Understanding Custom Lease Provisions | Devon Energy Prod. Co., L.P. v. Sheppard

Devon Energy Prod. Co., L.P. v. Sheppard, 668 S.W.3d 332 (Tex. 2023). Post-Sale Postproduction Costs.

Key Takeaways

1. Proceeds Plus leases provide Royalty owners the economic advantage of receiving payment on “marketable product” and avoid burdensome valuations based on where and in what condition it is sold.
2. Under a Proceeds Plus lease, price adjustments made by the Lessee on account of a buyer’s post-sale postproduction costs could be added back to the royalty base calculation. Here, the Lessee failed to “add back” an $18 per barrel price reduction under such circumstances.
3. Read your lease. Custom lease terms can obviate general rules and will control.
4. Courts will not adhere to the same interpretation rules for custom lease provisions as will be afforded those terms of art that have been judicially interpreted (often repeatedly). If you want predictable, use language that has been judicially interpreted. If you want custom, you get a custom review.

The heart of this dispute is the proper method of calculating royalties under the terms of a custom oil and gas lease. In Texas, there are general rules, and then there are exceptions. The general rule is that lease royalties are free of the costs of production but bear their proportionate share of post-production costs; the exception to this general rule is that parties to an oil and gas lease are free agree otherwise.

In an appeal of first impression, the Court decided the legitimacy of a bespoke lease provision which attempted to ensure that the lessor’s royalty would not be subject to post-sale postproduction costs, including those incurred in any sale of production. Under the lease term crafted by the parties, the lessor’s royalty base (i.e. the amount on which royalties are calculated) can exceed the actual gross proceeds base, such that the producer is required to “pay royalties on the  gross proceeds of the sale plus sums identified in the producers’ sales contracts as accounting for actual or anticipated postproduction costs, even if such expenses are incurred only by the buyer after or downstream from the point of sale.” This means that per the terms of the lease provision, the amount on which the lessor’s royalty is calculated could be proportionately higher than that on which the produce’s net revenue is calculated.

The subject leases covered Eagle Ford Shale mineral interests. The Sheppard and Crain leases were executed in 2007 and 2010 respectively, amid the escalating shale boom.[2] The Sheppard lease provided for a 1/5 royalty for oil and gas, whereas the Crain leases provided for a 1/4 royalty. For simplicity, we’ll refer to the parties as the Lessors and the Operators.

For oil, the royalties were to be calculated, “… free of all costs and expenses to the Lessor into to pipeline, or other receptacle to which the Lessee may connect its wells or the market value thereof, at the option of the Lessor, such value to be determined by… the gross proceeds of the sale thereof”

The gas royalty provision provides that royalties will be based on “... the gross proceeds realized from the sale of such gas, free of all costs and expenses, to the first non-affiliated third-party purchaser under a bona fide arm's length sale or contract. “Gross proceeds” (for royalty payment purposes) shall mean the total monies and other consideration accruing to or paid the Lessee or received by Lessee for disposition or sale of all unprocessed gas proceeds, residue gas, gas plant products or other products. Gross proceeds shall include, but is not limited to advance payments, take-or-pay payments (whether paid pursuant to contract, in settlement or received by judgment) reimbursement for production or severance taxes and any and all other reimbursements or payments.”

The thrust of the dispute centered on the language of Paragraph 3(c) and Addendum L, which provided that if any oil and gas sales price includes “any reduction or charge for expenses or costs of production,” then such reductions or charges would be added to gross proceeds so as to ensure that the Lessor’s royalty would “never be charged directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes.”[2] Restated, the royalty would be based on the actual gross proceeds, PLUS any reductions or charges that were accrued before gross proceeds was calculated. For simplicity, we’ll call this the “Add Back Provision.”

In an attempt to clear up any doubt, Addendum L stated that royalty payments would not include, “either directly or indirectly, any costs or expenses” related to making oil or gas ready for sale or use, including post-production expenses, and plant or facilities costs used in processing or treating production.

Under the Sheppard and Crain leases, the producers would sell production of oil and gas “to unaffiliated third parties at various points downstream from the wellhead and pay royalty to the landowners on the gross proceeds ‘paid to’ or ‘received by’ the producers for those sales.” Because third-party purchasers typically pay a lower price on production to account for transport and other related expenses, prior to calculating the landowner’s royalty, producers in a no-deductions lease typically “add back” pre-sale processing and transport expenses to the final sales price. This was provided for here with Addendum L’s Add Back Provision.

After reviewing royalty payments, lessors found “that the producers sold oil under contracts setting the sales price … by using published index prices at the market centers downstream from the point of sale and then subtracted $18 per barrel for the buyers anticipated post-sale costs for ‘gathering and handling, including rail car transportation. That is, the sales price included an $18/barrel reduction in anticipation of the post-sale costs that the buyer would incur.

Despite the requirements in the Add Back Provision, this $18 per barrel downward price adjustment was never added back into the base royalty calculation. Essentially, the lessors’ royalty was based on a price that was $18 per barrel less than it should have been. Further examination revealed additional improper deductions, stemming from complex pricing formulas and sales contracts that accounted for the buyer’s current or expected post-sale postproduction costs.[9] In other words, there were post-production costs that were being effectively assessed against the lessors.

Claiming underpayment, the lessors filed suit, insisting that all sums that had been subtracted by the producer in anticipation of post-sales costs be added back to the royalty base. Specifically, under Add Back Provision’s language, the sales contracts’ downward adjustments were charges or reductions the producer was obligated to add to gross proceeds, to ensure the landowner royalty is not “indirectly” encumbered by postproduction costs.

The Texas Supreme Court summed up the issue as follows: “The landowners have no quarrel with how the producers have calculated gross proceeds, but they read the leases as requiring royalty to be paid on additional sums that are not gross proceeds and that do not inure to the producer’s benefit: the buyer’s actual or anticipated costs to enhance the value of production after the point of sale. In alleging royalties have been underpaid, the landowners cite the specifically written language in [the Add Back Provision] as obligating the producers to pay royalty on those expenses by adding the deducted amounts to the producer’s gross sales proceeds before calculating royalty payment.” Devon at 339.

While the Lessors claimed that royalties were to be calculated based on amounts in excess of the actual gross proceeds, the Operators interpreted the Add Back Provision as applying only to pre-sale expenses that were deducted either directly, or indirectly. As such, the $18/barrel reduction for anticipated post-sales costs was not within the proper categories of costs to be added back in to the royalty-based calculation.

Further, the Operators argued that the Add Back Provision was only surplusage, and as such, did not change the clear import of the Gross Proceeds lease. Pursuant to Heritage Resources, Inc. v. NationsBank and Judice v. Mewbourne Oil Co., under a Gross Proceeds lease, the lessor’s royalty is free of costs “only between the well and the point of sale.” Cite at 340.

Trial & Appellate Court

Both the trial court and the appellate ruled in the lessor’s favor.

two main issues were raised: (1) price adjustments of a fixed amount with a stated purpose corresponding to “production, treatment, transportation, manufacturing, process[ing] or marketing” expenses; and (2) price adjustments based on the actual costs incurred by third-party purchasers for “production, treatment, transportation, manufacturing, process[ing] or marketing” expenses.

Texas Supreme Court

On appeal to the Texas Supreme Court, the main issue was whether, under the custom lease language (i.e. the language used by the parties), there was sufficiently manifested intent to include in the royalty base post-sale production costs that had been deducted from the producer’s gross sales proceeds. The Texas Supreme Court determined that under the custom lease language used by the parties, “when the [Operators’] dispositions of production include price adjustments with a stated purposes corresponding to ‘production, treatment, transportation, manufacturing, process[ing] or marketing’ expenses, those amounts must be ‘added to’ ‘gross proceeds’ before calculating the landowners’ royalty payments.” Cite at 343.

A.    Gross Proceeds Leases
The Supreme Court of Texas explained that because the parties executed “gross proceeds” leases, they had agreed that leases weren’t bound by the typical rules, “freeing the landowner's royalty from at least some postproduction costs.”  Furthermore, the Court stated the issue was not whether the “buyer’s postproduction costs are gross proceeds under the leases…”, but rather “whether the leases nonetheless require the producers to pay on those costs.”  To that end, the Court determined that parties could make an agreement “requiring producers to pay royalty on postproduction costs incurred downstream from the point of sale” despite an absence of precedent.  Parties are generally free to contract as they see fit, so long as the agreement is not illegal.

The Add Back Provision’s broad language required that “any reduction or charge” for postproduction costs that had been reflected in the producer’s sales price be “added to” gross proceeds so that the landowners’ royalty “never” bears those costs even “indirectly.”  The provision’s purpose was to “provide the producer with the flexibility to sell production at any point downstream of the well while discharging the landowners from the usual burden to share the costs of rendering production marketable, whether through direct expenditures or indirectly through a lower valuation at the producer's chosen point of sale.” 

B.    Intent of the Parties
The Court found that the parties sufficiently expressed their intent that the lease “operate differently” as follows: “first by requiring that royalties be paid on gross proceeds and then by requiring an addition to gross proceeds for the stated purpose of freeing the landowners’ royalty from expenses and costs.” 

Second, the court noted that the Sheppard and Crain leases aligned with the Heritage Resources ruling, under which “to make a royalty free of postproduction costs, a lease could change the point at which it was valued or specify that something would be added to the royalty base.” Here, the subject leases did both.

C.    Proceeds Plus Leases
Ultimately, the Sheppard and Crain leases were declared “proceeds plus” leases that use a “two-prong calculation of the royalty base.” 
In order to calculate royalties under a Proceeds Plus lease form, the producers must first “determine their gross proceeds from selling the production, which… 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 price, those costs and expenses shall be added to the … gross proceeds.”  
The court emphasized “this 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.” 

Having overruled all the producers’ issues, the Supreme Court of Texas affirmed judgment in favor of the landowners. 

Freeport-McMoRan Oil & Gas LLC and Ovintiv USA Inc., v. 1776 Energy Partners, LLC, 672 S.W.3d 391 (Tex. 2023). Texas Natural Resources Code Suspense Statute - Safe Harbor Provisions and Interest Accrual for Proceeds Withheld

Key Takeaways

1.    Operators have Safe Harbor where the title is jacked up. 

a. The Texas Natural Resources Code allows withholding payments without interest when:

i. a “dispute concerning title” exists which “would affect distribution of payments,” or
ii. The payor has reasonable doubt that the payee has clear title to the proceeds.

2.    If a lessor wants interest in those situations, the lease or JOA must clearly and unequivocally state the same. Like, very clearly and unmistakably.
3.    As a matter of law, a constructive trust being placed on a Payee’s leasehold interests created a reasonable doubt regarding clear title to production proceeds and justified the Payor taking “safe harbor” and withholding payments without interest.

This dispute centers around the issue of whether and when “safe-harbor” provisions from the Texas Natural Resources Code can justify an operator withholding contractually obligated production payments from the owners.  The statute at issue is found in Texas Natural Resources Code Section 91.402 (“Safe Harbor Provision”)

In the present case, Ovintiv USA Inc. (“Ovintiv”) and 1776 Energy Partners, LLC (“1776”) entered into a JOA to develop acreage in Karnes County. The JOA designated Ovintiv as operator and required 1776 to pay its proportionate share of operating expenses in return for its share of production revenues.  

Longview Energy Company sued 1776, claiming rightful ownership of the leases that 1776 had contributed to the JOA with Ovintiv. Longview received a judgment against 1776, and an appeal ensued. In response, citing the Safe Harbor Provision, Ovintiv promptly halted revenue payments under the JOA. 1776’s share of the proceeds was instead deposited into a suspense account, with Ovintiv netting out the share of expenses attributed to 1776/Longview.  Ovintiv made clear that all funds would be allocated to the “rightful owner” once the dispute was fully resolved.  

Trial & Appellate Court

In response to its NRI being placed in suspense, 1776 brought action against Ovintiv for breach of contract, demanding release of the production payments plus interest.  During the course of this litigation, the judgment against 1776 in the Longview suit was overturned. Once a final judgment was entered, Ovintiv distributed the withheld payments to 1776, but still declined to pay interest. 1776 continued suit against Ovintiv order to collect interest that had accrued while the funds were withheld. 

Ovintiv won at the trial court, only to have the 4th Court of Appeals reverse the judgment, remanding the case for fact issues surrounding the safe-harbor claims.

Texas Supreme Court

On appeal to the Texas Supreme Court, Ovintiv reiterated its statutory argument that the Safe Harbor Provision authorizes operators to withhold payments without interest under certain delineated circumstances, such as title disputes. Ovintiv argued that because it had sought safe-harbor pursuant to the Texas Natural Resource Code in the face of an active title dispute, 1776 was not entitled to the interest that had accrued while the title dispute was on-going.  

Safe-Harbor Provision

While acknowledging the deadlines and penalties enforced by the Texas Natural Resources Code, the court clarified there are exceptions to these rules as well. Specifically, the “safe-harbor” provisions found in Section 91.402 sets out those instances in which a payor can withhold payments without interest: (1) a dispute concerning title that would affect the distribution of payments and (2) reasonable doubt that the payee has clear title to the/an interest in production

A.    Dispute Concerning Title
The first safe-harbor situation – Title Dispute – requires the operator to establish two essential elements: that the dispute (1) existed during the time that payments were withheld, and (2) affected distributions of payments.  
1776’s argued that the prior judgment did not affect payment distribution, as 1776 retained both legal and equitable title to the leases and interests at all times after the judgement and during the appeal. In rejecting this argument, the court revisited its past interpretations of the Safe Harbor provisions.  Following a lengthy discussion of the ordinary definitions of the words in the statute such as “would” and “affect”, the court concluded that in order to effectively invoke the Safe Harbor Provision, an operator is only required to demonstrate that the title dispute would have an expected future impact on the distribution of payments.  

Under the specific facts, regardless of whether or not legal title had actually transferred and despite the fact that there was no actual effect on payments, the court found that Ovintiv properly invoked the Safe Harbor Provision where it had a likely expectation that the prior judgment could affect distribution of payments.  Thus, an operator will not be bound to a standard requiring them to predict the future. The purpose of the Safe Harbor Provision is to provide an operator with a mechanism to avoid liability for disputes between third parties, where the operator has a clear right to develop and produce.

B.    Reasonable Doubt Regarding Clear Title
The second situation in which the Safe Harbor Provision can be invoked requires an operator to demonstrate a “reasonable doubt” that the owner (here, 1776) has “clear title to the interest in the proceeds of production.”  

The question often, as it did in this case, comes down to the reasonableness of the doubt; was the operator’s doubt reasonable? Ordinarily, reasonableness is a queston of fact for the jury to decide, such as when there is a disagreement about the facts themselves. However, in some, more limited circumstances, the question of reasonableness can be a question of law, meaning a matter for the court to decide.  Once such instance is where there is no dispute about the material facts, and only one reasonable inference can be drawn from them. Note: How do you know which one you are faced with? No clue.

Pointing to the pending lawsuit, the prior judgment, and specifically, the effects of the prior judgment (the judge placed 1776’s interest was placed in a constructive trust during the pendency of the suit), the court held Ovintiv did in fact have a “reasonable doubt” as to whether 1776 Energy held clear title.

The court inferred that simply by the court having placed the interests in a constructive trust – which is the same mechanism used for wrongfully possessed properties – the ownership title was automatically unclear and that a reasonable doubt existed as a matter of law. Because the constructive trust made ownership unclear, the court found that Ovintiv likewise had an objective reasonable doubt as to whether 1776 had clear title to the property’s well production.

Under either Safe Harbor Provision – Section 91.403(b)(1)(A) & (B)(ii), the court held that Ovintiv was entitled to withhold the interest accrued from the withheld production payments. The court appeals decision was reversed, reinstating the trial court’s decision in favor of Ovintiv.

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