Gordon Potts v. Chesapeake Exploration, L.L

PRISCILLA R. OWEN, Circuit Judge: The meaning of royalty provisions in an oil and gas lease are in dispute. Gordon Potts and Brandy West (the lessors) appeal the district court’s grant of summary judgment in favor of the lessee, Chesapeake Exploration, L.L.C. (Chesapeake). We affirm. I Potts and West are two of the lessors in an oil, gas, and mineral lease in which Chesapeake is the successor-lessee to FSOC Gas Co., Ltd. (FSOC). Three paragraphs of the lease are at issue. Paragraph 11 provides in relevant part: The royalties to be paid by Lessee are: ... on gas ... the market value at the point of sale of 1/4 of the gas sold or used.... Notwithstanding anything to the contrary herein contained, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil *472 and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation. Paragraph 29 contains a “favored nation” provision, which states: Lessee agrees if Lessee or any of its Working Interest Partners has agreed to pay or later agrees to pay a higher royalty or bonus consideration to another landowner, mineral owner or other parties, (in the same drilling unit, spacing unit or pooled or utilized land to which the leased lands are included), then Lessee shall pay to Lessor an amount based on such higher royalty, or bonus consideration retroactive to the effective date of the Lease(s). Paragraph 37 provides, in pertinent part: Payments of royalties to Lessor shall be made monthly and shall be based on sales of leased substances to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor or leased substances not sold in an arms length transaction shall be determined based on prevailing values at the time in the area. Lessee shall have the obligation to disclose to Lessor any information pertinent to this determination. An affiliate of Chesapeake, Chesapeake Operating, Inc. (COI), operates the lease on Chesapeake’s behalf. COI, as agent for Chesapeake, sells gas produced from the lease to Chesapeake Energy Marketing, Inc. (CEMI), another affiliate of Chesapeake, at the wellhead located on the lessors’ property. CEMI then transports the gas through a gathering system and resells it to unaffiliated purchasers at gas pipeline hubs that are considerable distances from the wellhead. The sales to unaffiliated purchasers occur at delivery points that include the Houston Ship Channel and locations in Louisiana and Alabama. CEMI pays Chesapeake the weighted average sales price that CEMI receives when it sells the gas downstream, after deducting post-production costs that CEMI incurs between the wellhead and the points at which deliveries to unaffiliated purchasers occur. The royalty that Chesapeake pays to the lessors is 1/4 of the price it receives from CEMI. Potts protested to Chesapeake that his royalty payments were improperly calculated because post-production costs had been deducted in arriving at the value on which royalty was based. Potts also questioned whether Chesapeake had complied with the favored nation clause and demanded access to Chesapeake’s records. Chesapeake initially agreed that it should not have deducted post-production costs in calculating royalties and paid Potts accordingly. However, Chesapeake subsequently changed its position, asserting that its original concession regarding post-production costs was a mistake. Chesapeake conceded that it had failed to pay Potts the amount he was due under the favored nation provision, but in tendering what was owed under that provision of the lease, Chesapeake withheld the amount it contended was an “over-payment” of royalties due to post-production costs that Chesapeake had not, but was entitled to, deduct. Potts filed suit against Chesapeake in Texas state court, alleging breach of contract and seeking a declaratory judgment that Chesapeake was not permitted to deduct post-production costs in calculating royalty. After Chesapeake removed the case to federal district court on the basis of diversity jurisdiction, West joined the litigation as a plaintiff. West claimed that Chesapeake initially paid her royalties without deductions for post-production costs, but then ceased remitting payments altogether on the ground that she had been overpaid and Chesapeake was re- *473 eouping the difference out of future payments. The parties filed cross-motions for summary judgment. The district court granted Chesapeake’s motion and denied that of the lessors. Construing the lease under Texas law, the court held that Chesapeake was permitted to calculate “market value at the point of sale” by starting with the market value received from unaffiliated purchases and subtracting reasonable post-production costs incurred between the downstream points of sale to unaffiliated purchasers and the point of sale to CEMI. The lessors moved for reconsideration, arguing inter alia that because royalty payments are to be calculated based on sales to unrelated third parties under paragraph 37 of the lease, the “point of sale” to be considered is the point at which CEMI sold the gas to unaffiliated purchasers. The district court denied the motion. The lessors timely appealed. II “We review a district court’s grant of summary judgment de novo, applying the same standard as the district court.” 1 Under that standard, “[sjummary judgment is proper ‘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.’ ” 2 “We generally review a decision on a motion to alter or amend judgment under [Federal Rule of Civil Procedure] 59(e) for abuse of discretion. To the extent that a ruling was a reconsideration of a question of law, however, the standard of review is de novo.” 3 III The parties agree that Texas law applies in construing the lease. 4 Under Texas law, “[a]n oil and gas lease is a contract, and its terms are interpreted as such.” 5 The parties further agree that the lease in this case is unambiguous. “In construing an unambiguous oil and gas lease our task is to ascertain the parties’ intentions as expressed in the lease.” 6 We are to “examine the entire document and consider each part with every other part so that the effect and meaning of one part on any other part may be determined.” 7 Additionally, “[w]e give terms their plain, ordinary, and generally accepted meaning unless the instrument shows that the parties used them in a technical or different sense.” 8 A We begin our analysis of the lease’s provisions with the royalty clause in paragraph 11. It provides that royalties on gas are “the market value at the point of sale of 1/4 of the gas sold or used.” This unambiguously requires Chesapeake to pay 1/4 of the market value of the gas at the point at which Chesapeake sells the gas. If, as in the present case, the lessee sells the gas at the wellhead, there generally will be no post-production costs in *474 curred by the lessee. If the lessee sells the gas downstream from the wellhead, then the lessee would be required to pay 1/4 of the market value of the gas calculated at that point of sale and could not deduct post-production costs incurred between the wellhead and the point of sale. The lessors contend that there are other provisions in the lease that modify or override this part of the royalty clause. They rely on the following language, also found in the royalty clause in paragraph 11 of the lease: Notwithstanding anything to the contrary herein contained, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation. The above-quoted language directs that “royalty” is to be “free of all costs and expenses related to the exploration, production and marketing of’ gas “including, but not limited to, costs of compression, dehydration, treatment and transportation.” As discussed above, when gas is sold at the wellhead, there are typically no costs of compression, dehydration, treatment or transportation. When there are no such costs at the wellhead, the market value at the wellhead is “free of all costs and expenses,” as contemplated by the above-quoted paragraph, and there is nothing in the royalty clause “contrary” to the “Notwithstanding” sentence. If the gas is sold by the lessee downstream of the wellhead, then both the sentence providing for a 1/4 royalty and the “Notwithstanding” sentence contemplate that costs incurred by the lessee between the point of production and the point of sale are to be borne by the lessee. Since it is undisputed that gas sales by Chesapeake have occurred at the wellhead, and since the lessors do not contend that the sales to unaffiliated purchasers were at less than market value, Chesapeake could arrive at the market value at the wellhead by deducting reasonable post-production costs to deliver the gas from the wellhead to the point at which the gas was sold to unaffiliated purchasers. The district court correctly concluded that Chesapeake’s calculation of royalties is consistent with the methodology for calculating market value at the wellhead explained by the Supreme Court of Texas in Heritage Resources, Inc. v. NationsBank. 9 In Heritage, the royalties to be paid under the leases were a percentage of the gas’s “market value at the well.” 10 The leases further provided that “there shall be no deductions from the value of [the] Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.” 11 The Supreme Court of Texas held that the lessee had not breached the lease in arriving at market value of gas at the wellhead by deducting post-production transportation costs from the market value ascertainable at a downstream point. 12 The court explained, “[t]here are two methods to determine market value at the well.” 13 “The most desirable method is to use comparable sales” at the well. 14 When information about such sales is not readily available, the market value at the well is determined by taking the market value of the gas at a point downstream where sufficient information is available, and then “subtracting reasonable post-production *475 marketing costs,” such as transportation and processing expenses. 15 The “no deductions” clause, the court continued, simply “restate[d] existing law” by providing that the lessors’ royalty, which could be calculated using the two methods described, may not be further reduced because of costs. 16 The lessors insist that that the “[n]ot-withstanding” sentence is distinguishable from the “no deductions” clauses at issue in Heritage and should be given a different meaning. The clauses in Heritage stated that “there shall be no deductions from the value of [the] Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.” 17 The lessors contend that, unlike the clauses at issue in Heritage, a sentence in their lease provides that all royalties shall loe free of all costs. The lessors argue that the lease does not simply prohibit deductions from a given value, but provides affirmatively that the royalty may not be “burdened” with any costs. They maintain that subtracting post-production costs from sales that occur miles from the wellhead to derive the market value at the point of sale, in this case the wellhead, burdens the royalty with such costs. This argument misunderstands Heritage and is mathematically unsound. The Heritage court held that the “no deductions” clauses were not in conflict with the royalty provisions. The deduction of post-production costs incurred between the wellhead and a downstream point at which market value could be ascertained was nothing more than a method of determining market value at the well in the absence of comparable sales data at or near the wellhead. The value of the gas, and therefore the value of the royalty, was not reduced. As the concurring opinion stated, “[t]he concept of ‘deductions’ of marketing costs from the value of the gas is meaningless when gas is valued at the well. Value at the well is already net of reasonable marketing costs.” 18 That reasoning is equally applicable to the clause at issue in this case. The value of the lessors’ royalty is a percentage of the market value at the point of sale, which in this case is at the well. A “net-back” method of calculation does not “burden” or reduce the value of the royalty. 19 B The lessors contend, however, that the lease prohibits the point of sale from being at the wellhead if Chesapeake sells the gas to an affiliated entity. The lessors rely on paragraph 37 of the lease, which requires that royalty payments be “based on sales ... to unrelated third parties at prices arrived at through arms length negotiations.” Chesapeake argues that the lessors waived their reliance on paragraph 37 by failing to raise the issue in the district court until the lessors’ motion for reconsideration. Even if the lessors preserved their reliance on paragraph 37, a question that we do not reach, it does not support their position. Paragraph 37 says, in pertinent part: Payments of royalties to Lessor shall be made monthly and shall be based on sales of leased substances to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor or leased substances not sold in *476 an arms length transaction shall be determined based on prevailing values at the time in the area. Lessee shall have the obligation to disclose to Lessor any information pertinent to this determination. This section of the lease specifically contemplates that if the lessee sells the gas to an affiliate, the royalty shall “be determined based on prevailing values at the time in the area.” Paragraph 37 does not require the point of sale to be the point at which the gas is ultimately sold to a non-affiliated entity. The lessors argue that construing “point of sale” as the point where Chesapeake sells the gas to CEMI would frustrate the parties’ expectations and their reliance on the concurring opinion in Heritage. They rely on the following passage from the concurring opinion: There are any number of ways the parties could have provided that the lessee was to bear all costs of marketing the gas. If they had intended that the royalty owners would receive royalty based on the market value at the point of delivery or sale, they could have said so. 20 The concurring opinion emphasized that the parties to a lease “may allocate costs ... as they choose” and that courts must examine the specific language chosen in order to “determine how ... costs were allocated under [the] particular leases” at issue. 21 In this case, the language of the lease, including paragraph 37, make clear that the royalty due the lessors is a percentage of the market value of the gas at the point at which the lessee sells the gas. As discussed above, had Chesapeake sold the gas at a point downstream from the wellhead, then the royalty would be 1/4 of the market value of the gas at that point. Post-production cost incurred between the wellhead and the point of sale could not be deducted in arriving at the market value at the point of sale under either the “1/4” royalty sentence in the royalty clause of paragraph 11, or any other provision in the lease. But Chesapeake has sold the gas at the wellhead. That is the point of sale at which market value must be calculated under the terms of the lessors’ lease. C The lessors contend that the district court erred by relying on Heritage, asserting that the case has limited precedential value. They note that after the opinion in Heritage issued, one of the Justices who had joined the majority opinion recused himself. The other members of the Supreme Court of Texas split 4-4 in ruling on a motion for rehearing. An opinion dissenting from the denial of rehearing reflects that two of the Justices who had originally joined the majority opinion had changed position and had expressed their agreement with the original dissenting opinion. 22 The lessors argue that the Texas court was thus without a majority that agreed on the reasons supporting the judgment in Heritage. Because rehearing was denied, the court’s opinion in Heritage was not withdrawn. The Texas court’s decision in Heritage remains binding law, as the numerous cases from both the Supreme Court of Texas and this court citing that decision demonstrate. 23 *477 For the foregoing reasons, the judgment of the district court is AFFIRMED. Footnotes [1] 10 Ring Precision, Inc. v. Jones, 722 F.3d 711, 717 (5th Cir.2013) (citation omitted). [2] Id. (quoting Fed.R.Civ.P. 56(a)). [3] Miller v. BAC Home Loans Servicing, L.P., 726 F.3d 717, 721-22 (5th Cir.2013) (citations and internal quotation marks omitted). [4] See Clardy Mfg. Co. v. Marine Midland Bus. Loans Inc., 88 F.3d 347, 352 (5th Cir.1996) (“We look to state law to provide the rules of contract interpretation.”). [5] Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex.2005) (per curiam). [6] Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex.1996). [7] Id. [8] Id. [9] 939 S.W.2d 118 (Tex.1996). [10] Heritage, 939 S.W.2d at 120-21. [11] Id. [12] Id. at 123-24. [13] Id. at 122. [14] Id. [15] Id. [16] Id. [17] Id. at 120-21. [18] Id. at 130 (Owen, J., concurring). [19] See also Warren v. Chesapeake Exploration, L.L.C., No. 13-10619, 759 F.3d 413, 416-18, 2014 WL 3511880, at *3 (5th Cir.2014). [20] Heritage, 939 S.W.2d at 131 (Owen, J., concurring) (emphasis in original). [21] Id. at 124. [22] See Heritage Res., Inc. v. NationsBank, 960 S.W.2d 619, 619 (Tex.1997). [23] See, e.g., Ramming v. Natural Gas Pipeline Co. of Am., 390 F.3d 366, 372 (5th Cir.2004); El Paso Field Servs., L.P. v. MasTec N. Am., Inc., 389 S.W.3d 802, 808 (Tex.2012); Union Pac. Res. Grp., Inc. v. Hankins, 111 S.W.3d 69, 71 (Tex.2003).