The Oil and Gas Addendum

Let’s assume you own a 175 acre farm in Tioga County. In 2020, you negotiated a new oil and gas lease with XYZ Drilling (the “2020 Lease”). During the negotiations you told the landman that the standard royalty clause in XYZ’s pre-printed lease form, which stipulates a 15% royalty “at the wellhead”, was unacceptable. You negotiated an addendum clause which says your royalty of 15% “shall never bear, either directly or indirectly, any cost or expense to dehydrate, compress, gather, process or transport” the raw gas.  Several years later, you receive your first royalty statement from XYZ Drilling. You are shocked, angry and confused. The royalty statement depicts significant deductions for dehydration, compression and gathering.  You call XYZ Drilling and tell them there must be a mistake as the 2020 Lease addendum prohibits all deductions. They say there is no mistake – the pre-printed royalty clause still mandates a valuation point at the wellhead. Given that language, XYZ Drilling asserts that the downstream costs (i.e. dehydration, compression and gathering) can be deducted from the sales price to arrive at a so-called wellhead value. How is this possible?  Can the driller ignore the agreed-upon addendum and instead rely on the boiler-plate language in the pre-printed lease form to authorize deductions? A recent decision by the Texas Court of Appeals suggests the driller can. This is troubling news for landowners.

At issue in Devon Energy v. Oliver were two (2) nearly identical oil and gas leases entered into in 2007 covering approximately 3,700 acres in DeWitt County, Texas (the “2007 Lease”). Paragraph 3 in the pre-printed lease form provided as follows:

“As royalty lessee covenants and agrees: (a) To deliver to the credit of lessor, in the pipeline to which lessee may connect its wells, the equal 1/5th part of all oil produced and saved by lessee from said land, or from time to time, at the option of lessee, to pay lessor the average posted market price of such 1/5th part of such oil at the wells as of the day it is run to the pipeline or storage tanks, lessors interest in either case to bear 1/5th of the cost of treating oil to render it marketable pipeline oil. . .”

Deven Energy argued that Paragraph 3 fixed the royalty valuation point at the wellhead. Mr. Oliver, however, contended that Paragraph 3 was modified and superseded by several clauses in the negotiated lease addendum. For example, Paragraph 15 of the addendum expressly prohibited the deduction of any costs:

“Lessor’s royalty on hydrocarbons shall never bear, either directly or indirectly, any portion of (a) the cost of expenses to save, store, gather, dehydrate, compress, pipe, truck, transport, treat, separate, process, refine, manufacture or market hydrocarbons on or from the leased premises, (b) the costs of expenses (including depreciation) to construct, repair, renovate or operate any plant or other facilities or equipment used in connection with treating, separation, extraction, processing, refining, manufacture or marketing of hydrocarbons produced from the leased premises or lands pooled therewith (c) any other costs or expenses whatsoever, except, Lessor’s royalty shall bear it proportionate part of all ad valorem, excise, state severance taxes, windfall profits taxes, or like and similar tax imposed on such hydrocarbons or on the value thereof that is attributable to Lessor’s royalty, if any, paid by Lessee, which proportionate part may be deducted from Lessor’s royalty interest before payment to Lessor.”

Likewise, Paragraph 38 of the lease addendum further modified the manner by which Mr. Oliver could further take his royalty “in-kind”:

“Lessor reserves the right to take, receive and market Lessor’s royalty share of all oil, in kind, to be delivered by Lessee to Lessor at the wells into facilities provided by Lessee, or at the direction of Lessor, into pipelines connected therewith, free and clear of all costs and expenses. Lessor may exercise Lessor’s right to take and market in kind by giving thirty (30) days written notice to Lessee. Pending such notice, Lessee shall purchase of market Lessor’s oil at a case price equal to the market value on the day of sale.

Because Paragraph 15 and Paragraph 38 conflicted with the terms and substance of Paragraph 3, Mr. Oliver argued that those clauses (i.e. Paragraphs 15 and 38) controlled and governed the royalty calculation.[1]  Under his view, no deductions were authorized under the 2007 Lease.

Devon Energy disagreed. Under Devon Energy’s interpretation, the royalty valuation point set forth in Paragraph 3 was not modified or changed by any addendum terms.  This was legally significant. If the royalty valuation point was “at the wells”, Devon Energy could utilize the “net-back” method to deduct the costs incurred between the wellhead and the downstream point-of- sale. See, The Net-Back Method Does Not Result in Better Pricing to Justify Deductions Under Market Enhancement Clause (October 2021). Devon Energy argued that neither Paragraph 15 or Paragraph 38 even mentioned, let alone changed, the royalty valuation point and, therefore, those paragraphs did not and could not conflict with Paragraph 3. Devon Energy suggested that all three clauses could be read together and given effect.  As such, Devon Energy asserted that the deductions were lawful and proper under the auspices of the “net-back” method. 

Mr. Oliver filed suit in April 2016 alleging a breach of the 2007 Lease. After several years of discovery, the parties filed cross-motions for summary judgment. The trial court granted Mr. Oliver’s motion, opining that Paragraph 15 and 38 controlled.  Critically, the trial court specifically ruled that Mr. Oliver’s royalty “is not valued at the well.” This negated Devon Energy’s reliance on the “net-back” method and arguably invalidated all of the deductions.  See, Texas Supreme Court Rules That Gross Royalty Clause Prohibits Drillers from Deducting Post-Production Costs (March 2021). Having determined Devon Energy’s liability for breach of the 2007 Lease, the trial court conducted a jury trial in July 2024 solely on the issue of damages. The jury awarded $15,800,000. Devon Energy immediately appealed to the 13^th District Court of Appeals in Corpus-Cristi, Texas.

Before we address the substance of the Court of Appeals’ opinion, a brief primer on the typical structure of a royalty clause is warranted. Almost every royalty clause has three (3) basic components: i) the royalty fraction (i.e. 1/8^th or 12.5%, etc.), ii) the “yardstick” (e.g. market value, proceeds or price) and iii) the location for measuring the “yardstick” (e.g. at the wellhead or the point-of sale). See, Bluestone Natural Resources v. Walker-Murray, 620 S.W.3d 380 (Texas 2021). Let’s take a closer look at the second and third components.

The “yardstick” component provides guidance as to the source of the royalty. There are typically two “yardsticks” which are utilized in modern oil and gas leases: the market value of the gas or the actual proceeds generated from the sale of gas. The Texas Supreme Court further described the two “yardsticks” as follows:

“Proceeds” or “amount realized” clause required measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas.  Union Pac. Res. [Grp.] v. Hankins, 111S.W.3d 69, 72 (Tex. 2003) (citing Yzaguirre [v. KCA Res., Inc.], 53 S.W.3d [368,] 372 [(Tex.2001)]. By contrast, a “market value” or market price” clause requires payment of royalties based on the prevailing market for gas in the vicinity at the time of sale, irrespective of the actual sale price. Yzaguirre, 53 5.W.3d at 372. The market price may or may not be reflective of the price the operator actually obtains for the gas. Id. At 372-73.

See, Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008).

There are generally two methods of determining the market value of gas: i) comparable sales or ii) the “net-back” method. Under the comparable sales method, the value of the gas at the wellhead is calculated by averaging the prices that the driller and other producers have received in the same production field for gas of comparable quality and quantity. Evidence of comparable sales, however, is often difficult to ascertain, so the work-back or net-back method developed as the preferred alternative. Under this method, the value of the gas at the wellhead is calculated by taking the downstream sale price and subtracting the processing and movement costs incurred between the wellhead and the point-of-sale. See, Atlantic Richfield v. State, 262 Cal. Rptr, 683, 688 (Cal. Ctr. App. 1989) (noting that the royalty is calculated “by working back from the price of the point-of-sale, deducting the cost of processing and transportation from the wellhead”). Thus, when there is no actual market for gas at the wellhead or when there is insuffcient evidence of comparable sales, the net-back method allows a driller to calculate an artificial value of the gas at the wellhead by subtracting the intervening costs. See, Kilmer v. Elexco Land Services, 980 A.2d 1147 (Pa. 2010) (“. . . we must work backward from the value-added price received at the point-of-sale by deducting the companies’ cost of turning the gas into a marketable commodity”).

The second “yardstick” measures the royalty on the proceeds actually received by the lessee. The Texas Supreme Court has consistently held that under a “proceeds” clause or an “amounts realized” clause, the landowner is granted “the right to a percentage of the sale proceeds with no adjustment for post-production cost.” See, Burlington Resources, 573 S.W.3d 198 (Tex. 2019); see also, Chesapeake Exploration, LLC v. Hyder, 483 S.W.3d 870, 871 (Tex. 2016) (noting that under a ‘proceeds lease’, the price-received basis for payment in the lease is sufficient itself to excuse the lessors from bearing post-production costs”); Warren v. Chesapeake Exploration, 759 F.3d 413 (5^th Cir. 2014) (stating that an “amount realized” clause, standing alone, will create a royalty interest free of post-production costs); Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (“[P]roceeds clauses require measurement of the royalty based on the amount of the lessee in fact receives under its sales contract for the gas”); Judice v. Mewbourne Oil Co., 939 S.W.2d 133 (Texas 1996) (“the term gross proceeds mean the royalty is to be based on the gross proceeds received. . .”). So, unlike the market value “yardstick”, the proceeds “yardstick” is typically free of post-production costs. Both “yardsticks”, however, can be impacted by the third and final component: the location where the “yardstick” is measured.

The third component is critical. It establishes the point from which the lessee, if necessary, “works back” to calculate and determine the value of the gas.  See, Bluestone Natural Resources, supra.  The “yardstick” is typically measured at either two locations: at the wellhead or at the point-of-sale. This is commonly known as the royalty valuation point.  If the valuation point is designated at the wellhead, but the gas is actually sold downstream, then, in that instance, the driller may utilize the net-back method to deduct the intervening processing and movement costs to arrive at a wellhead value.  Generally, a market value “yardstick” is typically associated with an “at the wellhead” valuation point. Conversely, if the royalty valuation point is at the point-of-sale, there is no need to work backwards to the wellhead and no costs need to be deducted. In practice, the second “yardstick” (i.e., proceeds) is usually measured at the point-of-sale. See, Bluestone Natural Resources, supra. (“[W]hen proceeds are valued in gross. . .the valuation point is necessarily the point-of-sale because that is where the gross is realized and received.”).  Confusion can arise when the royalty clause mixes concepts and combines a market value “yardstick” with a point-of-sale valuation point. See, Pennsylvania Superior Court Rules that Royalty Clause Referencing Both ‘Gross Proceeds’ and ‘At the Well’ was Ambigous (May 2022).

Back to Devon Energy. The pivotal issue on appeal was identifying the location to measure the “yardstick”. As noted, Devon Energy contended that Paragraph 3 fixed the valuation point “at the wells” and nothing in the addendum changed or moved this location. Mr. Oliver conceded that the addendum did not expressly identify an alternative location but suggested that Paragraph 15 implicitly required the royalty be “valued” at the location where no post-production costs could legally be deducted: the point-of-sale.

The Court of Appeal rejected Mr. Oliver’s creative argument. The panel noted that the valuation point fixed by Paragraph 3 was not modified or changed by any clause in the addendum. This omission was fatal to Mr. Oliver’s theory. In a rather rigid and formalistic approach, the Court of Appeals gave significant weight to the wellhead location set forth in Paragraph 3.  And since this valuation point was never changed, the language in Paragraph 15 was merely surplusage and had no bearing on the royalty calculation:

“[I]m other words, ‘at the wells’, no post-production costs shall be borne. Such is mere surplusage, meaning the parties did not need to include the post-production language because there are no post-production costs borne ‘at the wells’ over which the language could govern.”

The panel therefore opined that since the royalty valuation point is “at the wells as of the day it is run to the pipeline. . .”, the trial court erred when it granted summary judgment in favor of Mr. Oliver. This error was “harmful” and “caused the rendition of an improper judgment.” As such, the Court of Appeals reversed the jury award and remanded the matter back to the trial court for further proceedings.

So what is the takeaway from the Devon Energy decision? Better drafting. Mr. Oliver’s claim failed, in large part, because the lease addendum did not move or change the royalty valuation point. Simply saying that the royalty “shall never bear” any post-production costs may not be enough if the valuation point remains at the wellhead. Care must be taken when drafting a royalty addendum to ensure that the “yardstick” and the location to measure the “yardstick” are congruent and aligned. Ideally, the addendum should contain language which expressly states that the wellhead will never be utilized as the royalty valuation point. Because Paragraph 15 and Paragraph 38 neglected to change the valuation point, the Court of Appeals was compelled under Texas law to enforce the 2007 Lease as drafted.  Although not binding on Pennsylvania courts the Devon Energy decision is a stark reminder that careful and precise drafting should be employed when negotiating a new oil and gas lease.

[1] The addendum expressly stated that it “shall control and supersede” anything in the pre-printed base lease form.