The following article by James Holmes continues his review of Texas oil and gas law for royalty valuations, as it has evolved over 30 years and as it exists today. It picks up where the first Installment, released on March 22, left off. In this Installment, he reviews “market value”-style leases, “proceeds”-style leases, the “duty to market,” and lease language to prevent post-production deductions from lessening royalties.
Continuing the review of royalty-valuation law, three further pillars stand strong.
Fifth Pillar: Texas royalty-valuation language tends to fall into one of the two large categories: “market value”-style leases or “proceeds”-style leases. See Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (“‘Proceeds’ or ‘amount realized’ clauses require measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas. By contrast, a ‘market value’ or ‘market price’ clause requires payment of royalties based on the prevailing market price for gas in the vicinity at the time of sale, irrespective of the actual sale price. The market price may or may not be reflective of the price the operator actually obtains for the gas.” (citing Union Pac. Res. v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003); Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372-73 (Tex. 2001)).
“Market value” is an express contractual term – meaning, it appears as the words “market value,” “market price,” “market rate,” “field price,” or like expression in a royalty clause. Texas courts do not imply the term into the lease. “Market value” has what courts call an “objective” meaning. See, e.g., Exxon Corp. v. Middleton, 613 S.W.2d 240, 245, 246 (Tex. 1981). Texas provides that market value is “an objective basis for calculating royalties that is independent of the price the lessee actually obtains.” Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368, 374 (Tex. 2001). As an example, if the “market value” for gas-well gas was $4/MMBTU, but a producer was paying royalties on $2/MMBTU because it sold the gas to Chesapeake Energy Marketing for that price, the producer would owe royalties on $4/MMBTU – even though it never received that price.
As with “proceeds”-style leases discussed below, the phrase “at the well” (or like phrases like “in the field,” “on the land,” or “in the area”) plays an important role in “market value”-style leases. “Market value at the well has a commonly accepted meaning in the oil and gas industry. Market value is the price a willing seller obtains from a willing buyer. There are two methods to determine market value at the well.” Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118, 122 (Tex. 1996) (emphasis added; citations omitted). “The most desirable method is to use comparable sales. A comparable sale is one that is comparable in time, quality, quantity, and availability of marketing outlets.” Heritage Resources, 939 S.W.2d at 122 (citing Exxon Corp. v. Middleton, 613 S.W.2d 240, 246 (Tex. 1981); Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 872 (Tex. 1968)). “Courts use the second method [often called the “net-back” or “work-back” method] when information about comparable sales is not readily available. This method involves subtracting reasonable post-production marketing costs from the market value at the point of sale.” Heritage Resources, 939 S.W.2d at 122 (citations omitted). As a practical matter, in litigation and in royalty accounting, most producers and lessors define “market value” not by conducting “comparable sales” studies, but rather by applying the net-back method. E.g., BlueStone Nat. Res. II, LLC v. Randle, 601 S.W.3d 848, 856-57 (Tex. App. – Fort Worth 2019, pet. granted) (“Lessees seldom use the comparable-sales method because of a lack of data to make the calculation that measure requires. Instead, ‘[m]ost lessees use a different methodology for calculating their royalty payments – the ‘workback method,’ which permits [lessees] to calculate the value of their production at the wellhead by subtracting post-production costs from the price that they receive for their production at a downstream sales location.’” (citations omitted)).
Here are samples of “market value”-style oil and gas valuation clauses:
On oil (including condensate and other liquid hydrocarbons) one-sixth (1/6th) of the value of oil that flows from a well on said land. Lessee shall pay Lessor the market value thereof at the well purchased by a non-affiliated third party . . . .
On gas, including casinghead gas or other gaseous substances that flow from a well on said land, the market price at the well head of one-sixth (1/6th) of the gas . . . .
Next, proceeds obligations arise when the lease uses royalty-valuation terms such as “proceeds,” “amount realized” by the producer, or “sales” or “receipts” from sales or like language. These expressions attempt to make the producer pay royalties on what it actually received from the gas sale – on the actual sales bounty obtained by the producer’s hands. As an example, if the “market value” for gas-well gas was $4/MMBTU, but a producer was paying royalties on $2/MMBTU because it sold the gas to Chesapeake Energy Marketing for that price, the producer would owe royalties on $2/MMBTU – and not on the $4/MMBTU market price. (But if the producer knowingly, negligently or incompetently sold gas at $2/MMBTU when selling for $4/MMBTU was possible, the producer will have problems with the “duty to market” (seeSixth Pillar below) that accompanies all “proceeds”-style leases.)
As with market value royalties, proceeds or amount realized royalties typically bear a proportionate share of post-production costs, especially when the phrase “at the well” appears or the lease contemplates (expressly or implicitly) that a producer may sell oil and gas near the well or on leased premises. See Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, 573 S.W.3d 198, 205 (Tex. 2019) (“We have never construed a contractual ‘amount realized’ valuation method to trump a contractual ‘at the well’ valuation point. To the contrary, prior decisions suggest that when the parties specify an ‘at the well’ valuation point, the royalty holder must share in post-production costs regardless of how the royalty is calculated.” (citations omitted)); BlueStone Nat. Res. II, LLC v. Randle, 601 S.W.3d 848, 867 (Tex. App. – Fort Worth 2019, pet. granted) (“Further, Judice, Heritage Resources, Hyder II, and Burlington Resources [supreme court precedents] all recognize that a proceeds measure—not tied to particular point of sale—creates a measure that does not allow the lessor to net-back its post-production costs [that is, the royalty owner must bear post-production costs].”).
Here are samples of “proceeds”-style oil and gas valuation clauses:
On oil one-sixth (1/6th) of the amount received by the producer on said land. . . .
On gas, including casinghead gas or other gaseous substances that flow from a well on said land, the sales proceeds at the wellhead of one-fourth (1/4th) of the gas; where gas from said land is processed in a plant for the purpose of extracting products therefrom, Lessor shall receive as royalty one-fourth (1/4th) of the amount realized by Lessee at the plant of the products so extracted . . . .
Sixth Pillar: The so-called “duty to market” regulates below-market, affiliated and/or uncompetitive sales proceeds. This duty is present in all Texas proceeds leases, unless expressly disclaimed or supplanted with express language. It is a type of implied covenant, meaning a court reads the duty into the lease for the protection of a royalty owner. Despite the erosion of royalty-owner rights under Texas law over the past 25 years, this duty to market remains in “proceeds”-style leases. “A duty to market is [still] implied in leases that base royalty calculations on the price received by the lessee for the gas [that is, in proceeds or amount-realized leases]. A lessee may breach its implied covenant to market regardless of whether the lessee complies with the lease’s express provisions [that is, regardless of whether lessee pays royalties on its actually-received sales proceeds]; indeed, the purpose of an implied covenant claim is to protect a lessor from the lessee’s negligence or self-dealing that would result in unfairly low royalties under the express provisions.” Phillips Petroleum Co. v. Yarbrough, 405 S.W.3d 70, 78 (Tex. 2013) (cited with approval by Chesapeake Exploration, L.L.C. v. Hyder, 483 S.W.3d 870, 873 n.17 (Tex. 2016)). However, the duty is not present in “market value”-style leases; those leases have the “market value” standard to protect lessors from unfairly low royalty valuations.
The duty requires that “the lessee [producer owing royalties] must market the [oil and gas] production with due diligence and obtain the best price reasonably possible.” Cabot Corp. v. Brown, 754 S.W.2d 104, 106 (Tex. 1987) (emphasis added). The duty exists because proceeds leases – unlike market value leases – lack express language to protect royalty owners from the producers’ whims, self-dealing, incompetence, and/or errors when the producers market the royalty owners’ gas. See, e.g., Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368, 374 (Tex. 2001) (reiterating that the duty to market protects royalty owners when they lack express lease language to protect their interests: “Because the [market value] lease provides an objective basis for calculating royalties that is independent of the price the lessee actually obtains, the lessor does not need the protection of an implied covenant”).
Seventh Pillar: Texas law allows for parties to a lease – which are the producer (lessee) and the royalty owner (lessor) – to alter the default Texas rule that royalty payments must bear a proportionate share of post-productioncosts. See, e.g., Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, 573 S.W.3d 198, 203 (Tex. 2019) (“As in most situations, ‘the parties may modify this general rule by agreement.’” (citations omitted)); Chesapeake Exploration, L.L.C. v. Hyder, 483 S.W.3d 870, 876 (Tex. 2016) (“Heritage Resources does not suggest, much less hold, that a royalty cannot be made free of post-production costs.”); see also L.B. Hailey Ltd. P’ship v. Encana Oil & Gas (USA) Inc., No. 5:17-cv-00149-RCL, 2018 U.S. Dist. LEXIS 107421, at *5-*6 (W.D. Tex. June 27, 2018) (“The Texas Supreme Court held in Heritage, and later reaffirmed in Hyder, that parties may contract around having post-production costs deducted from a ‘market value at the well’ lease . . . .”).
Here are examples of parties to a lease attempting to alter the default Texas rule:
[Gas and gas products:] Lessee shall pay for Lessor’s proportionate part of the cost to make the gas market ready, including compression, treating, dehydrating and transporting gas to the trunk pipeline.
[or, in a weaker form:] If gas is gathered by, or sold to an affiliated third party of Lessee, then Lessee will pay Lessor’s cost of making the gas market ready, which includes compressing, dehydrating, treating and transporting gas to the trunk pipeline. Affiliated third party means any person or entity in which there is any ownership or shared beneficial interest with Lessee.
[Oil:] . . . If oil is purchased by an affiliated third party, then the value of the oil is that of the spot market price in the area of like gravity or the amount received by Lessee, whichever is greater.
The devil is in the details. Under legal principles called “contract construction,” Texas appellate courts will heavily scrutinize lease language attempting to alter the default rule; they will analyze severely whether the language truly exempts a royalty owner from bearing a proportionate share of post-production costs. For royalty-rights purposes, Texas law supposedly treats oil and gas leases like any other commercial contract, as shown below in an intermediate appellate court opinion and in a supreme court opinion:
An oil and gas lease is a contract, and its terms are interpreted as such. Construing an unambiguous lease is a question of law for the court. . . . In construing an unambiguous lease, [a court’s] primary duty is to ascertain the parties’ intent as expressed within the lease’s four corners.
Tana Oil & Gas Corp. v. Cernosek, 188 S.W.3d 354 (Tex. App. – Austin 2006, pet. denied) (citing Anadarko Pet. Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002); Skelly Oil Co. v. Archer, 356 S.W.2d 774, 778 (Tex. 1961); Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372 (Tex. 2001); other citations omitted.))
The [Texas Supreme] Court’s task is to “ascertain the true intentions of the parties as expressed in the writing itself.” This analysis begins with the contract’s express language. We “examine and consider the entire writing in an effort to harmonize and give effect to all the provisions of the contract so that none will be rendered meaningless.” We “give terms their plain, ordinary, and generally accepted meaning unless the instrument shows that the parties used them in a technical or different sense.” These guidelines apply to oil and gas agreements just as they would to any other contract.
Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, 573 S.W.3d 198, 202-03 (Tex. 2019) (citations omitted).
In actual application, Texas appellate courts have demonstrated patterns of not “ascertain[ing] the parties’ intent,” of not “harmoniz[ing] and giv[ing] effect to all the provisions of the contract so that none will be rendered meaningless,” and of not “giv[ing] terms their plain, ordinary, and generally accepted meaning.” Or, at least, they do a remarkably poor job of the foregoing. Legal commentators frequently criticize Texas appellate courts for not enforcing pro-lessor lease language that attempts to alter Texas’s default rule on post-production deductions. These commentators criticize the courts for striking through pro-lessor language – by calling it legal-speak words like “surplusage” – or by resolving (always resolving) conflicts between pro-lessor language and pro-lessee language in the lessee’s favor.
To benefit from Texas law’s allowance of “contracting around” the default rule – which means drafting pro-lessor language at the time of lease negotiation and execution – lessors must use a highly specialized oil and gas attorney, such as those at Holmes PLLC. If they do not do so, whatever language they draft likely will be ineffective to alter the default rule. There are a thousand ways pro-lessor lease language can die in a lawsuit involving Texas law; in order to avoid the deaths, royalty owners (lessors) must use highly specialized oil and gas attorneys to draft such language.In conclusion, the remaining pillars draw a crucial distinction between the concepts “market value” and “proceeds” in Texas royalty-valuation law. They establish also that Texas lessors must strive to include into oil and gas leases sufficient language to deter/prevent a producer’s taking of post-production deductions; on this point, he notes that Texas appellate courts will review such language very critically Accordingly, lessors must employ highly-specialized oil and gas attorneys when attempting to draft the language. In the next and final Installment, Holmes will gives his perspective on how royalty owners can best protect their rights under Texas law and industry practices, as they exist today.