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BlueStone Natural Resources II, LLC v. Randle

Court of Appeals of Texas, Second District, Fort Worth

April 18, 2019

BlueStone Natural Resources II, LLC, Appellant
v.
Walker Murray Randle; Stetson Massey, Jr.; Jo Ann Randle Massey; Sundance Minerals, LP; Deborah Lou Marshall Scherer; Marshall Scherer Ranch, LP; Sherry E. Marshall Pomykal; Marshall Pomykal Ranch, LP; Ardis Elaine Marshall; Nancy Putteet Fish; Gary M. Putteet; James Calhoun Langdon, Jr.; Sandra Wilson Langdon; Joseph Steadman Langdon; and Karen Rae Langdon, Appellees

          On Appeal from the 355th District Court Hood County, Texas Trial Court No. C2016258

          Before Gabriel, Pittman, and Bassel, JJ.

          MEMORANDUM OPINION

          DABNEY BASSEL, JUSTICE

         I. Introduction

         In this appeal's primary issue, we deal with a perennial struggle in Texas oil and gas law: Does the lessor or the lessee pay post-production costs (the processing and marketing costs of gas produced from a lease after the gas's extraction from the ground)? Appellant/Lessee characterizes the lease we interpret as "Frankenstein's Monster" with its parts cobbled together from the parts bin of oil and gas lease provisions. For this reason and others, Appellant urges that we must harmonize the terms of this unique creation to avoid having a perhaps inadvertently-included provision govern. Appellees'/Lessors' theme is that no matter its conception, we are bound by the language of the lease; that its terms dictate how to resolve conflicts in its language; and that any desire for a harmonious interpretation must give way to an obvious conflict between two of the lease's terms.

         Our specific task of interpretation begins with a royalty provision contained in a printed form lease that placed the burden on Appellees to pay post-production costs. The complication is that the parties appended additional terms to the printed form, and Appellees argue that one of the terms in the addendum created a royalty measure that shifted the burden of post-production costs onto Appellant. We conclude that the printed and appended terms are contrary to each other and that the controlling provision is in the appended terms. This resolution places the burden of paying post-production costs on Appellant. Accordingly, we affirm.

         II. Procedural Background

         The underlying litigation was originally brought in separate suits by various Appellees/Lessors. In the separate suits, Appellant and Appellees filed cross-motions for partial summary judgment that hinged on whether the provisions of the oil and gas leases at issue permitted Appellant to deduct post-production costs from royalty payments owed to Appellees. The parties entered into various stipulations regarding damages, depending on the trial court's summary-judgment ruling.

         The trial court signed orders granting Appellees' motions for summary judgment, which decreed that the leases did not permit the deduction of post-production costs and that the deduction of these costs breached the leases. The trial court then signed interlocutory judgments that again concluded that the leases did not permit the deduction of post-production costs and that the deduction of these costs breached the leases at issue. The trial court found that two additional breaches had occurred from Appellant's failure to pay royalties on what the parties stipulated to be Plant Fuel and Compressor Fuel. The interlocutory judgments awarded damages in accord with the parties' stipulations. Finally, the interlocutory judgments awarded attorneys' fees through trial but reserved the issue of appellate attorney fees for determination in a separate judgment.

         The parties next filed various agreed motions to consolidate, which the trial court granted. The trial court incorporated the interlocutory judgments into a "Consolidated Final Judgment." The Consolidated Final Judgment also awarded appellate attorneys' fees. This appeal followed.

         III. Lease Terms

         Because the primary question before us is how to interpret two terms of an oil and gas lease, we set forth the key terms. This appeal involves twelve leases, but the parties agree that the terms at issue are virtually identical among those various leases.

         Each lease has two components. The first component is a set of printed terms covering two pages. The second component is labeled "Exhibit 'A'" and also contains printed terms, which cover three pages. For ease of reference and for consistency with how the documents refer to themselves internally, we will refer to the two components as the Printed Lease and as Exhibit "A."[1]

         One of the two terms at issue is in Paragraph 3 of the Printed Lease. That paragraph provides a royalty for gas produced from the leased properties in the following fashion:

(b) on gas, including casinghead gas, or other gaseous substance produced from said land and sold or used off the premises or for the extraction of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold by Lessee the market value shall not exceed the amount received by Lessee for such gas computed at the mouth of the well, and on gas sold at the well the royalty shall be one-eighth of the amount realized by Lessee from such sale . . . .

         One of the twelve leases has a slightly different form but still states a royalty valuation for gas sold by Appellant/Lessee as "the amount realized by [L]essee, computed at the mouth of the well."

         The introductory paragraph in Exhibit "A" states, "It is understood and agreed by all the parties that the language on this Exhibit 'A' supersedes any provisions to the contrary in the printed lease hereof[.]" The other provision in controversy is Paragraph 26 of Exhibit "A." That provision states in whole as follows:

LESSEE AGREES THAT all royalties accruing under this Lease (including those paid in kind) shall be without deduction, directly or indirectly, for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and otherwise making the oil, gas[, ] and other products hereunder ready for sale or use. Lessee agrees to compute and pay royalties on the gross value received, including any reimbursements for severance taxes and production related costs.

         IV. Summary-Judgment Standard of Review

         We apply a de novo standard of review to summary judgments. Travelers Ins. Co. v. Joachim, 315 S.W.3d 860, 862 (Tex. 2010). "When competing summary-judgment motions are filed, 'each party bears the burden of establishing that it is entitled to judgment as a matter of law.'" Tarr v. Timberwood Park Owners Ass'n, Inc., 556 S.W.3d 274, 278 (Tex. 2018) (quoting City of Garland v. Dallas Morning News, 22 S.W.3d 351, 356 (Tex. 2000)). "[I]f 'the trial court grants one motion and denies the other, the reviewing court should determine all questions presented' and 'render the judgment that the trial court should have rendered.'" Id.

         V. Guiding Rules of Construction for Oil and Gas Leases

         "An oil and gas lease is a contract, and its terms are interpreted as such." Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005). "In construing an unambiguous oil and gas lease, . . . we seek to enforce the intention of the parties as it is expressed in the lease." Id. "We give terms their plain, ordinary, and generally accepted meaning[s] unless the instrument shows that the parties used them in a technical or different sense." Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex. 1996).

         "We examine the entire lease and attempt to harmonize all its parts, even if different parts appear contradictory or inconsistent." Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002) (citing Luckel v. White, 819 S.W.2d 459, 461 (Tex. 1991)). A court examines all of the lease's provisions "because we presume that the parties to a lease intend every clause to have some effect." Id. (citing Heritage Res., 939 S.W.2d at 121). Finally, we "cannot change the contract merely because we or one of the parties comes to dislike its provisions or thinks that something else is needed in it." Arlington Surgicare Partners, Ltd. v. CFL Invs., LLC, No. 02-15-00090-CV, 2015 WL 5766928, at *2 (Tex. App.-Fort Worth Oct. 1, 2015, no pet.) (mem. op.) (quoting Cross Timbers Oil Co. v. Exxon Corp., 22 S.W.3d 24, 26 (Tex. App.-Amarillo 2000, no pet.)).[2]

         VI. Overview of Royalty Provisions and the Allocation of Post-Production Costs

         As noted in the introduction, one frequent source of conflict between lessors and lessees and the central conflict in this appeal is which party bears the costs of processing minerals once they are extracted from the ground, i.e., which party will bear the post-production costs. The unique terminology used to express the calculation of a royalty, especially a gas royalty, requires a description of the standard practice in allocating costs, the structure of a royalty clause, and the nuances in arcane oil and gas terminology that impact the question of the allocation of post-production costs.

         At its most elementary level, a royalty is the landowner's share of production from a lease. See U.S. Shale Energy II, LLC v. Laborde Props., L.P., 551 S.W.3d 148, 154 (Tex. 2018). Of course, there are costs both for bringing the minerals, such as oil and gas, to the surface and for processing those minerals once they are brought out of the ground. The issue of which party to a lease pays the post-production processing costs of gas is of greater moment than for the processing of oil:

[U]nlike oil, which is typically sold to a refinery from storage tanks near the well and trucked to the refinery, the sale of gas involves substantial costs after the gas is brought to the surface. The gas must be compressed, processed, and transported to a market hub. Those operations are often expensive[] but usually increase the value of the gas.

         Joseph Shade & Ronnie Blackwell, Primer on the Texas Law of Oil & Gas, 59 (5th ed. 2013).

         In Texas, a royalty is free of the expenses of production-the expenses of bringing it to the surface. Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 872 (Tex. 2016) (op. on reh'g) (Hyder II) (citing Heritage Res., 939 S.W.2d at 121-22); Chesapeake Expl., L.L.C. v. Hyder, 427 S.W.3d 472, 480 (Tex. App.-San Antonio 2014) (Hyder I), aff'd, 483 S.W.3d 870 (Tex. 2016). The contrary is true of the costs incurred once the minerals reach the surface, and the "royalty is usually subject to post-production costs, including taxes, treatment costs to render it marketable, and transportation costs." Heritage Res., 939 S.W.2d at 122. As with any contract, the parties may modify the general rule that the lessor bears the post-production costs. Hyder II, 483 S.W.3d at 872; Heritage Res., 939 S.W.2d at 122.

         To try to bring some order to our review of how the leases at issue dealt with post-production costs, we begin with a brief description of royalty clauses. One commentator has superimposed a structure on royalty clauses and described the clauses as commonly having the mechanics of "at least three components: (i) the royalty fraction-e.g., 1/8th, 25%, 1/5th; (ii) the yardstick-e.g., market value, proceeds, price; and (iii) the location for measuring the yardstick-e.g., at the well, at the point of sale." Byron C. Keeling, In the New Era of Oil & Gas Royalty Accounting: Drafting a Royalty Clause That Actually Says What the Parties Intend It to Mean, 69 Baylor L. Rev. 516, 520 (2017). This appeal focuses on the second and third components.

         The second component-establishing "the yardstick"-may create a payment measure that looks to an outside source, such as a market value, or may simply reflect what was received in payment for the minerals, i.e., the proceeds of the sales of the minerals. Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008). The supreme court has provided a succinct description of the two measures:

"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. Union Pac. Res. [Grp.] v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003) (citing Yzaguirre [v. KCS 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 price for gas in the vicinity at the time of sale, irrespective of the actual sale price. Yzaguirre, 53 S.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.

Bowden, 247 S.W.3d at 699; see Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, No. 17-0266, 2019 WL 983789, at *4 (Tex. Mar. 1, 2019) (discussing "proceeds" or "amount realized" yardstick).[3]

         Because of its complexity, we will look first at the market-value yardstick. One method of making the market-value determination relies on comparable sales, looking for sales that are "comparable in time, quality, quantity, and availability of marketing outlets." Heritage Res., 939 S.W.2d at 122. Lessees seldom use the comparable-sales method because of a lack of data to make the calculation that measure requires. Keeling, supra, at 531.

         Instead, "[m]ost lessees use a different methodology for calculating their royalty payments-the 'workback method,' which permits them 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." Id. Or as the supreme court described the alternate methods of calculation: “Evidence of market value is often comparable sales, . . . or value can be proven by the so-called net-back approach, which determines the prevailing market price at a given point and backs out the necessary, reasonable costs between that point and the wellhead.” Heritage Res., 939 S.W.2d at 130 (Owen, J., concurring).[4]

         The third component of the royalty mechanism-the location for measuring the yardstick-is a vital part of the royalty calculation. It establishes the point from which a lessee works back to determine market value. Keeling, supra, at 530-32. The third component does this by setting the point along the process from production to sale where the value determination is made. Id. at 524. Determining this location is pivotal because of the process of gas becoming more valuable as it moves away from the point where it was extracted from the ground (the wellhead) to a point downstream in the refining process and eventually to its sale. Id. at 524-25. To elaborate on the point we made initially, moving away from the wellhead adds value; thus, "[o]il and gas production is less valuable at the wellhead because any arm's length purchaser will assume that it will have to incur the cost to remove impurities from the production, to transport it from the wellhead, or otherwise to get it ready for sale to a downstream market or the general public." Id.

         Tying the allocation of post-production costs to a point set between production and sale creates the potential for unpleasant surprises for lessors. Contrary to what a drafter unschooled in the nuances of oil and gas law might think, a lease usually does not express the allocation by saying that one party or another will or will not pay the post-production costs. Indeed, as discussed below, a provision making that simple statement may be interpreted as empty words when inserted in a royalty clause that expresses the allocation of costs in more traditional oil and gas jargon.

         A traditional expression-that requires the lessor to bear all the post-production costs-places the third component (that establishes the location for measuring the yardstick) "at the well." Id. at 530-32. Thus, if market value is the yardstick, the point of measuring the yardstick is "market value at the well," which has a commonly accepted meaning. Heritage Res., 939 S.W.2d at 122. This measure places the burden of paying post-production costs on the lessor because gas that has just emerged from the ground has not yet been "transported, treated, compressed, or otherwise prepared for market," and the market value at the well does not include the value added by those yet-to-occur processes. Id. at 130. The lessee recoups its expenses by working back the value from the amounts received in payment for the minerals, with the lessor's royalty payment being the amount that the lessee received from the sale of the minerals net of all the expenses incurred by the lessee from the point that the minerals emerged from the ground to the point that they were sold. Keeling, supra, at 531-32. In other words, the lessor bears the burden of post-production costs because the lessee deducts those costs from the price it receives and remits to the lessor the amount received net of the amount of the post-production costs. Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 135 (Tex. 1996) ("[Market value at the well] means value at the well, net of any value added by compressing the gas after it leaves the wellhead.").[5]

         Because of the nuances in expressing the allocation of post-production costs, there is sometimes a "night-is-day" feeling to the results in interpreting royalty clauses. We noted above that inserting a statement in a lease to specify who will or will not bear the post-production costs may have no effect. Blindly inserting a provision that states no post-production costs shall be deducted from the value of the lessor's royalty in juxtaposition to a provision that sets the valuation yardstick "at the well" is an exercise in futility. As one commentator noted, in leases that provide for the net-back of post-production expenses, "there are times when the express language of the lease may contain conflicting or inconsistent signals." Patrick H. Martin & Bruce M. Kramer, 6 Williams & Meyers Oil & Gas Law, § 645.2 at 614.8(1) (2018 ed.).

         The supreme court explained this interpretive twist in Heritage Resources. 939 S.W.2d at 120. The royalty clause in Heritage Resources set the yardstick at the market value of the gas produced from the lease and the point where to measure the yardstick at the well. Id. at 120-21. But the royalty provision also included a statement-often referred to as a "no-deductions clause"-that on its face appeared to say that the lessor would not be charged post-production costs: "[T]here shall be no deductions from the value of lessor's royalty by reason of any required processing, costs of dehydration, compression, transportation, or other matter to market such gas." Id. at 121.

         The quoted provision was not enough to put the genie back into the bottle and save the lessor from the commitment in the first portion of the royalty clause to have the market value of the royalty measured at the well, with its corresponding commitment to allow the lessee to net-back post-production costs it had incurred between the well and the point of sale of the gas. Id. at 130-31. The additional phrase did not conflict with the "at the well" royalty formulation or render the clause ambiguous; the "no deduction of post-production expenses" clause simply meant nothing. Id. In the supreme court's view, the appended phrase was surplusage:

As long as "market value at the well" is the benchmark for valuing the gas, a phrase prohibiting the deduction of post-production costs from that value does not change the meaning of the royalty clause. Thus, even if the Court were to hold that a lessee's duty to market gas includes the obligation to absorb all of the marketing costs, the proviso at issue would add nothing to the royalty clause. All costs would already be borne by the lessee. It could not be said under that circumstance that the clause is ambiguous. It could only be said that the proviso is surplusage.

Id.[6]

         Though the no-deductions clause in Heritage Resources meant nothing, that does not mean that a lessor cannot find language to shift the burden for post-production costs to the lessee. As noted, the supreme court has acknowledged that the parties may agree to allocate the post-production costs however they wish. Hyder II, 483 S.W.3d at 872; Heritage Res., 939 S.W.2d at 122. The parties can specify a different point to measure the yardstick and place the point of valuation further down the path from production to sale. Heritage Res., 939 S.W.2d at 131 ("If [the parties] had intended that the royalty owners would receive royalty based on the market value at the point of delivery or sale, they could have said so.").

         Another method a lessor may use to avoid the burden of post-production expenses is to specify a different yardstick than market value. When we first described the second component of the royalty clause, we noted that one of the other yardsticks that could be used to measure the royalty was proceeds. See Keeling, supra, at 521-22. By specifying the yardstick of the amount the lessee actually receives, the royalty provision may also remove the lessee's ability to net the post-production expenses out of the payment it makes to the lessor. Hyder II, 483 S.W.3d at 873. To make our own contribution to the jargon of royalty measures, we will refer to this as a pure-proceeds measure.

         One example using this simplified mechanism/pure-proceeds measure specifies that the lessee receives a percentage share "of the price actually received" by the lessor. Id. at 871. The supreme court described the effect that this measure has on the allocation of post-production costs as follows: "Often referred to as a 'proceeds lease,' the price-received basis for payment in the lease is sufficient in itself to excuse the lessors from bearing postproduction costs." Id. As a federal court interpreting a royalty clause also noted, one method for a lessee to shift the burden of paying post-production costs is to say "in the addendum that the lessor was entitled to 22.5% of the actual proceeds of the sale, regardless of the location of the sale." Warren v. Chesapeake Expl., L.L.C., 759 F.3d 413, 418 (5th Cir. 2014). The supreme court recently summarized how a proceeds-based measure may affect the allocation of post-production costs: "This Court and other courts have recognized that an agreement to value a royalty interest based on the 'amount realized,' or similar language, can grant the royalty holder the right to a percentage of the sale proceeds with no adjustment for post-production costs." Burlington Res., 2019 WL 983789, at *4.[7]

         But a location for measuring the yardstick can also be superimposed on the proceeds measure. Specifically, the addition of the words "at the well" to a proceeds measure reverses course and restores the burden of post-production costs to its traditional place in the lessor's column. The supreme court recently (and succinctly) made the point that it has "never held that an 'amount realized' valuation method frees a royalty holder from its usual obligation to share post-production costs even when the parties have agreed to value the royalty interest at the well." Id. at *5. The "at the well" valuation point controls the allocation of post-production costs, apparently, no matter the underlying yardstick as noted by the supreme court:

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.

Id. (citing Warren, 759 F.3d at 417-18; Judice, 939 S.W.2d at 136; Heritage Res., 939 S.W.2d at 123).[8]

         But to take the interpretive process fully down the rabbit hole, there may be documents that state both a pure-proceeds measure and another value tied to an "at the well" measure. Then, the measures of royalty contradict one another. See Judice, 939 S.W.2d at 136. The supreme court has highlighted that an instrument using the term "gross proceeds" is at odds with "at the well" language and with its mechanism to place the burden of post-production costs on the lessee: "The term 'gross proceeds' means that the royalty is to be based on the gross price received by [Lessee] Mewbourne. The use of the term 'at the well' indicates just the opposite, that the royalty is to be based on its value 'at the well.'" Id.; see also Heritage Res., 939 S.W.2d at 130 (stating that court was not presented with a clause similar to the one at issue in Judice in which "a division order directed royalties to be based on 'gross proceeds realized at the well, '" and that there is an "inherent, irreconcilable conflict between 'gross proceeds' and 'at the well' in arriving at the value of the gas," which is a "conflict [that] renders the phrase ambiguous").

         VII. Appellees'/Lessors' Royalty Is Not Burdened with Post-Production Costs

         In its first issue, Appellant argues that the unambiguous leases allow for the deduction of post-production costs. Thus, our discussion up to this point has not been purely academic. Instead, it gives context to Appellant's and Appellees' themes in this appeal. To elaborate on the themes described above, Appellant's theme is one of harmony, arguing that we must view the various provisions at issue from a starting point that Paragraph 3 of the Printed Lease creates a market-value-at-the-well measure for Appellees' gas royalty-a measure that no one disputes saddles Appellees with the post-production expenses. With this baseline, and driven by the goal of a harmonious interpretation, Appellant argues that the terms in Paragraph 26 of Exhibit "A" attached to the Printed Lease do not alter-but rather are "baked into," as Appellant calls it-this yardstick of royalty valuation.

         Appellees' theme is conflict. They argue that the provisions of the Printed Lease and Exhibit "A" irreconcilably contradict each other because one embodies a market-value-measured-at-the-well yardstick and the other a pure-proceeds yardstick. In the event of a conflict between the documents, Exhibit "A" commands that its terms supersede those of the Printed Lease. In Appellees' view, Exhibit "A's" pure-proceeds measure controls and so burdens Appellant with the post-production expenses.

         With those themes as a backdrop, our analysis will progress as follows:

• The Printed Lease creates an "at the well" royalty yardstick and measure;
• Exhibit "A" attached to the Printed Lease provides that when the terms of the two documents are contrary to the other, Exhibit "A" supersedes, and the lack of a specific direction in Paragraph 26 that it controls in the event of a conflict is not necessary to give that paragraph a superseding effect if it conflicts with the royalty provision of the Printed Lease;
• The test to determine whether the terms of the Printed Lease and Exhibit "A" are contrary to each asks whether the terms of each are so inconsistent they cannot subsist together;
• Paragraph 26 as a whole creates a pure-proceeds measure of royalty, which is contrary to the Printed Lease's "at the well" measure, and thus Exhibit "A" supersedes;
• The failure of Paragraph 26 to specifically alter the point of sale does not prevent it from superseding the different royalty measure in Paragraph 3;
• The El Paso court's opinion in SandRidge, [9] at first blush, may appear to conflict with our analysis, but it does not address the specific arguments we resolve; and
• Paragraph 26 cannot be read as a backstop provision to deal with disparities between the market price of gas and the price for which gas is sold under long-term contracts.

         A. We set forth the Lease Provisions and their effect on the royalty determination.

         1. The Printed Lease establishes a market-value-at-the-well royalty yardstick.

         No one disputes that the measure of royalty is created by Paragraph 3 of the Printed Lease. That paragraph provides in relevant part that the royalty on gas is "the market value at the well of one-eighth of the gas so sold or used." Breaking down the royalty clause into the components described above, (1) the Appellees'/Lessors' fractional share of the production is 1/8, (2) the yardstick of the valuation is market value, and (3) the location for measuring the yardstick is "at the well."[10] On its own, Paragraph 3 states the classic formulation that permits a lessee to net-back the post-production expenses it incurs between the well and the point of sale of the gas. In other words, the Appellees/Lessors bear those expenses under Paragraph 3.

         2.The first sentence of Paragraph 26 of Exhibit "A" in isolation duplicates the no-deduction clause that the Texas Supreme Court has ...


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