Lease Use Gas Deductions: Capitan valued flared and lease-use gas volumes using residue prices reduced for downstream post- production costs. Exception 9 Residue Deductions: Capitan valued residue gas using prices reduced for downstream post-production costs. Defendants also move for summary judgment on the statute of limitations, arguing that Hawkins should be barred from recovering any damages accruing before June 8, 2018. I. Are Defendants liable under the Lease for Exceptions 3, 6, and 9? The Court starts with the Parties’ lease interpretation battle on Exceptions 3, 6, and 9. But before analyzing the Lease’s language, the Court will first touch on a few key terms in the oil and gas industry as defined by the Texas Supreme Court. First, “[p]roduction is the process of bringing minerals to the surface.”15 In other words, the moment the sought-after minerals exit the wellhead constitutes the point of “production.” Second, a “royalty” is “generally defined as ‘the landowner's share of production, free of expenses of production.’”16 And depending on the lease terms, the royalty’s valuation point—the point at which the royalty base is calculated and from which the lessor takes their share—“may be calculated at the wellhead or at any downstream point.”17 Lastly, there are production and postproduction costs, with the former being the costs of producing the mineral, and the latter being expenses incurred by the operator to prepare, transport, and market the raw minerals for downstream sale.18 Generally, a royalty owner does not share the production costs burden with the lessee, meaning the lessee/operator bears all production costs.19 Postproduction costs, however, generally are included when calculating the royalty base.20 In other words, the “royalty base” from which the royalty owner takes its share usually carries the “costs [] incurred to remove impurities, to transport production from the wellhead, and to otherwise ready it for sale to a downstream market.21 Yet the lease “type”—evidenced by the parties’ agreed lease language—can alter the “usual” cost-allocation rules. For example, in a “proceeds” lease, the royalty is calculated “‘based on the amount the lessee in fact receives under its sales contract for the gas,’ regardless of whether it is more or 15 BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 386 (Tex. 2021). 16 U.S. Shale Energy II, LLC v. Laborde Properties, L.P., 551 S.W.3d 148, 154 (Tex. 2018) (quoting Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121–22 (Tex. 1996). 17 BlueStone Nat. Res. II, LLC, 620 S.W.3d at 387. 18 Id. 19 Devon Energy Prod. Co., L.P. v. Sheppard, 668 S.W.3d 332, 336 (Tex. 2023), reh'g denied (June 16, 2023). 20 Id. 21 Id. less than market value.”22 But there’s another layer; a lease may be a “gross proceeds” or a “net proceeds” lease. A “gross proceeds” lease, also called an “amount realized” lease, “standing alone, creates a royalty interest that is free of postproduction costs.”23 In contrast, a “net proceeds” lease would, in general, move the royalty base’s valuation point, allowing the operator to deduct certain postproduction costs.24 The Parties do not dispute that the Lease is a “gross proceeds” lease, and thus the royalty base for Hawkins’ royalty should be “computed on gross amounts received … based on point-of-sale proceeds without deduction of postproduction costs” incurred by Capitan. Yet it’s not that simple; the moment Capitan produces the minerals, the captured minerals are immediately diverted into storage tanks on the well pad, from which the minerals are sold and dispensed into the third-party buyers’ trucks or other transportation means.25 So at that point, no postproduction costs. But that doesn’t mean the postproduction costs for making the captured minerals marketable for downstream sale don’t impact Hawkins’ royalty base at some point. Indeed, when Capitan sells the captured minerals to a third party, the per-unit price in the third-party sales contract is adjusted downward to account for the costs that the third party will incur for marketing, transporting, or otherwise readying the raw minerals for downstream sale. Put simply, Capitan receives a lower price for the captured minerals—which means a lower royalty base from which Hawkins takes its one-fourth royalty share—because the pricing 22 BlueStone Nat. Res. II, LLC, 620 S.W.3d at 387 (quoting Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (emphasis in original). 23 Id. at 390. 24 See, e.g., Burlington Res. Oil & Gas Co. LP v. Texas Crude Energy, LLC, 573 S.W.3d 198, 209 (Tex. 2019) (“We have previously interpreted a ‘net proceeds’ royalty provision to authorize deduction of post-production costs.”). 25 Doc. 61, Ex. 9 at ¶¶ 6, 12–13 (filed under seal). formula in the third-party contract accounts for the third party’s postproduction costs. That is the crux of this case. The Lease’s relevant language states that “Lessor’s Royalty shall not bear or be charged with, directly or indirectly, any cost or expense incurred by Lessee …” The Parties agree that the Lease bars Capitan from “directly or indirectly” charging Hawkins’ royalty with any cost or expense that Capitan incurs. But in that agreement lies the dispute. Capitan argues it does not “incur” postproduction costs because all postproduction costs are incurred by the third party after the point of sale. Hawkins disagrees, arguing that the Texas Supreme Court’s reasoning in Devon Energy Production Company, L.P. v. Sheppard forecloses Capitan’s argument.26 And even if Devon v. Sheppard does not fully apply, Hawkins asserts that the Lease’s plain language still prevents the postproduction deductions in Capitan’s sales contracts. The Court handles each argument in turn. A. Does the reasoning from already decide Defendants’ liability? Hawkins contends that the Lease does bar such deductions because of the Texas Supreme Court’s reasoning from its recent decision in Devon Energy Production Company, L.P. v. Sheppard. There, the Devon Court faced similar facts; the operator was deducting from the price any post-sale costs incurred by unaffiliated third-party buyers after the point of sale before the royalty calculation was made.27 So because of those post-sale, postproduction deducts, the “gross proceeds” number—from which the lessor’s fractional royalty share was calculated—was lower. 26 668 S.W.3d 332 (Tex. 2023), reh'g denied (June 16, 2023). 27 Id. at 338–39. But this case is distinguishable from Devon. To begin with, the lease language in Devon is far more encompassing than the Lease in this case. For example, the lease in Devon contains an “addback clause,” which stated, “any reduction or charge for the expenses or costs of production, treatment, transportation, manufacturing, process[ing] or marketing of the oil or gas … shall be added to … gross proceeds so that Lessor's royalty shall never be chargeable directly or indirectly with any costs or expense other than its pro rata share of severance or production taxes.” 28 Like the Devon Court recognized, this means the lease language “employ[ed] a two-prong calculation” of the royalty base—the gross proceeds received by the operator plus the “enumerated postproduction costs or expenses … deducted in setting the sales prices” added back to the gross proceeds.29 Or like the Devon appeals court put it: “a ‘proceeds-plus’ royalty that ‘expressly [and unambiguously] contemplates the addition of certain sums to gross proceeds in order to arrive at the proper royalty base.”30 In contrast, the Lease in this case contains no such language, a point which Hawkins concedes.31 What’s more, the Devon lease takes the addback language a step further by “expressly” mandating that reductions included in third-party contracts be added back to the gross proceeds.32 Indeed, the Devon lease required that the operator addback any reduction or charge for the postproduction costs included in “any disposition, contract or sale of oil or gas.”33 So unlike the Lease here, the Devon lease not only required postproduction costs to be 28 Id. at 337, 339 (emphasis in original). 29 Id. at 348 (emphasis added). 30 Devon Energy Prod. Co., L.P. v. Sheppard, 643 S.W.3d 186, 189, 201, 205, 211 (Tex. App.—Corpus Christi– Edinburg 2020), aff'd, 668 S.W.3d 332 (Tex. 2023). 31 Doc. 67 at 8 (“While the lease in Sheppard contains an “add-to” clause that does not appear in the Lease, the absence of that clause does not warrant a different result.”). 32 Devon Energy Prod. Co., L.P. 668 S.W.3d at 336. 33 Id. added back, but also explicitly required the operator to addback reduction or charges for postproduction costs in any contract or sale of oil or gas. Although Hawkins still wishes to xerox the Devon Court’s reasoning to this case despite the distinct lease language, this Court is wary of reading Devon so broadly for two reasons. First, the Devon Court cautioned “‘that different royalty provisions have different meanings,’ and the construction of an oil-and-gas lease must ultimately be based predominantly on the particular clause at issue construed within the context of the lease as a whole.”34 Put simply, courts should be wary of applying the reasoning from one oil and gas lease to another, distinct lease. Second, the Devon Court repeatedly emphasized “‘the highly unique’ lease terms” at issue.35 For example, the Devon lease is described as having “inescapably broad language.”36 In fact, in the opinion’s conclusion, the Devon Court stated the parties “employ[ed] atypical lease language” that is “broad and without limitation.” And unlike the lease in Devon, the Lease in this case is—as Hawkins describes it—straightforward.37 So in sum, Hawkins’ invitation to read Devon’s reasoning so broadly as to apply it in this case ignores the Texas Supreme Court’s repeated warnings that “the construction of an oil-and-gas lease must ultimately be based predominantly on the particular clause.”38 34 Id. at 348 (citing Burlington Res. Oil & Gas Co. LP v. Texas Crude Energy, LLC, 573 S.W.3d 198, 206 (Tex. 2019); Endeavor Energy Res., L.P. v. Energen Res. Corp., 615 S.W.3d 144, 155 (Tex. 2020)). 35 Id. at 340 (quoting Devon Energy Prod. Co., L.P. v. Sheppard, 643 S.W.3d 186, 189 (Tex. App.—Corpus Christi–Edinburg 2020), aff'd, 668 S.W.3d 332 (Tex. 2023). 36 Id. at 345. 37 Doc. 59 at 1. 38 Devon Energy Prod. Co., L.P. 668 S.W.3d at 348. B. Even if does not foreclose Defendants’ argument, does a plain reading of the Lease still prevent postproduction deductions in third-party sales contracts? But the issues in this case are not settled just because Devon v. Sheppard’s reasoning cannot be transcribed and applied here. Indeed, the question is now what this Lease says and what it bars. Because the Parties agree that the Lease language is unambiguous, the Court’s task is “to ascertain the parties' intentions as expressed in the lease.”39 Texas law requires the Court to enforce the unambiguous lease as written, giving terms their plain and ordinary meaning unless the instrument reflects that the parties intended a different meaning.40 The Lease’s relevant language states that “Lessor’s Royalty shall not bear or be charged with, directly or indirectly, any cost or expense incurred by Lessee …” Again, the Parties agree that “directly or indirectly” in the Lease’s language should modify “charged.”41 Thus, a better reading of the Lease’s language would be “Capitan shall not directly or indirectly charge Hawkins’ Royalty for any cost or expense incurred by Capitan.” Hawkins’ main argument is that Capitan’s contracts with third-party buyers have “indirectly charged Hawkins’ royalties with prohibited costs, which are not allowed under the Lease.” But that argument, although seemingly persuasive on its face, omits the key condition precedent—the costs must have been “incurred” by Capitan. Put simply, two things must be true for Capitan to have violated the Lease’s language. First, Capitan must have “incurred” the costs. Second, Capitan must have then directly or 39 Id. at 343. 40 Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex.1996). 41 Doc. 61 at 7 (“In other words, the modifier ‘directly or indirectly’ modifies ‘charge’ and not ‘incurred.’”); Doc. 67 at 8 (“But Hawkins does not dispute that ‘directly or indirectly’ modifies ‘charged’ in the Lease.”). indirectly charged Hawkins’ Royalty with those costs. So the problem is that Hawkins’ argument begs the question on who is incurring the postproduction expenses. According to Black’s Law Dictionary, “incur” means “[t]o suffer or bring on oneself (a liability or expense).”42 Likewise, the Oxford English Dictionary states “incur” means “to become through one's own action liable or subject to.”43 So who is liable for paying for the postproduction costs? The answer becomes clear with another, simple question: if the captured minerals are prepared, marketed, and transported from Capitan’s well pad to a downstream sale location, who takes on the expense (pays) to do so? There’s no evidence Capitan does; the undisputed way Capitan conducts operations for the Wells supports that fact. Thus, Capitan does not “incur” postproduction costs according to the word’s plain meaning. Hawkins’ counter that Capitan is “subject to” deductions in the pricing formula would be more persuasive if “directly or indirectly” modified “incurred” because Capitan arguably “indirectly incurs,” thus subject to, postproduction costs when it takes a lower price because of a pricing formula deducting such costs. But again, the Parties agree that “directly or indirectly” modifies “charged.” That leads to another unaddressed problem—Capitan must have incurred a “cost or expense.” In this situation, the third parties incur transportation, marketing, or other preparatory costs; Capitan “incurs” a decrease in revenue. Without being too pedantic, a decrease in revenue is different from an increased cost or expense. Indeed, there many reasons why a company would structure operations one way or another for accounting 42 Black’s Law Dictionary 917 (Bryan A. Garner ed., 11th ed. 2019). 43 Incur, OXFORD ENGLISH DICTIONARY (3d ed. 2015). purposes. Take simple economies of scale, which could make it more profitable for a smaller operator, with lower volume, to sell at the well pad for a lower price rather than undertake the postproduction work itself. The Court recognizes that this is a common accounting maneuver; companies large and small structure contracts or shift items on the P&L statement with accounting in mind. But decreasing revenue through taking a lower price is different from incurring an expense. And, critically, this accounting technique—which Hawkins has not alleged is fraudulent— does not violate the Lease’s plain language. Hawkins’ proposed interpretation of the Lease ventures away from a purely textual reading and into the realm of more constitutional interpretative canons that search for meaning outside the parties’ meeting of the minds. That said, there is a temptation to analyze an oil and gas lease like a constitutional question. But succumbing to that temptation would lead to absurd results based on outside societal factors that the text could not bear.44 Indeed, textual interpretation “in its purest form begins and ends with what the text fairly implies.”45 In short, Capitan did not violate the Lease when the pricing formula in its third-party sales contracts accounted for postproduction costs to be incurred by those third parties. Accordingly, the Court will deny Hawkins’ summary judgment motion on the Lease’s interpretation and grant summary judgment in Defendants’ favor on Exceptions 3, 6, and 9. 44 See, e.g., Van Dyke v. Navigator Grp., 668 S.W.3d 353 (Tex. 2023), reh'g denied (June 16, 2023) (holding that the mineral reservation of “one-half of one-eighth” in a 1924 deed actually meant four-eighths because there was a widespread “misconception” in society at the time about what that common lease term meant). 45 Antonin Scalia & Bryan Garner, Reading Law: The Interpretation of Legal Texts 14 (2012). II. Are Defendants liable under the Lease for Exceptions 7 and 8? The two remaining exceptions in Defendants’ summary judgment motion are Exceptions 7 and 8. Exception 7 accuses Capitan of failing to pay royalties on volumes used as plant fuel and plant loss, while Exception 8 asserts that Capitan valued flared and lease- use gas volumes using residue prices deal. The Lease’s royalty provision for gas states in full: Lessee shall pay the Lessor One-Fourth (1/4) of the gross proceeds received by Lessee for all gas (including substances contained in such gas) recovered, separated, produced or saved from or on the leased premises and sold by Lessee in an arms’ length transaction; provided, however in the event gas is not sold under an arms’ length transaction, Lessor’s royalty on such gas (including substances contained in such gas) shall be calculated by using the highest price paid or offered for gas of comparable quality in the general area where produced and when run. For both Exceptions, Capitan argues that under the gas royalty provision, it must pay royalties only for gas “sold by Lessee.” Thus, it was not required to pay for plant and fuel loss or flared and lease use gas. Yet like Hawkins points out, Capitan omits the second half of those paragraphs, which outlines what happens “in the event gas is not sold under an arms’ length transaction.” In that case, “Lessor’s royalty on such gas (including substances contained in such gas) shall be calculated by using the highest price, plus premium, if any, paid or offered for gas of comparable quality in the general area where produced and when run.” Capitan counters, however, that the second half does not apply because gas “not sold in an arms’ length transaction” is a common clause in oil and gas leases that merely protects the lessor from “sweetheart” transactions between the lessee and an affiliate. Put simply, Capitan believes royalties should be paid under the Lease only on gas sold, with one mechanism outlining how royalties should be paid when the gas is sold in an arms’ length transaction and the other when gas is sold in a non-arms’ length transaction. And to that end, Capitan urges the Court to “fulfil its duty to harmonize and give effect to all provisions of the contract.”46 The Court agrees with that sentiment, but not with Capitan’s interpretation. Capitan’s interpretation belies a simple reading. A simple reading divides the Royalty Clause into (1) gas sold in an arms’ length transaction and (2) gas not sold in arms’ length transaction. The phrase “gas not sold in an arms’ length transaction” would therefore cover every circumstance where the gas is not sold in an arms’ length transaction—the sweetheart deals with affiliates and gas not sold. Next, “reading the contract as a whole,” the Court notes the Lease includes a “free use clause” in Paragraph 6(c), which gives Capitan the right “to have free use of oil, gas and water from the leased premises … for all operations hereunder.” The free use clause thus carves out from the royalties provision gas not sold but used by Capitan in its operations. And as Capitan so helpfully suggests, the Court will “give effect to all provisions of the contract” with the Surplusage Canon. The Surplusage Canon requires that “every provision is to be given effect” and that “[n]o provision “should needlessly be given an interpretation that causes it to duplicate another provision or to have no consequence.”47 So if, like Capitan insists, only gas “sold” triggers the need to pay royalties, what is the purpose of the free use clause? The free use clause would then have no consequence—needless 46 Doc. 71 at 5. 47 Antonin Scalia & Bryan Garner, Reading Law: The Interpretation of Legal Texts 174 (2012) (Surplusage Canon); see also Devon Energy Prod. Co., L.P. v. Sheppard, 668 S.W.3d 332, 343 (Tex. 2023), reh'g denied (June 16, 2023) (“To the extent possible, we strive to harmonize and give effect to all the lease provisions so that none will be rendered meaningless.”). surplusage. Thus, gas “recovered, separated, produced or saved from or on the leased premises” that is not sold in an arms’ length transaction, and not falling under the free use clause, would obligate the payment of royalties “calculated by using the highest price, plus premium, if any, paid or offered for gas of comparable quality in the general area.” There is one slight wrinkle, however, on Exception 8. Lease-use gas would seemingly fall under the free use clause; Hawkins does not appear to argue to the contrary. The issue is that Capitan argues that flared gas also falls under the free use clause because “flared gas is burned on the premises for several purposes.” Capitan cites paragraph 13 of its expert’s declaration to support that assertion.48 But paragraph 13 of that declaration does not say what those “several purposes” are or anything relevant to flaring. And without more evidence, Defendants have not met their summary judgment burden. So in sum, Defendants’ summary judgment on Exceptions 7 and 8 should be denied as to any gas not falling under the free use clause in Paragraph 6(c) of the Lease. III. Defendants’ liability under the Texas Natural Resources Code. Hawkins also moves for summary judgment on Defendants’ liability under the Texas Natural Resources Code. Section 91.402(a) of the Texas Natural Resources Code requires that “[t]he proceeds derived from the sale of oil or gas production from an oil or gas well located in this state must be paid to each [lessor] by [lessee] on or before 120 days after the end of the month of first sale of production from the well.” If payments from lessee to lessor are not made within the applicable period, lessee must pay interest on such late 48 Doc. 61, Ex. 9 at ¶¶ 6, 12–13 (filed under seal). payments.49 The evidence shows Capitan has failed to pay some amount of royalties owed to Hawkins within the applicable period (e.g., Exception 7). Thus, Hawkins’ motion for summary judgment on Defendants liability under the Texas Natural Resources Code should be granted. IV. Tolling of the statute of limitations Because there appear to be some royalties required by the Lease that Capitan has not paid, the statute of limitations issue becomes relevant. But the Court is not convinced that Defendants have met their summary judgment burden on this issue. More evidence and arguments on this issue may be brought before the Court during the bench trial. Thus, Defendants’ summary judgment motion on damages accruing before June 8, 2018, should be denied. CONCLUSION The Court reiterates that there is a stark difference between this Lease and the lease in Devon v. Sheppard, which, for example, on its face covered postproduction costs incurred by other parties that indirectly affected the royalty base. That lease language would likely cover Capitan’s operations here. Yet parties have the freedom to contract for whatever they wish.50 So if Hawkins wanted the Lease to include an express prohibition against deducting postproduction costs from the price in any contract or oil and gas sale like the parties did in Devon, it could have done so. Indeed, the leases at issue in Devon were even drafted around the same time as the Lease in this case. But the Parties did not do so here. 49 TEXAS NAT. RES. CODE § 91.403. 50 E.g., Nettye Engler Energy, LP v. BlueStone Nat. Res. II, LLC, 639 S.W.3d 682, 696 (Tex. 2022). It is therefore ORDERED that Plaintiffs Motion for Summary Judgment be GRANTED in part and DENIED in part. The Court GRANTS summary judgment on Defendants’ violation of the Texas Natural Resources Code and DENIES summary judgment on Plaintiffs lease interpretation. It is also ORDERED that Defendants’ Motion for Summary Judgment be GRANTED in part and DENIED in part. The Court GRANTS summary judgment on Exceptions 3, 6, and 9, and DENIES summary judgment on Exceptions 7 and 8 and the tolling of the statute of limitations. It is so ORDERED. SIGNED this 10th day of August, 2023. UNITED STATES DISTRICT JUDGE 18