Opinion
23-30860
01-06-2025
ELIZABETH FRY FRANKLIN; CYNTHIA FRY PEIRONNET, Plaintiffs-Appellees/Cross-Appellants, v. REGIONS BANK, Defendant-Appellant/Cross-Appellee.
Appeal from the United States District Court for the Western District of Louisiana USDC No. 5:16-CV-1152
Before SMITH, CLEMENT, and HIGGINSON, Circuit Judges.
EDITH BROWN CLEMENT, CIRCUIT JUDGE
This case involves a dispute between two lessors and the bank in charge of managing their mineral interests on a tract of property atop the Haynesville Shale in Louisiana. In 2007, Regions Bank accidentally extended a lease for drilling rights on this entire tract when the lessors only intended to convey rights to a portion. Advances in drilling technology drastically increased the value of the resource-rich tract in the years that followed, so the mistaken extension threatened to box the lessors out of the boom. But the lessors had their day in court.
In 2021, the district court held a bench trial and found Regions liable for breach of contract. On remand to determine the meaning of the lease's royalty provision for calculating the damages award, the district court considered extrinsic evidence and concluded that the parties intended the royalty to be calculated based on gross proceeds. The court fashioned its award of royalty damages accordingly, accounting for prejudgment interest on past losses and projected future losses discounted to present value.
We AFFIRM the district court's ruling that the lease conveyed a gross proceeds royalty and the admission of extrinsic evidence to reach this conclusion. However, we REVERSE the district court's award of royalty damages plus prejudgment interest and REMAND with instructions for the district court to consider evidence of actual loss data insofar as it is available for years past.
I.
Elizabeth Franklin and Cynthia Peironnet ("Landowners") own an undivided interest in an 1,805.34-acre tract of land in Caddo Parish, Louisiana. The tract sits above the Haynesville Shale, which is a rock formation deep below the surface containing significant quantities of natural gas. The Landowners each entered into agreements with Regions Bank ("Regions") to manage their mineral interests on the property. Regions subsequently negotiated and executed two leases and a lease extension on the Landowners' behalf.
In 2004, a Regions representative negotiated an oil-and-gas lease with Prestige Exploration, Inc. ("Prestige") on the entire tract for a three-year term. This lease provided for a $100.00 per acre bonus and royalties of 20% of gross proceeds received, or a fair and reasonable price, whichever was higher. The lease contained both a Pugh Clause, under which the lease automatically extended if the lessee had a well that was producing in paying quantities, and a depth-severance clause, under which the lease would lapse after three years as to all land 100 feet below the deepest depth drilled, even if there was a shallower well producing in paying quantities. Separately, a company known as Matador Resources ("Matador") had been developing an area above the Haynesville Shale known as the Cotton Valley formation. Shortly after entering the lease agreement, Prestige assigned its rights within the lease to Matador. Based on available technologies at the time, Matador only drilled in the Cotton Valley formation during the lease's term.
See Sandefer Oil & Gas, Inc. v. Duhon, 961 F.2d 1207, 1208 n.1 (5th Cir. 1992) (explaining the origin of the "Pugh Clause").
As the end of the lease term neared, only 168.95 acres were not producing in paying quantities. Because the lease was set to lapse on these undeveloped acres under the depth-severance clause, Matador sought an extension for this tract and ultimately reached an agreement through Regions for eighteen months at $75.00 per acre. But Regions' landman failed to proofread the document, and the extension executed by the parties provided Matador with mineral rights to the entirety of the 1,805.34 acres owned by the Landowners rather than only the undeveloped portion.
Because the extension and its inadvertent terms clouded the ability of the Landowners to lease deep drilling rights for the entire property, they sued Matador in state court. Specifically, the Landowners sought to rescind the lease extension for unilateral error or, in the alternative, reformation of the agreement for mutual mistake. The parties believed the state court litigation would result in the lease extension's invalidation.
Shortly after the Landowners entered into the faulty lease extension agreement, new technology emerged in early 2008 that allowed for extraction of natural gas within the resource-rich Haynesville Shale, the untapped, deeper formation below the Landowners' property. On May 7, 2008, after filing suit in state court to invalidate the inadvertent extension agreement with Matador-but well before the lawsuit had been resolved-Regions accepted an offer on behalf of the Landowners to enter two separate agreements with Petrohawk Energy Corporation ("Petrohawk") for drilling rights to the Haynesville Shale. Franklin v. Regions Bank (Franklin II), 37 F.4th 986, 992 (5th Cir. 2022). One agreement leased mineral rights on 1,636.39 disputed acres at $8,750.00 per acre with a royalty of 25%, contingent on Petrohawk's ability to lease all depths under the tract once the state court litigation with Matador concluded. The Landowners also executed a separate but identical agreement with Petrohawk for rights to 665.11 acres in a tract unaffected by the state court litigation described as "PX-12." The royalty provisions in both lease forms with Petrohawk provided:
Franklin v. Regions Bank (Franklin II), 37 F.4th 986, 989 (5th Cir. 2022) ("The farm sits atop the storied Haynesville Shale, one of the largest natural gas fields in the lower forty-eight states."); Kennedy v. Saheid, 51,044, p. 13 (La.App. 2 Cir. 11/16/16); 209 So.3d 985, 994 n.3 ("This court would take judicial notice that March 2008 marked the beginning of the land-leasing boom associated with the Haynesville Shale formation.").
The royalties to be paid by Lessee are . . . on gas, including casinghead gas, or other gaseous substance produced from said land and sold or used off the premises or for the extraction of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale ....Both leases also referenced an addendum to the agreement, formally described as Exhibit A. The addendum provided as follows:
In the event of a conflict between the language as stated in this Exhibit "A" and the language as stated hereinabove, the language in Exhibit "A" shall prevail.
* * *
It is hereby agreed and understood between the parties hereto that wherever the term one eighth (1/8) appears in the printed lease form attached hereinabove, said term is hereby deleted and the term 25% is inserted and substituted therefor[].
* * *
There shall be no cost charged to the royalty interest created under this lease, except severance and applicable taxes.
The parties agreed that the lease with Petrohawk on the disputed tract would only become effective if the state court litigation invalidated the inadvertent contract extension with Matador. The agreement for PX-12, however, became effective upon execution.
The state court case against Matador reached the Louisiana Supreme Court in 2013. Much to the parties' surprise, the court upheld the lease extension agreement the Landowners and Matador entered inadvertently as clear and unambiguous. See Peironnet v. Matador Res. Co., 2012-2292, p. 3536 (La. 6/28/13); 144 So.3d 791, 818. The state supreme court ruled that the 2007 extension agreement unambiguously extended the original 2004 lease for all 1,805.34 acres, including the deep rights. This meant Matador's lease prevailed, and Petrohawk could not drill into the Haynesville Shale, despite its lease with the Landowners for drilling rights on the 1,639.39-acre tract. Therefore, the Landowners could not receive royalties from Petrohawk on this tract because they were bound to the 2007 lease extension with Matador providing for a 20% royalty rate for extracted minerals rather than the 25% rate agreed upon with Petrohawk. The 665.11-acre tract known as PX-12, unaffected by the state court litigation, has been drilled by Petrohawk and has produced natural gas royalties pursuant to the agreement for more than a decade.
Payment stubs show that the Landowners have received a 25% royalty from the natural gas extracted from this tract "by multiplying gross sales by the royalty percentage (in decimal form), then subtracting only severance taxes."
II.
In 2016, the Landowners filed suit against Regions in the United States District Court for the Western District of Louisiana, alleging breach of contract. Specifically, the Landowners sought damages for mishandling the lease extension, which caused them to "receive 20% royalties under the 200[4] Matador lease instead of 25% royalt[ies] under the 2008 Petrohawk lease."
Regions moved to dismiss the claim, and the district court granted the motion on the basis that the applicable prescriptive period for tort claims time-barred the Landowners' claim. Franklin v. Regions Bank, NO. 16-1152, 2019 WL 3491643, at *6 (W.D. La. July 12, 2019), report and recommendation adopted by NO. 16-1152, 2019 WL 3484046 (W.D. La. July 31, 2019), reversed and remanded, Franklin v. Regions Bank (Franklin I), 976 F.3d 443, 450 (5th Cir. 2020). Determining that the Landowners' claim was based in contract rather than tort, this court reversed and remanded the case for trial. Franklin v. Regions Bank (Franklin I), 976 F.3d 443, 450 (5th Cir. 2020).
Shortly thereafter, during the bench trial in April 2021, the Landowners argued that the Petrohawk lease provided for a 25% gross proceeds royalty-calculated by multiplying price and quantity of natural gas sold without subtracting post-production costs-after accounting for the addendum's controlling language. The Landowners argued, additionally, that extrinsic evidence could prove their no-cost interpretation. However, the district court refused to consider any extrinsic evidence, noting that the royalty provision could be interpreted based on the four corners of the agreement and the existing record.
The district court ultimately found that Regions, through its representative, breached its duty of care in failing to limit the lease extension to the 168.95-acre tract and its deep rights. However, the district court found that the exculpatory clause released Regions from liability because its employee made a "mistake in judgment" that did not constitute willful or gross negligence. The court further noted that the Landowners would have received the same lease value (not royalty value) even if a breach had not occurred.
Additionally, the district court determined that the cloud on the title caused by the lease extension litigation did not result in damages to the Landowners. The court reasoned that even if there had been no lease extension agreement, Petrohawk would have made the same offer that Regions accepted on the Landowners' behalf. For reasons unknown, the district court avoided any discussion of royalty damages.
On appeal, a panel from this court reversed the district court's determination that the exculpatory clause in the agreement with the Landowners shielded Regions from liability. Franklin II, 37 F.4th at 994-95. It also determined that the district court did not clearly err in its determination that the Landowners suffered no "lease bonus damages." Id. at 995. But because the district court failed to address whether the Landowners sustained royalty damages, the panel remanded for resolution of that issue. Id. at 995-96.
On remand, the district court advised the parties that the case would be "reopened for the limited purpose of introducing extrinsic evidence to determine the intent of the parties as to the royalty provisions in the 2008 Petrohawk lease." The district court originally announced that it planned to bifurcate the remaining proceedings and would set a "separate hearing" to "address the issue of [royalty] damages" after holding a hearing to determine the royalty provision's meaning. Indeed, the district court held a hearing in June 2023 and admitted additional evidence to supplement its analysis of the royalty provision.
After concluding that the parties intended to create a royalty based on gross proceeds by incorporating Exhibit A, however, the district court ruled that "[n]o additional evidence or testimony [would] be allowed in making the damage determination." Instead, the district court proclaimed that "[a]rguments should be made by the parties based on the evidence and testimony previously submitted." This foreclosed the opportunity for the parties to submit evidence and testimony outside of the trial record from multiple years prior.
In October 2023, the district court ultimately awarded the Landowners $3,450,272.00 in "past royalty damages" for 2009 to 2017 and $954,101.60 in "future royalty damages" from 2018 to end-of-well-life based on damages estimates. It also awarded prejudgment interest on past lost royalties, starting at each year's end, but limited post-judgment interest to future lost royalties.
Damages were awarded based on a report prepared in May 2019 by Robert McGowen, the Landowners' expert, prior to the April 2021 bench trial. In this report, McGowen relied upon "actual data for the years 2009-2017" and he then calculated a "future" annualized lost royalty for 2018 through the end-of-well-life, which was determined to be 2031. His report adjusted lost royalty damages in each future year to present value. Importantly, this report lacked actual loss data for any year after 2017 because McGowen prepared it in anticipation of the originally scheduled 2019 trial date before the district court erroneously granted Regions' motion to dismiss.
The Landowners subsequently moved to amend or correct the judgment because it failed to reflect the most recent data from updated expert reports and depositions, as well as to have the district court make additional findings to avoid projecting royalty damages sustained in 2018, 2019, 2020, 2021, or 2022 as "future" royalties. The district court amended its judgment in part, noting that post-judgment interest would accrue on the full award. The court doubled down on its projected award of "future" lost royalties, observing that the royalty issue had been properly "decided according to the record from the April 2021 trial" and allowed consideration of "no further evidence . . . regarding damages." Despite acknowledging the availability of actual loss data for multiple years in the past, the court instead relied upon projections for those years.
Regions timely appealed the district court's ruling that the lease conveyed a royalty based on gross proceeds, as well as the court's award of prejudgment interest for lost royalties sustained in the years before the Landowners filed suit. The Landowners cross-appealed the district court's calculation of royalty damages, arguing the district court improperly calculated the award after refusing to consider supplementary expert evidence showing actual losses for years in the past that the court estimated as "future" damages.
III.
A.
At the outset, we must determine whether the district court properly held that the Exhibit A addendum rendered ambiguous the meaning of the royalty provision in the lease form.
Interpretation of a contract is a legal question subject to de novo review, "including the question of whether the contract is ambiguous." Greenwood 950, L.L.C. v. Chesapeake La., L.P., 683 F.3d 666, 668 (5th Cir. 2012). Louisiana law governs the interpretation of oil-and-gas contracts in a diversity case such as this one, Ramming v. Nat. Gas Pipeline Co. of Am., 390 F.3d 366, 372 (5th Cir. 2004) (per curiam), and a district court's interpretation of state law is reviewed de novo, Am. Bankers Ins. Co. of Fla. v. Inman, 436 F.3d 490, 492 (5th Cir. 2006). However, "[i]f the interpretation of the contract turns on the consideration of extrinsic evidence, such as evidence of the intent of the parties," we review for clear error. Comar Marine, Corp. v. Raider Marine Logistics, L.L.C., 792 F.3d 564, 578 (5th Cir. 2015) (quoting Nat'l Union Fire Ins. Co. v. Circle, Inc., 915 F.2d 986, 989 (5th Cir. 1990) (per curiam)).
Under Louisiana law, "[a] mineral lease is a contract by which the lessee is granted the right to explore for and produce minerals." LA. REV. STAT. § 31:114. "Interpretation of a contract is the determination of the [parties'] common intent," LA. CIV. CODE art. 2045, that "starts with the language of the Agreement." Gulf Eng'g Co. v. Dow Chem. Co., 961 F.3d 763, 767 (5th Cir. 2020) (citing Six Flags, Inc. v. Westchester Surplus Lines Ins. Co., 565 F.3d 948, 954 (5th Cir. 2009)). The terms in a contract "must be given their generally prevailing meaning." LA. CIV. CODE art. 2047. If the terms are clear "and lead to no absurd consequences," additional interpretation is unnecessary to determine the parties' intent. Gulf Eng'g Co., 961 F.3d at 767 (internal quotations omitted).
On the other hand, "[a] contract is considered ambiguous on the issue of intent . . . when the language used in the contract is uncertain or is fairly susceptible to more than one interpretation." Blanchard v. Pan-OK Prod. Co., 32,764, p. 7 (La.App. 2 Cir. 4/5/00); 755 So.2d 376, 381. Under Louisiana law, "[a] doubtful provision must be interpreted in light of the nature of the contract, equity, usages, the conduct of the parties before and after the formation of the contract, and of other contracts of a like nature between the same parties." LA. CIV. CODE art. 2053. If "there is ambiguity in the written expression of the parties' common intent," a district court may consider parol or extrinsic evidence to determine the meaning. Blanchard, 755 So.2d at 381.
Admission of expert testimony, for example, is "prudent" for explaining the technical and customary meaning of ambiguous terms. Phillips Oil Co. v. OKC Corp., 812 F.2d 265, 281 (5th Cir. 1987); Greenwood 950, 683 F.3d at 668.
In Louisiana, a lessor's royalty profit from an oil-and-gas lease is calculated based on either its market value at the well or gross proceeds. A royalty calculated at the well generally "subtract[s] reasonable postproduction marketing costs from the market value at the point of sale." Ramming, 390 F.3d at 372. On the other hand, a royalty calculated based on gross proceeds simply multiplies the market price by the quantity sold without subtracting post-production costs. PATRICK S. OTTINGER, LOUISIANA MINERAL LEASES: A TREATISE, § 5-14, at 707-11 (2016).
In relevant part, the Petrohawk lease form provided that "[t]he royalties to be paid by Lessee are . . . [calculated using] the market value at the well." But the subsequently incorporated addendum included limiting language, providing that "[t]here shall be no cost charged to the royalty interest created under this lease, except severance and applicable taxes." The addendum also included language stating that its terms "shall prevail" over the language in the lease.
According to Regions, the addendum does nothing to change the point at which the royalty is calculated based in part on this court's decision in Warren v. Chesapeake Exploration, L.L.C., 759 F.3d 413 (5th Cir. 2014) (determining a royalty based on its market value at the well despite an addendum's no-cost clause). In the bank's view, the addendum does not alter the nature of the royalty, so the Landowners remain responsible for their share of post-production costs in accordance with Warren. The only effect of the addendum, according to Regions, is to provide that severance and other applicable taxes can be withheld from the royalty payment after accounting for the lessor's share of post-production costs assessed at the well.
The Landowners disagree, theorizing that the addendum's language transformed the character of the royalty from a market at the well provision to a royalty based on gross proceeds. They contend that the language in the addendum expressly overrides the lease form by clarifying that all deductions, including the assessment of post-production costs, to the royalty interest are prohibited-"except for severance and applicable taxes."
Each party's construction is logically plausible from the contractual terms, but neither squarely settles the matter. Indeed, the parties did not use express language in the addendum altering the royalty's calculation from its market value at the well to gross proceeds, although the no-cost clause prohibiting deductions from the "royalty interest" is intended to prevail over any contradictory language in the lease form. And despite the addendum stating that no costs except those identified can be charged to the "royalty interest," it is not apparent at what point in the post-extraction process that figure is calculated-or whether certain costs can be deducted before determining this figure. What is clear, however, is that the competing expressions in the leasing instruments render the overall meaning of the royalty provision "fairly susceptible to more than one interpretation." Blanchard, 755 So.2d at 381. Therefore, the district court properly deemed the royalty provision ambiguous.
B.
To determine the ambiguous provision's intended meaning, the district court considered conflicting testimony from expert and fact witnesses regarding whether the parties incorporated the addendum to convert the lease from a royalty determined by its "market value at the well" to a calculation based on "gross proceeds." Franklin v. Regions Bank, No. 5:16-CV-01152, 2023 WL 5309908, at *5 (W.D. La. Aug. 17, 2023).
First, Edward Waller, who served as a Regions property manager, testified that he was tasked with obtaining as much money as possible for his clients at the lease-negotiation stage. He also emphasized that part of his role was to ensure the proper allocation of royalties. After reviewing the Landowners' parallel lease for PX-12, which Petrohawk treated as a grossproceeds lease, Waller testified that Exhibit A demonstrated the drafter's intentions of converting the lease's royalty provision to gross proceeds. Waller also explained that "a cost-free lease [is] basically a gross proceeds lease" because the industry uses the terms "interchangeably."
Joey Hand served as Senior Vice President, Oil &Gas Property Manager at Regions, and as the property manager for the Landowners. He was involved in negotiations over the two leases the Landowners made with Petrohawk. He testified that the intent behind Exhibit A in both contracts was to convert the royalty provisions to a gross-proceeds calculation, even though Hand observed that "he did not think that he accomplished that." Hand also testified that he sought to get the Landowners "a better deal than [he] had ever gotten them before."
Robert McGowen, a petroleum engineer retained by the Landowners, testified that it is customary in the oil-and-gas industry for an addendum to override terms in a standard lease form. He also testified that he reviewed monthly payment records and annual reports regarding the PX-12 lease, noting that those records showed Petrohawk paid royalties to the Landowners without deducting post-production costs. McGowen also testified that he never reviewed evidence that suggested Regions' trust department disagreed with this structuring of royalty payments for royalties on PX-12.
John D. Collinsworth is a professional landman familiar with customary and industry uses of terms within mineral leases in northwest Louisiana. Relying on his industry experience, Collinsworth testified that the language in Exhibit A for PX-12, as well as the lease at issue in this case with identical language, reflected a "gross proceeds" royalty provision. He also explained that the terms "cost-free" and "gross proceeds" "mean the same thing."
Finally, the district court referenced prior testimony from financial analyst David Fuller. During the 2021 trial, Fuller testified that the lease form undoubtedly created a royalty provision that deducted post-production costs. He also testified that if the parties had intended to change the royalty provision's character, they could have done so with express language to that effect.
Aside from witness testimony, the district court also considered evidence of Petrohawk's history of royalty payments for natural gas extracted on the PX-12 tract with an identical lease and addendum. Under Louisiana law, "the conduct of the parties informs an unclear contract," Jones v. Adm'rs of Tulane Educ. Fund, 51 F.4th 101, 116 (5th Cir. 2022), and "[a] course of dealings between parties . . . give[s] particular meaning to and supplement[s] or qualif[ies] terms of an agreement," LA. CIV. CODE art. 2053 cmt. e (internal quotations omitted). In Petrohawk's thirteen years of payments on PX-12, the company had not subtracted costs before paying a 25% royalty on natural gas extracted and sold from that tract. The district court considered this payment history as evidence that Petrohawk, and the Landowners, understood that the identical addendum's royalty terms prevailed.
Ultimately, the district court ruled that the weight of extrinsic evidence suggested the parties intended the addendum to prevail over the lease form by providing for a royalty based on gross proceeds. As explained above, this ruling is subject to a clear-error standard of review. Regions failed to identify any clear error in the district court's evidentiary analysis.
C.
Nonetheless, Regions argues that we are bound as a matter of law by this court's decision in Warren v. Chesapeake Exploration, L.L.C., 759 F.3d 413 (5th Cir. 2014), to hold that the royalty should be calculated based on its market value at the well where post-production costs are generally shared between lessor and lessee.
This court in Warren construed three oil-and-gas leases "as a single contract" because the relevant contractual language was identical. Id. at 415. The contract described a royalty based on the "amount realized by Lessee, computed at the mouth of the well." Id. at 417 (internal quotations omitted). Such language meant the royalty would be based on net proceeds, "and the physical point . . . used as the basis for calculating net proceeds [became] the mouth of the well." Id. at 417-18. Therefore, Chesapeake Exploration's royalty obligation to the Warrens became based on "the amount of proceeds computed at the mouth of the well, which mean[t] proceeds net of reasonable post-production costs incurred beyond the mouth of the well." Id. at 419.
Additionally, "the phrase 'net proceeds' contemplates deductions." Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 136 (Tex. 1996).
Interpreting Texas law, this court analyzed the Texas Supreme Court's decision in Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996), a ruling which invalidated a clause that limited post-production costs to the operator. Id. at 122-23. Because of Heritage, deducting postproduction costs from a royalty in "at the well" leases before payment to the lessor had been the long-standing default rule in Texas. Id. Although an addendum to the contract at issue in Warren contained a clause prohibiting the deduction of certain post-production costs from the royalty, the addendum did not alter the character of the contract's royalty provision because its terms were "not inconsistent with the royalty clause in the preprinted lease." Warren, 759 F.3d at 417-19. Pursuant to Texas law, the addendum "did not change the point at which the royalty was computed," which was at the mouth of the well. Id. at 418.
The Heritage decision broadly has stood for the proposition that the commonly understood terms "royalty" and "market value at the well" referenced in oil-and-gas leases in Texas rendered clauses allocating postproduction costs "surplusage as a matter of law." Heritage, 939 S.W.2d at 123. There was a time in practice when this effectively placed a straitjacket on the point at which "at the well" royalties were calculated in the state, presuming that both lessor and lessee would share post-production costs.But Warren's logic, imported partly from Heritage, does not indiscriminately extend to mineral leases executed outside Texas.
See OTTINGER, supra, § 5-14, at 710. The Texas Supreme Court later weakened the default rule in Heritage after this court decided Warren. In Chesapeake Exploration, L.L.C. v. Hyder, 483 S.W.3d 870 (Tex. 2016), for example, the state supreme court made clear that Heritage does not require a lessor to bear a proportional share of post-production costs where the mineral lease clearly manifests a contrary intent. Id. at 876.
Aside from Warren's inapplicability here, we emphasize that the royalty provision governing the Landowners' lease is structured differently. Cf. Warren, 759 F.3d at 416 ("[A]ll royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing . . . including, but not limited to, costs of compression, dehydration, treatment and transportation."). As this court has discerned, "different royalty provisions have different meanings," and there are no "established immutable rules for construing 'at the well' royalty provisions" across this circuit. Id. at 416-17. Courts instead must "careful[ly] examin[e] . . . the various terms and phrases the parties use" under relevant state law. Id. at 417.
The addendum further provided that the "Lessor will, however, bear a proportionate part of all those expenses imposed upon Lessee by its gas sale contract to the extent incurred subsequent to those that are obligations of Lessee."
The relevant oil-and-gas law in this case flows from Louisiana. The royalty owed to a landowner generally "attaches to the oil and gas produced at the surface when such products are captured, or are brought 'under physical control,' at the wellhead in this state." Louisiana's default rule for royalty calculations was determined in Wall v. United Gas Public Service Co., 152 So. 561 (La. 1934). The dispute focused on where the royalty should be calculated because "nothing in the contract itself . . . touch[ed] the question whether the term 'market price' meant the price at the well or the price the gas would bring in a market remote from the well." Id. at 563.
Patrick S. Ottinger, A Funny Thing Happened at the Wellhead: "Post-Production Costs" and Responsibility Therefor, 8 LSU J. ENERGY L. & RES. 13 (2020); see also OTTINGER, supra, § 4-25, at 534 (citing LA. REV. STAT. § 31:7).
The Louisiana Supreme Court in Wall identified two methods for determining market value calculated at the well. Id. at 563-64. The first method accounts for comparable sales in the area near the well. Id. But courts have acknowledged generally that "gas at the wellhead is of no value until it is marketed and transported to the purchaser." Culpepper v. EOG Res. Inc., 47,154, p. 4 (La.App. 2 Cir. 5/16/12); 92 So.3d 1141, 1144. The second method, described as the "the Louisiana approach," is an effort to reconstruct market value where the operator may deduct post-production costs from the sales price before paying the royalty to the landowner. Freeland v. Sun Oil Co., 277 F.2d 154, 157-59 (5th Cir. 1960). Market value is reconstructed by starting with the gross proceeds from the sale of the mineral and deducting any additional costs of taking the mineral from the wellhead to the point of sale. Merritt v. Sw. Elec. Power Co., 499 So.2d 210, 213 (La. Ct. App. 1986). In other words, "all increase in the ultimate sales value attributable to the expenses incurred in transporting and processing the commodity must [generally] be deducted." Freeland, 277 F.2d at 159.
Shared responsibility of post-production costs remains the default rule in Louisiana like its sister states within this circuit. But Louisiana's default rule for determining the owed royalty in "at the well" oil-and-gas leases is flexible. Indeed, in Louisiana Mineral Leases: A Treatise, Patrick Ottinger observed room for movement in the joints, noting that "unless the mineral lease provides to the contrary, the lessor's royalty share is responsible for its proportionate part of the post-production costs" incurred as part of "efforts to make the product marketable." Therefore, when determining a royalty payment, the landowner presumptively shares in what remains after post-production costs are deducted unless the leasing agreement directs otherwise.
OTTINGER, supra, § 5-14, at 707 (emphasis added).
Indeed, the Louisiana Court of Appeals in Merritt emphasized the freedom to contract by allowing parties to opt out of the default rule. 499 So.2d at 214. The court underscored that "[u]nless the parties agree otherwise, the cost of marketing gas once it has been produced is shared by the lessor and lessee under a market-value lease." Id. (emphasis added). As Ottinger chronicled, such "agree otherwise" language often has been given effect by incorporating a no-cost clause to demonstrate that the parties intend to depart from the status quo.
Id. at 708.
Id. § 4-25, at 565.
Post-production cost allocation is therefore discretionary between parties in structuring an oil-and-gas royalty under Louisiana law. This contractual freedom "operates fully in respect of the issue of 'postproduction costs,' as there are no issues of public policy that would deny the parties the ability to construct their own bargain." For example, this court in Columbine II Ltd. Partnership v. Energen Resources Corp., 129 Fed.Appx. 119 (5th Cir. 2005) (per curiam), upheld the parties' departure from Louisiana's default rule when they contractually prohibited the assessment of postproduction costs in a sublease despite the underlying lease's silence on such costs. Id. at 122-23.
Id. at 564.
We apply these principles of Louisiana oil-and-gas law with this landscape as the backdrop. Like the lease in Freeland, the Petrohawk lease form originally provided for royalties calculated at the "market value of the well of [25%] of the gas so sold or used, provided that on gas sold at the wells the royalty shall be [25%] of the amount realized from such sale." Viewing this language in isolation, a proportionate share of costs "should be deducted before computing and delivering the lessor's royalty" based on the reconstruction approach embraced by Louisiana law. Freeland, 277 F.2d at 158 (internal quotations omitted). But the parties included additional language in the addendum, exercising the contractual freedom that Louisiana law accommodates by disallowing the deduction of post-production costs after determining the royalty interest. In other words, they expressly declined to allocate a share of post-production costs to the lessor.
This arrangement comports with the process outlined in Ottinger's treatise, where he identifies "three distinct components . . . pertinent to the calculation of royalties due to the lessor [i.e., landowner] under a mineral lease." These steps are described as follows:
Id. § 4-25, at 508.
(1) the parties should start with the agreed upon "fraction (or decimal or percentage) interest specified";
(2) the parties should calculate "the benchmark by which the lessee is to determine the monetary price (generated by the sale or other disposition of the product) to which the stated fraction is to be applied"; and
(3) the parties should consider "whether the lessee is permitted to deduct from the [landowner's] royalty share, any portion of costs and expenses incurred by the lessee."
Id.
The first step is straightforward. To calculate the benchmark at the second step, the parties are directed to "multiply[] the quantity of oil or gas sold by the lessee, times the per unit price paid for the product." This determines the royalty interest. Therefore, after an operator has determined the gross proceeds from its product sales, it can deduct "any portion of costs and expenses" from the lessor's royalty at step three.
Id. at 508 n.746.
Id. Ottinger observes that generally "[t]he functional point at which the royalty interest of the lessor attaches . . . under an 'at the well' lease" is where the "[m]inerals are reduced to possession" and "under physical control that permits delivery to another." Id. at 533-34 (citing LA. REV. STAT. § 31:7). For leases determined by "market value at the well," the royalty is generally calculated using the reconstruction approach to "reverse determine" market value by accounting for post-production costs, unless the contract dictates otherwise. Id. at 534.
Id. at 508.
At step three, we agree with the Landowners that the lease addendum, whose terms "shall prevail" over the language in the lease form, plainly means what it says. The addendum states that "[t]here shall be no cost charged to the royalty interest created under this lease, except for severance and applicable taxes," prohibiting any deduction otherwise. Therefore, any deduction of post-production costs from the royalty interest determined at the second step is prohibited. This reading aligns with the district court's evidentiary determination that the addendum created a royalty based on gross proceeds.
Although Regions resists the applicability of Louisiana law, the law of the forum state is undeniably controlling in this diversity case. And in Louisiana, no legislative or judicial decree prohibits an arrangement allowing lessors to avoid their share of post-production costs. Indeed, Ottinger noted historically that "many operators based in Texas, but operating in Louisiana, [were] surprised that the default rule of Heritage [did] not prevail in Louisiana." This should not surprise Regions since the bank's own landman negotiated the faulty lease extension with operators in the latter state. In Louisiana, nothing prevents parties from contracting out of the default rule by prohibiting the deduction of post-production costs from the lessor's cut if they so choose. In this case, they did.
Id. § 5-15, at 711.
* * *
As stated above, the district court arrived at an interpretation of the royalty provision supported by the bulk of extrinsic evidence without committing clear error. This evidentiary interpretation likewise comports with Louisiana oil-and-gas law. We therefore find no reversible error in the district court's determination that the parties intended the royalty to be calculated based on gross proceeds.
IV.
Regions also challenges the district court's decision to consider previously unadmitted extrinsic evidence for determining the meaning of the royalty provision on remand.
"We review de novo a district court's interpretation of a remand order, including whether the law-of-the[-]case doctrine or mandate rule forecloses any of the district court's actions on remand." Lion Elastomers, L.L.C. v. NLRB, 108 F.4th 252, 257 (5th Cir. 2024) (alteration in original) (quoting Gen. Universal Sys., Inc. v. HAL, Inc., 500 F.3d 444, 453 (5th Cir. 2007)).
Briefly recounting relevant procedural history is useful. This court previously held that Regions' negligence left the Landowners "with the 20% royalty rate from the original lease, depriving them of the 25% rate from the Petrohawk lease." Franklin II, 37 F.4th at 995. This court also noted that the "the district court did not address" how the appropriate royalty rate applied "or make any credibility or fact findings regarding the dueling experts," prompting the most recent remand. Id. at 996. Confronting the royalty damages question directly in response, the district court requested briefing from the parties and held a hearing to consider extrinsic evidence for determining the meaning of the agreement's royalty provision.
Regions argues by determining the lease royalty clause to be ambiguous and allowing the introduction of extrinsic evidence to resolve the ambiguity, the district court violated the law-of-the-case doctrine. This doctrine dictates that "a decision of a legal issue or issues by an appellate court establishes the 'law of the case' and must be followed in all subsequent proceedings in the same case in the trial court or on a later appeal in the appellate court." White v. Murtha, 377 F.2d 428, 431-32 (5th Cir. 1967); see also K.P. v. LeBlanc, 729 F.3d 427, 436 (5th Cir. 2013) (noting the law-of-the-case "rule provides that an issue of law or fact decided on appeal may not be reexamined either by the district court on remand or by the appellate court on a subsequent appeal" (internal quotations omitted)). A district court is required to "abstain[] from reexamining an issue of fact or law that has already been decided on appeal." Perez v. Stevens, 784 F.3d 276, 280 (5th Cir. 2015) (per curiam) (quoting United States v. Teel, 691 F.3d 578, 582 (5th Cir. 2012)).
Application of the doctrine is discretionary, and it is "more likely to apply . . . when the prior opinion was apparently well-considered." USPPS, Ltd. v. Avery Dennison Corp., 647 F.3d 274, 283-84 (5th Cir. 2011) (citing Trans World Airlines, Inc. v. Morales, 949 F.2d 141, 144 (5th Cir. 1991)) (per curiam), aff'd in part, rev'd in part sub nom. Morales v. Trans World Airlines, Inc., 504 U.S. 374 (1992)).
Relatedly, "[t]he mandate rule requires a district court on remand to effect our mandate and to do nothing else." Deutsche Bank Nat'l Trust v. Burke, 902 F.3d 548, 551 (5th Cir. 2018) (per curiam) (quoting Gen. Universal Sys., Inc., 500 F.3d at 453). "Because the mandate rule is a corollary of the law of the case doctrine, it compels compliance on remand with the dictates of a superior court and forecloses relitigation of issues expressly or impliedly decided by the appellate court." Id. (cleaned up).
In no uncertain terms, this court previously remanded the case solely because "the district court did not address [the royalty] or make any credibility or fact findings regarding the dueling experts." Franklin II, 37 F.4th at 996. This court also recounted that "the district court did not squarely address [the Landowners'] second damages theory-namely, that [Regions'] error stuck them with the 20% royalty rate from the original lease, depriving them of the 25% [royalty] rate from the Petrohawk lease." Id. at 995. Without any explanation when rendering the damages award, the district court simply ignored the royalty damages question until this court directed it to answer.
It is difficult to square how the law-of-the-case doctrine or the mandate rule could bar adjudication of an issue that has gone previously unaddressed. Nonetheless, Regions contends that JackedUp, L.L.C. v. Sara Lee Corp., 807 Fed.Appx. 344 (5th Cir. 2020) (per curiam), is controlling. In Jacked Up, this court held that the district court correctly refused to consider new theories of damages or evidence on remand after receiving "specific and explicit instructions regarding how to proceed on remand." Id. at 350; see also Henderson v. Stalder, 407 F.3d 351, 354 (5th Cir. 2005) ("Where, as here, further proceedings in the district court are specified in the mandate of the Court of Appeals, the district court is limited to holding such as are directed." (quoting Crowe v. Smith, 261 F.3d 558, 562 (5th Cir. 2001))). Regions seemingly reads this to suggest that district courts cannot ever consider new theories of damages or damage evidence on remand.
Such a reading runs headlong into this court's precedent, previously accepted practices, and common sense. See, e.g., United States v. Wilson, 322 F.3d 353, 360 (5th Cir. 2003) (noting "the court's prior opinion obviously contemplated the taking of additional evidence" on remand); see also Box v. Dallas Mexican Consulate Gen., 623 Fed.Appx. 649, 654 (5th Cir. 2015) (per curiam) (observing that Wilson suggests, "[a]bsent limitation in the remand, the district court [was] free to admit additional evidence and conduct all necessary review of the claims on any grounds before it" (internal quotations omitted)). As we have said before, "[w]here further proceedings are contemplated by an appellate opinion, the district court retains the discretion to admit additional evidence," United States v. Bell Petrol. Servs., Inc., 64 F.3d 202, 204 (5th Cir. 1995), unless bound by a specific mandate that restricts subsequent proceedings. Wilson, 322 F.3d at 360.
Regions ignores that the remand instruction in Jacked Up provided express guardrails for the district court. Not so here, where the previous panel provided no specific instruction or limitation regarding what theories or evidence could be admitted and considered in determining royalty damages. The remand simply tasked the district court with answering a question it previously ignored. The district court therefore properly admitted and considered extrinsic evidence as it attempted to determine the royalty provision's intended meaning.
Accordingly, we find no reversible legal error.
V.
The final issue involves the proper calculation of annualized royalty damages Regions owes to the Landowners after being found liable for breach of contract. Because the tract at issue has continued to produce natural gas during this protracted litigation, the losses are ongoing. Therefore, the appropriate calculation depends on the availability of actual production and commercial data at critical points in this case that has spanned nearly a decade. In short, the issue is complex.
We start with the basics. In 2023, the district court fashioned its damages award based on expert Robert McGowen's 2019 report submitted as evidence in the original bench trial in 2021. In this report, McGowen calculated past lost royalty damages for years 2009 to 2017 based on actual production data, as well as "future" lost royalty damages based on projections between 2018 and the end-of-well-life in 2031. Naturally, the passage of time has brought with it actual loss data for years since 2018 that were previously categorized and calculated as "future" losses. The district court, however, saw no availing justification to account for the Landowners' actual losses during these years, even though such data was available at the time it fashioned the damages award.
In denying the Landowners' motion to modify the award to account for newly available data, the district court noted succinctly that McGowen "did not update the damages [amount] for past damages from 2018 to April 2021 at the April 2021 trial. Neither will this Court."
Specifically, the Landowners contend that the court failed to base its damages award on evidence showing actual royalty losses in years 2018, 2019, 2020, 2021, and 2022, and then compounded that error by present-value discounting and refusing to award prejudgment interest for those years now in the past. They argue that the district court's refusal to consider McGowen's supplemental report in rendering its damages determination constitutes reversible error. We agree.
The "validity of various damages measures" is "[a] purely legal question[] . . . review[ed] . . . de novo." Hoffman v. L &M Arts, 838 F.3d 568, 581 (5th Cir. 2016). Absent legal error, "the award of damages is a finding of fact reviewed for clear error." Tex. A&M Rsch. Found. v. Magna Transp., Inc., 338 F.3d 394, 404 (5th Cir. 2003); see also Luwisch v. Am. Marine Corp., 956 F.3d 320, 326 (5th Cir. 2020) (per curiam) (acknowledging that "findings of fact are reviewed for clear error," including the "calculation of damages" (internal quotations omitted)). "A finding is clearly erroneous if it is without substantial evidence to support it, the court misinterpreted the effect of the evidence, or this court is convinced that the findings are against the preponderance of credible testimony." French v. Allstate Indem. Co., 637 F.3d 571, 577 (5th Cir. 2011) (quoting Becker v. Tidewater, Inc., 586 F.3d 358, 365 (5th Cir. 2009)). This court should "reverse under the clearly erroneous standard 'only if [there is] a definite and firm conviction that a mistake has been committed.'" Id. (quoting Canal Barge Co. v. Torco Oil Co., 220 F.3d 370, 375 (5th Cir. 2000)).
A.
Louisiana law governs the royalty damages calculation. In Louisiana, damages from a breach of contract are "measured by the loss sustained by the obligee and the profit of which [s]he has been deprived." LA. CIV. CODE art. 1995. "The plain language of this article requires that damages include whatever profit the plaintiff may have lost," Amoco Prod. Co. v. Texaco, Inc., 2002-240, p. 22 (La.App. 3 Cir. 1/29/03); 838 So.2d 821, 837, or the amount of "actual loss" sustained, Apache Deepwater, L.L.C. v. W&T Offshore, Inc., 930 F.3d 647, 658-59 (5th Cir. 2019).
Louisiana law prioritizes "direct evidence [of] the exact extent of loss caused by a breach of contract" when measuring damages, including lost profit damages. Arthur J. Gallagher &Co. v. Babcock, 703 F.3d 284, 293 (5th Cir. 2012) (quoting White Haute, LLC v. Mayo, 09-955, p. 13 (La.App. 5 Cir. 3/23/10); 38 So.3d 944, 952). Louisiana law further requires that proof of actual lost profits be "as precise as circumstances in a particular situation allow," Citadel Broad. Corp. v. Axis U.S. Ins. Co., 2014-0326, p. 4 (La.App. 4 Cir. 2/11/15); 162 So.3d 470, 475, and the lost profits be proven with "reasonable certainty," Simpson v. Restructure Petrol. Mktg. Servs., Inc., 36,508, p. 6 (La.App. 2 Cir. 10/23/02); 830 So.2d 480, 484. However, because lost profits are "often difficult to prove and mathematical certainty or precision is not required," courts give parties "[b]road latitude . . . in proving lost profits." Brecheen v. News Grp., L.P., 11-1173, p. 28 (La.App. 5 Cir. 12/11/12); 105 So.3d 1011, 1029-30. "When damages are insusceptible of precise measurement, much discretion [is] left to the court for the reasonable assessment of these damages." LA. CIV. CODE art. 1999.
In announcing the royalty damages award, the district court noted that it "intended on the introduction of expert reports for the purpose[] of the ambiguous provisions of the 2008 Petrohawk lease, not as to damages." The district court also observed that it "never allowed the introduction of supplemental reports as to damages after the April 2021 trial," finding "no reason not to use McGowen's past royalty figures" and his "future royalty analysis."
Therefore, the district court proceeded without considering available historic evidence of actual losses sustained by the Landowners during multiple years in the past, despite broad agreement amongst the parties' experts regarding its utility. As a practical matter, Regions' expert, David Fuller, seemingly agreed with McGowen's approach of using available evidence of actual losses to calculate damages for years now in the past instead of continuing to project them as estimates. Fuller even adjusted his damages analysis in response to McGowen's supplemental report on remand by classifying the annualized royalties from 2009 through 2022 as "historical" damages and the annual royalties from 2023 forward as "future" damages. He also explained that the preferred measure of lost profits in Louisiana depends on the "most recent information" "only [now] available due to the passage of time" because "volumes that were estimated . . . are now actual."
Not only did the district court refuse consideration of actual loss evidence, but it failed to cite any authority justifying its calculation of lost profit damages pursuant to Louisiana law. The court merely "surmised that the royalty issue should be decided according to the record from the April 2021." In the end, the district court awarded the Landowners $3,450,272 in past royalty damages based on production history from 2009 to 2017 and $954,101.60 in projected future lost royalty damages from 2018 to the end-of-well-life. The district court also awarded prejudgment interest on the annualized royalties between 2009 and 2017, along with an amended grant of post-judgment interest on the entire royalty damages award.
We emphasize that courts in Louisiana are directed to award the "the loss sustained" when such a computation is feasible. See LA. CIV. CODE art. 1995. And under Louisiana law, "[i]n cases where direct evidence is not available to establish the exact extent of loss caused by a breach of contract," only then may courts rely upon "foreseeable profit as [the appropriate] measure of damages." Arthur J. Gallagher &Co., 703 F.3d at 293 (internal quotations omitted).
The record reveals that the Landowners offered, and the district court rejected, direct evidence of actual losses sustained between 2018 and 2022. This means that production data demonstrating the extent of royalty damages sustained by the Landowners during these years was available but ignored by the district court. In short, the refusal to consider this evidence sidestepped Louisiana law. This error subsequently resulted in an unduly deflated award, thereby failing to compensate the injured party for the losses sustained, when the court adjusted the miscategorized "future" years between 2018 and 2022 to present value.
B.
It has been observed that "[a]warding prejudgment interest and discounting to present value are really two sides of the same coin." Monessen Sw. Ry. Co. v. Morgan, 486 U.S. 330, 348 (1988) (Blackmun, J., concurring in part and dissenting in part). Improperly "[r]efusing to award prejudgment interest ignores the time value of money and fails to make the plaintiff whole." Thomas v. Tex. Dep't of Crim. Just., 297 F.3d 361, 372 (5th Cir. 2002). Indeed, "[p]rejudgment interest serves to compensate for the loss of use of money due as damages from the time the claim accrues until judgment is entered, thereby achieving full compensation for the injury those damages are intended to redress." West Virginia v. United States, 479 U.S. 305, 310 n.2 (1987); Chamberlain ex rel. Chamberlain v. United States, 401 F.3d 335, 345 (5th Cir. 2005) ("[P]rejudgment interest in Louisiana is viewed as a form of reparation.").
Entitlement to prejudgment interest is similarly governed by Louisiana law in this diversity case. Concise Oil &Gas P'ship v. La. Intrastate Gas Corp., 986 F.2d 1463, 1472 (5th Cir. 1993). As explained by the Louisiana Supreme Court, "interest is recoverable on debts arising ex contractu from the time they become due, unless otherwise stipulated." Corbello v. Iowa Prod., 2002-0826, p. 28-29 (La. 2/25/03); 850 So.2d 686, 706, superseded by statute on other grounds, LA. REV. STAT. § 30:2015.1. An award of prejudgment interest "is meant to fully compensate the injured party for the use of the funds to which he is entitled but does not enjoy." Sewell v. St. Bernard Par. Gov., No. 21-2376, 2023 WL 1765923, at *13 (E.D. La. Feb. 3, 2023) (quoting Sharbono v. Steve Lang &Son Loggers, 97-0110 (La. 7/1/97); 696 So.2d 1382, 1386).
Louisiana's presumption in breach-of-contract cases provides that prejudgment interest runs from the date the breached occurred, which generally precedes judicial demand, regardless of whether "the precise amount of the damages [is then] liquidated or absolutely certain." David Y. Martin, Jr., Inc. v. Heublein, Inc., 943 F.Supp. 637, 643 (E.D. La. 1996) (noting "[Louisiana] courts have established only that, in order for interest to run from the date of breach, damages must be ascertainable"). Alternatively, courts should award prejudgment interest from the date of judicial demand if calculation from the breach date is unascertainable in "highly complicated" cases. Trans-Glob. Alloy, Ltd. v. First Nat'l Bank of Jefferson Par., 583 So.2d 443, 457-59 (La. 1991) ("While we agree that the damages in this case were not ascertainable until reduced to judgment, we nevertheless find that interest should run from the date of judicial demand.").
Although we agree with the district court's conclusion that "[p]re-judgment interest should run from the date each item of past damages was incurred" because damages in each of those years could be ascertained, the award nonetheless failed "to fully compensate the injured party." Sharbono, 97-0110, 696 So.2d at 1386. Indeed, the district court properly awarded prejudgment interest on royalty damages incurred between 2010 and 2017. But the court failed to award the same on annualized damages between 2018 and 2022-past years for which the Landowners had data available showing the exact extent of their lost profits-and instead erroneously reduced the award for each of those years to present value. Therefore, we reverse the court's award of prejudgment interest because it insufficiently compensated the Landowners for their entitled damages.
C.
On remand, the district court is instructed to recalculate royalty damages and prejudgment interest based on the framework outlined in accordance with Louisiana law. In fashioning the proper royalty damages award, evidence showing actual losses must be considered when it is presented and otherwise admissible. The court may award damages for future losses based on projections, subsequently discounted to present value, only when actual loss data is unavailable or unascertainable. Additionally, the Landowners are entitled to prejudgment interest on damages that run from the date the breach occurred until judgment is entered.
We recognize actual loss data for 2023 and 2024 may now be available. In that event, the district court is directed to consider such data.
* * *
Accordingly, we AFFIRM the district court's ruling that the natural gas lease provided for a no-cost royalty based on gross proceeds. The district court did not err by considering extrinsic evidence for determining the royalty provision's meaning. We REVERSE the district court's calculation of royalty damages plus prejudgment interest and REMAND for proceedings consistent with instructions provided in this opinion.