Some oil and gas practitioners have suggested that the Texas Supreme Court’s recent Devon opinion is a radical new development in the Court’s oil and gas royalty jurisprudence. See Devon Energy Prod. Co. v. Sheppard, 668 S.W.3d 332 (Tex. 2023). I disagree. Even after Devon, the basic rules of royalty calculation remain the same: the term “net proceeds” still means net proceeds, and the term “gross proceeds” still means gross proceeds. The key takeaway from Devon is something we all knew even before Devon: the parties to an oil and gas lease are free to negotiate terms that deviate from the basic rules. Id. at 344-45; see Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 124 (Tex. 1996) (“Parties to a lease may allocate costs, including post-production or marketing costs, as they choose.”).
The parties in Devon entered into leases which contained royalty clauses stating that the lessors would receive a fractional share of the gross proceeds that the lessee realized on the first sale of its oil or gas production to an unaffiliated purchaser. Devon, 668 S.W.3d at 337. Those clauses, at least in themselves, were fairly run-of-the-mill gross proceeds royalty clauses. But those gross proceeds royalty clauses were not the focus of the Court’s attention in Devon. Instead, the conflict between the parties centered “on more unconventional language” in a separate paragraph of the parties’ leases — Paragraph 3(c). Id. The unconventional language in Paragraph 3(c) stated:
"If any disposition, contract or sale of oil or gas shall include any reduction or charge for the expenses or costs of production, treatment, transportation, manufacturing, process[ing] or marketing of the oil or gas, then such deduction, expense, or cost shall be added to … gross proceeds so that Lessor’s royalty shall never be chargeable directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes."
Id. at 337-38 (emphasis in original). Some commentators have described Paragraph 3(c) as an “add-back” clause.
I suspect that when the parties in Devon originally entered into their leases, they understood Paragraph 3(c) merely to reinforce their intent that the lessors were to receive a share of the gross sales price at the point of sale. More specifically, I think that the likely purpose of Paragraph 3(c) in the Devon lease was simply to protect the lessors against creative sales contracts in which the lessee might try to segregate the sales price from any post-production costs. Suppose, for instance, the following set of facts:
(i) the lessee produces crude oil from a wellhead location in Cotulla, where the oil has a market value of $60.00 a barrel;
(ii) instead of selling its oil production at the wellhead, the lessee uses an affiliate to transport the oil to an intermediate downstream sales market in Houston, where the oil has a market value at prevailing market prices of $80.00 a barrel; and
(iii) the lessee then sells its oil production at the intermediate downstream sales market in Houston to an unaffiliated purchaser under a sales contract stating that the purchaser will pay $72.00 a barrel to the lessee for the lessee’s production and $10.00 a barrel to the lessee’s affiliate for the affiliate’s transportation costs from Cotulla to Houston.
Under that set of facts, Paragraph 3(c) in the Devon lease would ensure that the lessee must pay the lessors their fractional royalty share of $82.00 a barrel, not just $72.00 a barrel.
The problem with unconventional and untested language is that it may have unintended effects under circumstances which the parties may not have fully anticipated at the time they entered into their leases. In Devon, the lessee sold its oil production “under contracts setting the sales price — and thus the gross sales proceeds — by using published index prices at market centers downstream from the point of sale and then subtracting $18 per barrel for the buyer’s anticipated post-sale costs.” Id. at 339. To put it the context of the previous example, suppose the following:
(i) the lessee produces crude oil from a wellhead location in Cotulla, where the oil has a market value of $60.00 a barrel;
(ii) instead of selling its oil production at the wellhead, the lessee uses an affiliate to transport the oil to an intermediate downstream sales market in Houston, where the oil has a market value at prevailing market prices of $80.00 a barrel; and
(iii) the lessee sells its oil production at the intermediate downstream sales market in Houston to an unaffiliated purchaser under sales contracts stating that the purchaser would pay the lessee the published index prices for crude oil per barrel at a further ultimate downstream sales center in Cushing, minus $18 per barrel for the purchaser’s transportation costs to get the production from Houston to Cushing.
If the index prices at the ultimate downstream sales center in Cushing were $100 per barrel, then the sales price that the lessee would receive for its production at the intermediate downstream sales market in Houston would still be $82 per barrel — the same as in the previous example. But as the Court effectively ruled in Devon, Paragraph 3(c) in the Devon lease would require that the lessee pay the lessors a fractional share of $100.00 a barrel, not just $82 a barrel.
The parties in Devon probably never intended that Paragraph 3(c) would require the lessee to “add back” to its sales price the costs that an unaffiliated purchaser might incur downstream of the point of sale. Regardless, the Court in Devon applied Paragraph 3(c) literally. Paragraph 3(c) in the Devon lease literally says that “any … charge for … the costs of … transportation … shall be added to … gross proceeds.” Id. at 337-38. As the Court reasoned in Devon:
"The inescapably broad language in Paragraph 3(c) is clear in that regard. It requires “any reduction or charge” for postproduction costs that have been included in the producer’s disposition of production to be “added to” gross proceeds so that the landowners’ royalty “never” bears those costs even “indirectly.” Paragraph 3(c) is not textually constrained to the expenses incurred by the seller or prior to the point of sale."
Id. at 345 (emphasis added).
Neither the majority opinion in Devon nor the dissent addressed whether the majority’s literal construction of Paragraph 3(c) creates an absurd result. Cf. Markel Ins. Co. v. Muzyka, 293 S.W.3d 380, 387 (Tex. App.—Fort Worth 2009, no pet.) (“We will not construe contracts to produce an absurd result when a reasonable alternative construction exists.”). Perhaps that is because the “absurdity safety valve is reserved for truly exceptional cases, and mere oddity does not equal absurdity.” Combs v. Health Care Servs. Corp., 401 S.W.3d 623, 630 (Tex. 2013). Even so, the Texas Supreme Court has not hesitated to apply the absurdity safety valve where necessary to avoid giving statutes an unreasonable construction. See, e.g., Castleman v. Internet Money Ltd., 546 S.W.3d 684, 688 (Tex. 2018). The absurdity safety valve presumably should equally apply where necessary to avoid giving contracts — including oil and gas leases — an unreasonable construction.
The majority in Devon was well aware that its literal construction of Paragraph 3(c) required a strange result — even if perhaps not an absurd one. Although the Court in Devon acknowledged that it had literally construed the Devon leases to be “proceeds plus” leases entitling the lessors to receive even more than a fractional share of the lessee’s actual sales price at the point of sale, the Court went to great lengths to try to limit its specific holding to its facts, emphasizing that the parties’ lease was “bespoke,” that Paragraph 3(c) was “specially written,” and that the “inescapably broad” language in Paragraph 3(c) was “unusual,” “atypical,” and “quite clear in expressing the intent to deviate from the usual expectations regarding the allocation of postproduction costs.” Devon, 668 S.W.3d at 335, 338, 340, 345-46, 348-39.
But while the specific holding in Devon may have produced a strange result, the reasoning the Court used to get to that result was nothing new. As the Court has repeatedly emphasized over the years, it will enforce “leases exactly as they are written, according to their plain language.” Id. at 347; see Heritage Res., 939 S.W.2d at 121. The Court will continue to “construe commonly used terms in a uniform and predictable way,” but the parties to an oil and gas lease are — at their own risk — “free to make their own bargains.” Devon, 668 S.W.3d at 336, 346; see Nettye Engler Energy, LP v. BlueStone Nat. Res. II, LLC, 639 S.W.3d 682, 696 (Tex. 2022) (“Although mineral transactions are subject to certain presumptions that state the ‘usual’ rules, we have repeatedly affirmed that parties are free to make their own bargains, and courts are obligated to enforce agreements as the parties intended.”).
Perhaps the lasting impact of Devon is simply that parties should be careful if they choose to deviate from the basic rules of royalty calculation. As I recently noted:
"The scope and specific language of the royalty clause in an oil and gas lease should be something that the parties consider on the front end during negotiations, not on the back end during litigation. The parties should take care to ensure that the royalty clause in their lease actually says what they intend it to mean."
Byron C. Keeling, Fundamentals of Oil and Gas Royalty Calculation, 54 St. Mary’s L.J. 705, 740 (2023).
Commenti