The Future of “Add-Back” Litigation after Devon
By Christopher M. Hogan, Trial Attorney & Founding Partner, Hogan Thompson LLP
06/08/23—Since the Texas Supreme Court’s decision in Devon Energy Prod. Co., L.P. v. Sheppard, --- S.W.3d ---, No. 20-0904, 2023 WL 2438927 (Tex. Mar. 10, 2023), energy companies across Texas have tried to determine the effect of Devon on their royalty payment obligations. The specter of “add-back” litigation in light of Devon has become a major concern in the state.
But while Devon is critical to understanding lease obligations, it does not stand alone. Another important development in Texas royalty caselaw can be seen through the Texas Supreme Court’s denial of a petition for review in Shirlaine West Properties Ltd. v. Jamestown Resources, L.L.C., a case in which the petitioners sought to expand Devon to cover other lease language. Understanding the scope of Devon and the limits of the decision is important to operators seeking to understand potential liability for “add-back” claims going forward.
Add-Back Claims
If you are not familiar with an add-back claim, picture a gross-proceeds lease where the lessor gets paid based on money that an operator receives for gas. The operator might have paid a pipeline company—Pipeline Inc.—to transport the gas from the lease to a pipeline and then paid for Pipeline Inc. to process the gas for sale to a third party. In a typical gross-proceeds situation the operator would not have been able to deduct those post-production costs from the lessor’s royalty.
So instead, the operator sells the gas to Pipeline Inc. at the well, and Pipeline Inc. processes and transports the gas to the point of sale to the third party. Pipeline Inc. then pays the operator based on the eventual sales price of the gas to the third party, minus a fixed percentage or cost based on the expense of transportation and processing. Now when the operator pays the lessor its share of the proceeds it will get from Pipeline Inc., those proceeds will be less than they would have been had the operator paid Pipeline Inc. to transport and process the gas outside of this arrangement.
An add-back claim is a demand that the operator, when calculating royalty payments to the lessor, adjust the payment upward to account for these third-party expenses. Essentially, the lessor demands a higher royalty than one based solely on the operator’s gross proceeds.
The example above is simple. But add-back claims get more suspect the more you think about them. In our example above, what if Pipeline Inc. sells the gas to a trading house, which then sells it to an LNG exporter, which then transports the gas to Japan and sells it to a utility, which then sells it to its customers. Does the lessor get a royalty based on the (much higher) sales price in Japan? Such a scenario shows some of the conceptual problems with add-back claims.
Devon – The Background
The leases at issue in Devon deviated from the typical question that confronts Texas courts when it comes to oil and gas royalty provisions. Many oil and gas leases fall into one of two buckets: an “at the well” lease that requires a royalty owner to share in post-production costs, or a “gross proceeds” lease that does not permit the producer to charge the royalty owner its share of post-production costs. Much of the lease language in the leases at issue in Devon was typical gross-proceeds language, requiring the producers to pay on gross proceeds realized from the sale of oil and gas. In line with this language, “the producers [did] not deduct—directly or indirectly—any expenses they incur[red] to ready production for sale.” Devon, 2023 WL 2438927, at *3. For example, “when unaffiliated third-party processors . . . purchased production at the tailgate of the processing plant, and they have paid a lower price as a cost adjustment for having transported and processed gas on the producers’ behalf, the producers . . . added the pre-sale transportation and processing expenses to the stated sales price before computing the landowners’ royalty payment.” Id.
But the royalty owners noticed that the producers were selling oil produced on the leases under a contract that set the sales price “at market centers downstream from the point of sale and then [subtracted] $18 per barrel for the buyer’s anticipated post-sale costs for ‘gathering and handling, including rail car transportation.’” Id. at *4. The royalty owners later learned about “other transactions with complicated pricing formulas that similarly employed market-center index prices that were adjusted downward by flat, percentage, or volume amounts that the sales contracts sometimes—but not always—identified as accounting for the buyer's actual or anticipated post-sale postproduction costs.” Id. In light of these transactions, the royalty owners sued. The royalty owners prevailed at the trial court and mostly prevailed at the Corpus Christi Court of Appeals. The Texas Supreme Court granted a petition for review.
The Devon Decision at the Supreme Court
The main point of contention in Devon was how to interpret what the Texas Supreme Court called a “bespoke lease provision” that was in the leases at issue in the case. Id. at *1. This provision—Section 3(c)—discussed how certain costs and expenses could be “added back” to those gross proceeds:
(c) 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 *2. The leases also had an “Addendum L” that similarly addressed costs and expenses charged on the leases:
Payments of royalty under the terms of this lease shall never bear or be charged with, either directly or indirectly, any part of the costs or expenses of production, gathering, dehydration, compression, transportation, manufacturing, processing, treating, post-production expenses, marketing or otherwise making the oil or gas ready for sale or use, nor any costs of construction, operation or depreciation of any plant or other facilities for processing or treating said oil or gas. Anything to the contrary herein notwithstanding, it is expressly provided that the terms of this paragraph shall be controlling over the provisions of Paragraph 3 of this lease to the contrary and this paragraph shall not be treated as surplusage despite the holding in the cases styled “Heritage Resources, Inc. v. NationsBank”, 939 S.W.2d 118 (Tex. 1996) and “Judice v. Mewbourne Oil Co.”, 939 S.W.2d 133, 135-36 (Tex. 1996).
Id. at *3 (cleaned up).
The producers argued that the “add back” language was “mere surplusage that emphasizes the cost-free nature of a ‘gross proceeds’ royalty by requiring them to ‘add back’ only pre-sale postproduction costs that may have diminished the sales price.” Id. at *5. But the Texas Supreme Court disagreed. It noted that the leases required payment of more than gross proceeds:
But the leases also plainly require certain sums to be “added to” gross proceeds. The question is not whether an unaffiliated buyer's postproduction costs are gross proceeds under the leases or under the law. Of course, they are not. The question is whether the leases nonetheless require the producers to pay royalty on those costs.
Id. at *8. While the royalty owners had no precedent to support their reading, the Court noted that the parties were free to make a lease containing such an unprecedented clause and analogized it to the “marketable product” rule in some states outside of Texas.
The Court also noted that Paragraph 3(c) “serves no purpose at all if not to allow the amount on which the royalty payment is calculated to exceed gross proceeds.” Id. at *9. While the Court recognized the need for interpreting oil and gas provisions consistently to promote industry stability, it found that there was “nothing common, usual, or standard about the language in Paragraph 3(c), which is quite clear in expressing the intent to deviate from the usual expectations regarding the allocation of postproduction costs.” Id. Ultimately, the Court agreed that the leases “are ‘proceeds plus’ leases that employ a two-prong calculation of the royalty base”:
First, the producers must properly determine their gross proceeds from selling the production, which by definition must be free of postproduction costs. Second, when the producers’ contracts, sales, or dispositions state that enumerated postproduction costs or expenses have been deducted in setting the sales prices, those costs and expenses “shall be added to the ... gross proceeds.” The words chosen by the parties in these unique provisions demonstrate an intent and expectation that some amount may be added to the producers’ gross proceeds when calculating royalties.
Id. at *11.
Shirlaine West Properties and possible limits on Devon
After the Corpus Christi Court of Appeals’ opinion in Devon was issued, I figured it was only a matter of time before more lessors tried to incorporate add-back claims where they do not really fit. Shirlaine West Properties Ltd. v. Jamestown Resources, L.L.C., 02-18-00424-CV, 2021 WL 5367849 (Tex. App.—Fort Worth Nov. 18, 2021, no pet. h.) appears to be a good example of such a situation.
The case stems from a 2010 lease between Shirlaine and Chesapeake Exploration (“Chesapeake”). The lease at issue provided for a royalty that was “25% of the market value at the point of sale, use or other disposition of all such gas” and noted that “[t]he market value of all gas shall be determined at the specified location and by reference to the gross heating value (measured in British thermal units) and quality of the gas.” Id. at *1. The lease also contained no-deductions language and a Heritage disclaimer. Id. Finally, the lease had a provision (the “Add-Back Provision”) about the possible add-back of deductions:
If Lessee realizes proceeds of production after deduction for any expenses of production, gathering, dehydration, separation, compression, transportation, treatment, processing, storage or marketing, then the proportionate part of such deductions shall be added to the total proceeds received by Lessee for purposes of this paragraph.
After execution of the lease, Chesapeake assigned some of its interest to Total E&P USA, Inc. (“Total”). Both Chesapeake and Total sold their gas at the wellhead to affiliates. While the mechanics of how those affiliates then sold the gas differed, the result was that both lessees received sales proceeds reduced based on post-production costs that the affiliates incurred in processing and/or marketing the gas.
The lessors sued claiming that post-production costs were not permitted under the lease. The court first examined the key questions of the measure of value and the location of that valuation. Based on the lease language, the court held that the lease “fix[es] market value as the measure of value and set[s] the location of the value at the point of sale.” Id. at *6. Because the point of sale was the wellhead, the lessees had a right to take post-production deductions even though that sale was to an affiliate. Citing Justice Owen’s concurrence in Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996), the court also rejected the no-deductions language as “surplusage, or restatements of existing law.” Id. And the court rejected the Heritage disclaimer based on the Texas Supreme Court’s rejection of similar language in Chesapeake Exploration, L.L.C. v. Hyder, 483 S.W.3d 870 (Tex. 2016). Each of these holdings by the court was a rather straightforward application of Texas caselaw on post-production costs.
But the lessors claimed that the Add-Back Provision presented the court with a new twist:
Lessors contend that by Lessees selling the gas to [their affiliates] with postproduction costs deducted from the purchase price, Lessees realize proceeds after deduction for expenses identified in Sentence 7, and Lessors are therefore entitled to have these expenses added back into the “total proceeds” to be used for calculating royal.
Id. at *7. The court, however, rejected this argument. It found that such a reading would “create an internal conflict [with] the market-value-at-the-well provisions” and “effectively convert a market-value-at-the-well lease into a ‘total proceeds’ lease.” Id. While the court left open the possibility that the Add-Back Provision might apply if sales had not occurred at the wellhead, the court determined that the lessors’ attempt to use the provision to eliminate post-production cost deductions conflicted with the rest of the lease.
The lessors in Shirlaine West Properties petitioned the Texas Supreme Court for review. In their petition for review, the lessors leaned strongly on the Corpus Christi Court of Appeals’ decision in Devon. Once the Texas Supreme Court released its decision, the lessors filed an “amendment” to their petition for review focusing on Devon’s alleged effect on their case. The Texas Supreme Court, however, denied their petition for review on June 2, 2023.
What should operators in Texas do now?
In light of Devon and Shirlaine West Properties, producers operating in Texas should have several takeaways when it comes to royalty obligations in Texas.
First, as always, lease language remains king in Texas. Some practitioners hoped that the Texas Supreme Court would essentially establish a ceiling on royalty provisions that capped the royalty based on a gross-proceeds calculation. But the Court declined to create any such rule, and instead showed that the exact lease language used remains central to royalty payment. The Court cautioned that “we address only the specific language of the provisions before us as applied to the disputed issues on appeal,” suggesting a desire that lower courts not apply the decision too widely. The Court’s description of the lease provision at issue as “bespoke,” “highly unique,” and “unusual” supports this limited scope, and the Court’s decision to deny the petition for review in Shirlaine West Properties only strengthens that reading.
Second, when examining lease language for “add-back” arguments, look at what is allegedly being added-back. The lease language in Devon was clear that it required add-back payments for any “deduction, expense or cost” and that the lessor was never to be charged “with any costs or expenses.” This focus on charges and expenses differs from many leases that focus almost exclusively on “deductions” and require add backs for deductions taken. But under Heritage, there are no deductions to be taken when a lease values oil or gas at the wellhead. See Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 130 (Tex. 1996) (Owen, J., concurring). Thus, any lessor attempting to use add-back language that deals only with “deductions” taken may find themselves in the same spot as the lessor in Heritage, with the lease language being considered “mere surplusage.” Indeed, it appears the lessors in Shirlaine West Properties found themselves in this exact spot.
Third, not every adjustment made in a sales contract is necessarily going to qualify for an “add-back.” The Corpus Christi Court of Appeals in Devon went contract-by-contract and examined the language used in the contracts discussing post-production costs. For contracts that expressly stated that the producers were receiving less money for oil and gas based on transportation, processing, or other post-production work, those costs had to be added back to the royalty payment. But for contracts that made price adjustments but did not clarify the reason for the adjustment (e.g., paying based on the NYMEX public index minus $0.15/MMBtu), the add-back provision did not apply because it was unclear why the adjustment took place. Because the lessors did not challenge this part of the Devon holding from the Corpus Christi Court of Appeals, this distinction remains valid (and binding on trial courts in that court of appeals’ district). Scrubbing down contract language will be key to fighting future add-back cases; though operators should watch out for lessors arguing that discovery will be needed on a contract-by-contract basis to determine the real reason for each price adjustment. See Devon Energy Prod. Co., L.P. v. Sheppard, 643 S.W.3d 186, 207 (Tex. App.—Corpus Christi–Edinburg 2020) (“Appellees have not pointed to any evidence establishing that the purpose for these reductions is one of those specifically identified in paragraph 3(c).”).
Fourth, operators looking at language like that in Devon should likely not be concerned that they will have to pay royalties based on later sales between different third parties. The Devon Court briefly addressed this issue in its decision:
[The lease language] does not mean that any “reduction or charge” for postproduction costs in the buyers’ subsequent dispositions must be included in the royalty base ad infinitum. To the contrary, Paragraphs 3(a), (b), and (c) contractually tether the royalty obligation to the time and place where gross proceeds are realized.
Devon, 2023 WL 2438927, at *11. This limitation fortunately forecloses arguments about royalty owners getting paid based on later sales about which an operator may have little or no information. Of course, this limitation tracks the lease language in Devon, and thus could theoretically be altered in future lease forms.
Fifth, operators should beware of lessors relying only on phrases like “indirect charges” or “indirectly deducting” when evaluating add-back claims, as I believe this is where the biggest fights will be when reading Devon. While such language was present in the Devon leases and relied on by the Texas Supreme Court in reaching its opinion, the Court focused more heavily on the “added to” language in Section 3(c) of the leases. It is far from certain in my opinion that Devon would have reached the same conclusion if the lease at issue only barred “direct and indirect charges” without featuring language about those charges being “added to” the gross royalty. Yet many leases I have seen feature this “indirect” language without any express “add-back” provision. I do not believe such leases would have been viewed by the Devon Court like the lease at issue in Devon.
Sixth and finally, the language from Devon is unfortunately more common than you think. Despite the Texas Supreme Court’s characterization of the leases in Devon as “bespoke,” “highly unique,” and “unusual,” the add-back provision used in the Devon leases is not that rare in Texas. Amicus briefs filed with the Court noted that this lease language is already being used across Texas. And the General Land Office has incorporated a similar provision into its state lease form. When it comes to leases using identical (or nearly identical) language as the lease in Devon, operators will have little flexibility in fighting against “add-back” claims.
Christopher M. Hogan Trial Attorney & Founding Partner chogan@hoganthompson.com | 713.671.5642
Chris Hogan focuses his litigation practice on resolving complicated disputes for corporate and individual clients, particularly those in the energy industry. Chris has substantial first-chair experience in federal court, state court, and arbitration proceedings. is honored to represent as lead counsel major energy companies such as Apache, BPX, Chevron, ConocoPhillips, Devon, EOG, Marathon Oil, Mewbourne, and Ovintiv.