“If you can’t understand what your contract means without asking the lawyer who wrote it, you should not be surprised later if judges – who can’t just take your lawyer’s word for it – also have trouble understanding what it means.” – Justice Blacklock[1]
As a general rule, a landowner under a Texas oil and gas lease is entitled to royalties from the sale of raw oil and gas produced from the ground, free of drilling and production costs. After oil and gas are brought to the surface, a producer or purchaser will incur additional “post-production” costs. These costs include gathering, transporting, compressing, dehydrating, and otherwise refining the raw oil or gas to create more valuable and market-ready products. The royalty owner does not share in this added value unless it is specifically contracted for in the lease. Thus, the royalty provision in a typical Texas lease has three essential – and often heavily negotiated – elements: (i) an amount, such as one-fourth, one-fifth, or three-sixteenths; (ii) a valuation method, such as market value, net proceeds, or gross proceeds; and (iii) a valuation point, such as the mouth of the well, the tailgate of the processing plant, or the point of sale. Under what has become known as a “gross proceeds lease,” a royalty owner is typically free of post-production costs up to the specified downstream valuation point.
In Devon Energy Prod. Co., L.P. v. Sheppard, it was undisputed that certain subject leases were gross proceeds leases. The landowners under these leases were thus entitled to royalties free of post-production costs calculated at the first point of sale.[2] However, the subject leases also included the following provision: “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” (emphasis added).[3]
Devon sold oil and gas to third parties at various points downstream from the wellhead. In accordance with the subject leases, it paid royalties based on the gross proceeds received at these points of sale without deducting post-production costs.[4] However, Devon was occasionally compelled to identify a price for products that were not yet in marketable condition. In these instances, Devon arrived at a valuation based on published “market-center” prices for more refined downstream products. It then netted back to the first point of sale a valuation based on these market center prices (a common practice in the area).[5] At issue in this case was whether it was proper for Devon to utilize this net back method, or whether these amounts should have been added to gross proceeds at the point of sale. The “added to” calculation method would have resulted in substantially higher royalty payments to the landowners.
The Supreme Court found that the lease language above created “proceeds-plus” leases. Royalties were payable not only on gross proceeds, but also on an unaffiliated buyer’s post-sale post-production costs if the producers’ sales contracts stated that the sales price had been derived by deducting such costs from published index prices downstream from the point of sale.[6] Therefore, the royalty payments due under the subject leases exceeded gross proceeds. They required royalty payments on gross proceeds plus expenses incurred by the buyer downstream from the initial point of sale.[7] More specifically, the subject leases require a two-prong royalty calculation. First, the producers must determine gross proceeds from selling the production, which, by definition, is free of post-production costs. Second, when the producers’ contracts, sales, or dispositions state that enumerated post-production costs or expenses have been deducted in setting the sales prices, these costs and expenses “shall be added to the . . . gross proceeds.” To avoid the absurd result of a royalty owner receiving a future windfall at every post-sale point at which the buyers’ refined products are sold, the Court noted that the royalty obligation is “[tethered] to the time and place where gross proceeds are [first] realized.”[8]
Justice Blacklock, in his dissent, asserted that the provision above was merely intended to be an additional safeguard against the deduction of post-production costs, and to ensure that payments would be paid based on gross proceeds at the point of sale.[9] The market-center price came into the picture only as a mechanism for calculating the value at the first point of sale. In his opinion, it was included to “ensure that neither a clever lessee nor a wayward court will deprive the royalty holder of the full benefit of its cost-free “gross proceeds” royalty. [10] The market-center price came into the picture only as a mechanism for calculating the value at the first point of sale.[11] Moreover, the parties were free to set “market-center price” as their valuation method, but did not do so here.[12] Thus, stated Justice Blacklock, the Court’s decision allowed the owner of this gross-proceeds royalty to convert his interest from a royalty on products at the point of initial sale into a windfall royalty on more fully refined products sold by third parties at a downstream market center.[13]
Devon Energy Prod. Co., LP v. Sheppard is a case of first impression and the landowners cited to no precedent requiring producers to pay royalty on post-production costs incurred downstream from the point of sale.[14] The holding that the “proceeds plus” leases at issue created royalties payable in an amount that may exceed the consideration paid to producers is a hard pill for lessees to swallow. However, the Court was careful to note that this case only examines how post-production costs were allocated under these particular leases. What is clear is that broad “proceeds plus” language has now withstood scrutiny by Texas’ highest court, and producers should take note. Although this case is relegated to these particular leases, it is worth noting that this is a fairly common lease provision and a common method of valuation at the first point of sale, particularly in the Eagle Ford Shale.[15]
[1] Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, 573 S.W.3d 198 (Tex. 2019).
[2] 2023 Tex. LEXIS 223.
[3] Id. at 5-6.
[4] Id. at 6-7.
[5] Id. at 36.
[6] Id. at 2.
[7] Id. at 2-3.
[8] Id.
[9] Id. at 31-41.
[10] Id. at 33.
[11] Id. at 36.
[12] Id. at 38.
[13] Id. at 31.
[14] Id. at 21.
[15] See John B. McFarland, Oil and Gas Lawyer Blog: https://www.oilandgaslawyerblog.com/devon-v-sheppard-a-win-for-royalty-owners/.
Brad represents clients in connection with upstream energy transactions, complex mineral titles, pooling issues, lease analysis, joint operating agreements, surface use issues, title curative and general oil and gas business matters.