On March 12, 2021, the Supreme Court of Texas issued a unanimous opinion that clarifies when a lessee is entitled to deduct post-production costs from royalties paid to the lessor under oil and gas leases. Construing a lease and an addendum to the lease, the court in BlueStone Natural Resources II, LLC v. Randle, No. 19-0495 held that the “gross value received” language in the addendum constitutes a valuation point at the point of sale (which does not allow deduction of post-production costs) that conflicted with the form lease’s “at the well” provision (which generally allows such deductions). Because the addendum provided that it would control in the event of a conflict, the lessor BlueStone was not permitted to deduct post-production costs from royalties paid to the lessor. The court referenced but distinguished its recent decision in Burlington Resources Oil & Gas Co., LP v. Texas Crude Energy LLC, 573 S.W.3d 198 (Tex. 2019), which held that “at the well” valuation points permit deduction of post-production costs. Burlington did not dictate the result in BlueStone because the “value received” clause in the lease in Burlington did not have a modifier, whereas the phrase “value received” in the BlueStone lease was modified by the word “gross,” which “gives rise to ‘an in inherent conflict’” with an “at the well” royalty provision (BlueStone slip op. at 15 (quoting Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 136 (Tex. 1996) (Owen, J.) (plurality op.))). The court emphasized that traditional rules of contract construction apply to oil and gas leases.
1. Overview of royalty provisions: “market value at the well” versus “proceeds” leases
Courts in Texas employ standard contract construction rules to construe oil and gas leases, “begin[ning] with the contract’s express language” and examining the entire writing to harmonize the provisions in the contract (Burlington, 573 S.W.3d at 202-03). At the same time, however, certain background principles affect Texas courts’ interpretation of the language in oil and gas leases. For example, royalty owners generally do not pay production costs, such as for geophysical surveying and drilling wells, but usually are required to pay post-production costs, such as for transportation, processing and compression that are incurred to bring gas from the wellhead downstream to market. (See Burlington, 573 S.W.3d at 203.) This typical allocation of costs between the royalty owner and the lessee is often reflected in a “market value at the well” lease provision. (See Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 873 (Tex. 2016).) The market value at the well can be thought of as the commercial market value less the expenses incurred to get the oil or gas from the well to the market.1
Parties may, however, “contract for a royalty calculated based not on the value of the oil and gas at the well but on its value at the point of sale.” (See Burlington, 573 S.W.3d 204.) If a royalty is based on the amount realized from a sale, the lessee generally cannot deduct post-production costs from the royalty payment.2 This is called a “proceeds” lease,3 and it can have a huge impact on the amount of royalties a royalty holder receives because the value of oil or gas increases as it is processed and moved from the wellhead downstream.
In Burlington, the court clarified that royalty provisions in oil and gas leases can have a separate valuation point and valuation method.4 The leases in Burlington provided that the royalty payments were calculated based on the “amount realized” from the sale, i.e., the actual amount of money received for the sale instead of the typical “market value.”5 But the leases also included what the court concluded was an “at the well” provision.6 The court read the provisions together to create a valuation point at the well based on the valuation method of the amount realized from the downstream sale.7 The court concluded that Burlington had “the right to subtract post-production costs from the ‘amount realized’ in downstream sales price in order to calculate the product’s value” at the wellhead.8 In other words, Burlington held that there can be a valuation point at the well tied to a valuation method based on the amount realized at the downstream sale.
2. The dispute in BlueStone: whether BlueStone may deduct post-production costs from royalty payments
A primary issue in BlueStone was whether the lessee was entitled to deduct post-production costs from its royalty payments to lessors. The original lessee, Quicksilver, did not deduct post-production expenses for almost a decade. After BlueStone acquired the leases, it began deducting post-production costs from its royalty payments. The royalty holders sued BlueStone.9
At issue was the interplay between a form lease (the “printed lease”) and an addendum to that lease. The printed lease contains a royalty provision for “market value at the well of one-eighth of the gas so sold or used.” The addendum states that it controls over contrary provisions in the printed lease and includes a clause that states the “Lessee agrees to compute and pay royalties on the gross value received ... .”10 If the “at the well” clause in the printed lease is not superseded by the “gross value received” clause in the addendum, then BlueStone is permitted to deduct reasonable post-production costs from royalty payments to the royalty holders. But if the “gross value received” clause is both a valuation method and a valuation point, then the addendum controls over the printed lease, and BlueStone would not be permitted to deduct post-production costs from royalties.
The trial court and the Fort Worth Court of Appeals both held that the superseding clause in the addendum governed, resulting in a “pure-proceeds” royalty calculation that did not allow BlueStone to deduct post-production costs from its royalty payments.11 BlueStone appealed.
3. The Supreme Court of Texas holds that the “gross value received” provision in the addendum conflicts with the “at the well” provision in the lease and provides that BlueStone may not deduct post-production costs from its royalty payments
The Supreme Court of Texas determined that the “gross value received” clause in the addendum conflicted with the “at the well” provision in the printed lease, affirming the decision of the appellate court.12 The court started with a restatement of basic contract interpretation, noting that Texas courts “construe the mineral lease as a whole and interpret the language according to its plain, ordinary, and generally accepted meaning ... .”13 The court concluded that “when proceeds are valued in ‘gross’ ... the valuation point is necessarily the point of sale because that is where gross is realized or received.”14 The court rejected BlueStone’s argument premised on Burlington that “at the well” language acts as a “trump” card that supersedes the gross amount realized language.15 The court distinguished the lease at issue in Burlington, which did not use “gross” language to modify the “amount realized” valuation in the lease. The addendum at issue in BlueStone, however, included a “gross value received” clause. The terms, the court concluded, cannot be reconciled: “‘gross’ and ‘net’ terms do not peaceably coexist.”16 The court held that the lease was unambiguous, the “gross value received” clause in the addendum was controlling, and it provided (i) a “valuation method” of “‘the royalty based on the amount the lessee in fact receives under its sales contract for the gas’” and (ii) a “valuation point” that is “necessarily the point of sale” because of the modifier, “gross.”17 As a result, BlueStone was not permitted to deduct post-production costs.18
- When drafting contracts in general, and oil and gas leases specifically, drafters should take care to explicitly state the contract terms and not rely on generally understood industry terms.
- Drafters should carefully note that the valuation method is distinct from the valuation point, and both should be explicitly detailed in leases. Furthermore, drafters must be careful when using the terms “gross value received,” which will prohibit post-production deductions from royalty payments, and “at the well,” which permits those deductions.
- Parties to (or acquirors of) oil and gas leases should review existing leases to determine whether those agreements contain conflicts between “gross value received” and “at the well” clauses, and whether any superseding clauses might affect interpretation.
- Many form contracts are governed with riders or addendums, similar to the printed lease and addendum at issue in BlueStone. For example, the Edison Electrical Institute (EEI) master contract, which is a “commercially oriented, standard power purchase and sale agreement,” includes optional annex provisions and provides in its cover sheet the ability to identify any customized contract riders that modify the terms of the master agreement.19 The North American Energy Standards Board, Inc. (NAESB) also provides a base contract for the purchase and sale of natural gas, which is modified by the cover sheet, special provisions and transaction confirmations.20
- While BlueStone’s holding concerns oil and gas royalties, it provides insight into the ways the Supreme Court of Texas views contract modifications through riders or addenda. Drafters should be mindful of the potential for creating contradictory terms through amendments or addenda and draft to address such contradictions.
1 See Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 873.
2 See Burlington, 573 S.W.3d 204.
3 Chesapeake Exploration, L.L.C., 483 S.W.3d at 873.
4 Burlington, 573 S.W.3d at 211.
7 Id. at 205, 211.
8 Id. at 211.
9 See BlueStone Nat. Resources II, LLC v. Randle, 601 S.W.3d 848, 853 (Tex. App. — Fort Worth 2019, pet. granted).
10 There is also a dispute about a “free-use” clause that permits BlueStone to use “free from royalty ... oil, gas, and coal produced from said land in all operation which lessee may conduct hereunder.” The Supreme Court of Texas in a matter of first impression found that the free use clause was limited to on-lease uses. BlueStone, slip op. at 26.
11 Id. at 869.
12 BlueStone, slip op., at 2.
13 Id. at 8.
14 Id. at 14.
15 Id. at 15-16.
16 Id. at 15.
17 Id. at 12, 14, 17 (emphasis in original) (quoting Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008)).
18 Id. at 17.
19 Andrew S. Katz, Using the EEI-NEM Master Contract to Manage Power Marketing Risks, Energy Law Journal, Vol. 21, 269 & 275 (2000).
20 See, e.g., 7A William B. Burford, West’s Tex. Forms, Minerals, Oil & Gas § 17:10 (4th ed.).
This memorandum is provided by Skadden, Arps, Slate, Meagher & Flom LLP and its affiliates for educational and informational purposes only and is not intended and should not be construed as legal advice. This memorandum is considered advertising under applicable state laws.