
    BURLINGTON RESOURCES OIL & GAS COMPANY LP, Appellant, v. TEXAS CRUDE ENERGY, LLC and Amber Harvest, LLC, Appellees.
    NUMBER 13-16-00248-CV
    Court of Appeals of Texas, Corpus Christi-Edinburg.
    Delivered and filed March 2, 2017.
    
      Hon. Michael V. Powell, Locke, Lord, LLP, Dallas, TX, for Appellant(s).
    Hon. Edward John “Jack” O’Neill, Pierce & O’Neill, Houston. TX, for Appel-lee(s).
    Before Justices Rodriguez, Contreras, and Longoria
    
      
      . Justice Dori Contreras, formerly Dori Contreras Garza. See Tex. Fam. Code Ann. § 45.101 et seq. (West, Westlaw through 2015 R.S.).
    
   OPINION

Opinion by

Justice Contreras

In this permissive appeal, we are asked whether appellant Burlington Resources Oil & Gas Company LP (“Burlington”) may deduct post-production expenses from overriding royalty payments made under certain assignment instruments. The trial court concluded that the assignments did not allow for the deduction of post-production expenses and it rendered summary judgment in favor of appellees Texas Crude Energy, LLC (“Texas Crude”) and Amber Harvest, LLC (“Amber”). We affirm.

I. Background

In 2004, Burlington and Texas Crude entered into a Prospect Development Agreement (“PDA”) and Joint Operating Agreement (“JOA”) for the exploration and development of Sugarkane Field, an oil and gas producing area within the Eagle Ford Shale region in Atascosa, Bee, Karnes, and Live Oak Counties. The PDA also applied to any future leases acquired by the parties in an “Area of Mutual Interest.” Under the PDA, Burlington was named operator of the field and each party was to acquire a percentage of the other’s working interests in oil and gas leases within the field which they had already acquired. Specifically, Burlington was to own 87.5% of the working interest in the leases previously acquired by either of the parties, and Texas Crude was to own the remaining 12.5%. As to any future leases acquired by either of the parties within the “Area of Mutual Interest,” the parties agreed to offer to the other party the same percentages specified for the existing leases—that is, Texas Crude would offer an 87.5% working interest in any leases it acquired to Burlington, and Burlington would offer a 12.5% working interest in any leases it acquired to Texas Crude.

As consideration, the PDA also provided that Texas Crude would have the right to retain or be assigned an overriding royalty interest (“ORRI”) in every lease that was owned or thereafter obtained by either party within the “Area of Mutual Interest.” On May 22, 2006, Texas Crude assigned Burlington an 87.5% interest in various leases owned within the “Area of Mutual Interest.” The assignment stated that it is subject to the terms and conditions of the PDA and JOA, and that in the event of a conflict between the terms of the assignment and the terms of the PDA, the PDA terms shall control. Prior to making the assignment to Burlington, Texas Crude reserved ORRIs in accordance with the terms of the PDA and JOA, and it then conveyed those ORRIs to Amber, Texas Crude’s affiliate.

Over the next several years, Texas Crude acquired various other oil and gas leases within the “Area of Mutual Interest.” As to each lease, Texas Crude assigned ORRIs in those leases to Amber prior to assigning the 87.5% working interest to Burlington, and each ORRI assignment to Burlington was made expressly “[sjubject to all burdens of record” existing at the time of the assignment, including the previously-assigned ORRIs. Burlington also acquired leases within the “Area of Mutual Interest” and, pursuant to the PDA and JOA, it assigned the required ORRIs to Texas Crude, which then assigned the ORRIs to Amber.

Each instrument conveying an ORRI, whether from Burlington to Texas Crude or from Texas Crude to Amber, provided substantially as follows in its granting clause:

[Assignor] does hereby ASSIGN, TRANSFER AND CONVEY unto [As-signee], its successors and assigns, an overriding royalty interest in the quantity described below in all oil, gas, condensate, drip gasoline and other hydrocarbons that may be produced and saved from those lands covered by those certain oil, gas and mineral leases described in Exhibit “A” attached hereto and made a part hereof for all purposes, and pursuant to the terms and conditions of the said oil, gas and mineral leases. Said overriding royalty interests shall be delivered to ASSIGNEE into the pipelines, tanks or other receptacles with which the wells may be connected, free and clear of all development, operating, production and other costs. However, ASSIGNEE shall in every case bear and pay all windfall profits, production and severance taxes assessed against such overriding royalty interest,

(Emphasis added.)

The assignments each further stated substantially as follows:

This Assignment and the interest assigned hereby shall be subject to the following terms and provisions, to wit:
The overriding royalty interest share of production shall be delivered to AS-SIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected, free and clear of all royalties and all other burdens and all costs and expenses except the taxes thereon or attributable thereto, or ASSIGNOR, at ASSIGNEE’S election, shall pay to AS-SIGNEE, for ASSIGNEE’S overriding royalty oil, gas or other minerals the applicable percentage of the value of the oil, gas or other minerals, as applicable, produced and saved under the leases. “Value’’, as used in this Assignment, shall refer to (i) in the event of an arm’s length sale on the leases, the amount realized from such sale of such production and any products thereof, (ii) in the event of an arm’s length sale off of the leases, the amount realized for the sale of such production and any products thereof, and (Hi) in all other cases, the market value at the wells.

(Emphasis added.) Under these terms, if the owner of the ORRI chooses to receive its share of production in-kind, that share must be delivered “into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected, free and clear of all royalties and all other burdens and all costs and expenses except the taxes thereon or attributable thereto.” On the other hand, if the owner of the ORRI chooses not to receive its share in-kind but rather as a cash payment, the amount of the payment must be based on the “amount realized” from the sale of the minerals if sold in an “arm’s length sale,” or based on the “market value at the wells” if not sold in an “arm’s length sale.”

It is undisputed that, as operator of the field, Burlington sold all oil and gas produced under the leases at issue in “arm’s length sales” and Amber elected to receive all royalties in cash. According to Burlington, the ORRI payments it made to Amber “clearly identified post-production deductions that were being taken within the royalty calculation, such as transportation and processing, both on a gross basis for 100% of the production and for [Amberj’s ORRI percentages.”

Eventually, numerous disagreements arose between the parties, and appellees filed suit, alleging that Burlington (1) incorrectly deducted post-production expenses from the ORRI payments to Amber and (2) failed to comply with its duties under the PDA and JOA in various other ways. Among other forms of relief, appel-lees requested breach of contract damages “equal to the difference between the amount of overriding royalties actually paid by Burlington for the wells [at issue] and the amount [appellees] would have received if the overriding royalties had been paid correctly for these wells.”

On August 4, 2015, Burlington filed a motion for partial summary judgment regarding the issue of the deduction of post-production costs. The motion argued that Burlington is entitled to judgment as a matter of law on this issue because of the “well-established general Texas law rule that an ORRI bears its proportionate share of post[ ]production costs.” Appellees filed a cross-motion for summary judgment contending that they were entitled to judgment as a matter of law on this issue.

After a hearing, the trial court denied both motions for summary judgment on March 8, 2016. All parties then moved for reconsideration of the ruling, and the trial court granted the motion to reconsider on April 20, 2016, rendering an order denying Burlington’s summary judgment motion but granting appellees’ cross-motion. The trial court also granted Burlington permission to appeal the interlocutory ruling, finding that “an immediate appeal from this Order will materially advance the final conclusion of litigation.” See Tex Civ. Prac. & Rem. Code Ann. § 51.014(d) (West, Westlaw through 2015 R.S.) (allowing a trial court to authorize an immediate interlocutory appeal “if (1) the order to be appealed involves a controlling question of law as to which there is a substantial ground for difference of opinion; and (2) an immediate appeal from the order may materially advance the ultimate termination of the litigation”). We granted Burlington’s petition for permissive appeal. See id. § 51.014(f); Tex R. App. P. 28.3.

II. Discussion

Burlington argues on appeal by two issues that the trial court erred by denying its motion for summary judgment and by granting appellees’ motion for summary judgment.

A. Standard of Review

We review summary judgments de novo. Neely v. Wilson, 418 S.W.3d 52, 59 (Tex. 2013). A party moving for traditional summary judgment must show that no genuine issue of material fact exists and that the movant is entitled to judgment as a matter of law. Tex. R. App. P. 166a(c). We view the evidence “in the light most favorable to the party against whom the summary judgment was rendered, crediting evidence favorable to" that party if reasonable jurors could, and disregarding contrary evidence unless reasonable jurors could not.” Mann Frankfort Stein & Lipp Advisors, Inc. v. Fielding, 289 S.W.3d 844, 848 (Tex. 2009) (citing City of Keller v. Wilson, 168 S.W.3d 802, 827 (Tex. 2005)). When both sides move for summary judgment and the trial court grants one motion and denies the other, we review the summary judgment evidence presented by both sides, determine all questions presented, and render the judgment the trial court should have rendered. SeaBright Ins. Co. v. Lopez, 465 S.W.3d 637, 641-42 (Tex. 2015).

As with any other unambiguous contract, we construe a mineral lease as a matter of law, seeking to enforce the intention of the parties as expressed therein. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005). We examine and consider the entire writing in an effort to harmonize and give effect to all its provisions so that none will be rendered meaningless. J.M. Davidson, Inc. v. Webster, 128 S.W.3d 223, 229 (Tex. 2003). No single provision taken alone will be given controlling effect; rather, all the provisions must be considered with reference to the whole instrument. Id.

B. Applicable Law

An ORRI, like any royalty, is generally free from production costs such as expenses for exploration, drilling, and development. See Chesapeake Exploration, LLC v. Hyder, 483 S.W.3d 870, 872-73 (Tex. 2016) (defining an ORRI as a “given percentage of the gross production carved from the working interest but, by agreement, not chargeable with any of the expenses of operation”) (quoting MacDonald v. Follett, 142 Tex. 616, 180 S.W.2d 334, 336 (Tex. 1944)); H.G. Sledge, Inc. v. Prospective Inv. & Trading Co., 36 S.W.3d 597, 599 n.2 (Tex. App.—Austin 2000, pet. denied). However, an ORRI usually bears post-production costs such as taxes, transportation, and processing, unless the parties “modify this general rule by agreement.” Id. at 872-73 (citing Paradigm Oil, Inc. v. Retamco Operating, Inc., 372 S.W.3d 177, 180 n.1 (Tex. 2012); Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 122 (Tex. 1996); Alamo Nat’l Bank v. Hurd, 485 S.W.2d 335, 339 (Tex. Civ. App.—San Antonio 1972, writ ref d n.r.e.)); see Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 445 (Tex. App.—Corpus Christi 2006, pet. denied).

The question here is whether the assignments at issue effectively modify the general rule so as to preclude Burlington from deducting post-production expenses from ORRI payments made pursuant to those assignments.

C. Chesapeake Exploration v. Hyder

The same question was posed, to the Texas Supreme Court last year in Hyder, which both sides cite as support for their respective positions. See 483 S.W.3d at 871-76. The lease at issue there contained three royalty provisions. The first entitled the plaintiffs, the Hyders, to 25% of “the market value at the well of all oil and other liquid hydrocarbons” produced from the leases. Id. at 871. The second entitled the Hyders to 25% of “the price actually received by [Chesapeake]” for all gas produced from the leases, expressly “free and clear of all production and post-production costs and expenses.” Id. The third royalty provision—the one in dispute—entitled the Hyders to “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production obtained” from directional wells drilled on the lease but bottomed on nearby land. Id. at 871-72.

In that case, Chesapeake sold all of the gas produced from the lease at issue to its marketing affiliate, which in turn sold the gas to third-party purchasers in distant markets. Id. at 872. The marketing affiliate paid Chesapeake a “gas purchase price” which was calculated based on a weighted average of the third-party sales prices received by the marketing affiliate (the “gas sales price”) minus post-production costs. Id. For the Hyders’ ORRI in the gas produced from seven directional wells bottomed on adjacent land, Chesapeake paid 5% of the “gas purchase price,” but the Hyders sued, claiming that they were instead entitled to 5% of the “gas sales price.” Id.

The trial court, the court of appeals, and a 5-4 majority of the Texas Supreme Court agreed with the Hyders. The Court’s majority noted that the first two royalty provisions in the lease were clear as to post-production costs. Id. at 873. First, the 25% oil royalty bears post-production costs because it is paid on the “market value of the oil at the well,” which “should equal the commercial market value less the processing and transporting expenses that must be paid before the gas reaches the commercial market.” Id. (citing Heritage Res., 939 S.W.2d at 122). Second, the 25% gas royalty does not bear post-production costs because it is “based on the price Chesapeake actually received from its, marketing affiliate,” after post-production costs have been paid. Id.

The ORRI provision, on the other hand, was not as clear. Id. The Hyders argued that “cost-free” must refer to post-production costs, since a royalty by its nature is already free of production costs; but Chesapeake argued that “cost-free” is “merely a synonym for overriding royalty” and may simply emphasize that the ORRI is free of production costs. Id. at 873-74. Chesapeake further contended that the term “gross production” refers to “production at the wellhead,” meaning the royalty at issue would be equivalent to one based on the “market value of production at the wellhead,” which bears post-production costs. Id. at 874.

The Hyder majority noted that the ORRI’s exception for production taxes, which are generally considered post-production costs, cuts against Chesapeake’s argument because “[i]t would make no sense to state that the royalty is free of production costs, except for post[-]production taxes (no dogs allowed, except for cats).” Id. (citing Heritage Res., 939 S.W.2d at 122 (characterizing taxes as post-production costs)); but see id. at 878 (Brown, J., dissenting) (noting that the parties referred specifically to production taxes and opining that the parties intended “production taxes” to be a production cost). Nevertheless, the Texas Supreme Court observed that “drafters frequently specify that an overriding royalty does not bear production costs even though an overriding royalty is already free of production costs simply because it is a royalty interest.” Id. at 874 (noting that this suggests that “lease drafters are not always driven by logic”),

As to the “gross production” language, the Court noted that the other two royalties mentioned in the lease are also based on “full production” at the wellhead, and yet one bears post-production costs and one does not. Id. at 874-75. It held that “[sjpecifying that the volume on which a royalty is due must be determined at the wellhead says nothing about whether the overriding royalty must bear post[-]production costs.” Id. at 874.

The Hyder majority concluded:

Chesapeake argues that the [25%] gas royalty provision shows that when the parties wanted a post[-]production-cost-free royalty, they were much more specific. But as we have already said, the additional detail in the gas royalty provision serves only, if anything, to emphasize its cost-free nature. The simple “cost-free” requirement of the overriding royalty achieves the same end.
The overriding royalty provision reads as though the royalty is in kind, but Chesapeake does not argue that it must be, and in fact the royalty has always been paid in cash. Were the Hyders to take their overriding royalty in kind, as they are entitled to do, they might use the gas on the property, transport it themselves to a buyer, or pay a third party to transport the gas to market as they might negotiate. In any event, the Hyders might or might not incur post[-]production costs equal to those charged by Marketing. The lease gives them- that choice. The same would be true of the gas royalty, which is to be paid in cash but can be taken in kind. The fact that the Hyders might or might not be subject to post[-]production costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash. The choice of how to take their royalty, and the consequences, are left to the Hyders. Accordingly, we conclude that “cost-free” in the overriding royalty provision includes post[-]production costs.

Id. at 875.

D. Analysis

Burlington first argues that the assignments must be read in conjunction with the PDA and JOA, and that the PDA and JOA do not authorize Amber to retain or receive “anything other than the typical ORRI,” which would bear post-production costs. See J.M. Davidson, Inc., 128 S.W.3d at 229, EOG Res., Inc. v. Hanson Prod. Co., 94 S.W.3d 697, 701 (Tex. App.—San Antonio 2002, no pet.) (noting that “when two or more instruments make up a single transaction, all of them must be construed together as one contract”). In response, appellees contend that, under the merger doctrine, the language of the ORRI assignments themselves is controlling, notwithstanding what may have been contemplated in the contracts that authorized those assignments.

We agree with appellees that the specific ORRI language supersedes the PDA and JOA. The merger doctrine provides that, when the terms of an instrument vary from those contained in the contract for that instrument, the instrument “must be looked to alone to determine the rights of the parties.” Alvarado v. Bolton, 749 S.W.2d 47, 48 (Tex. 1988) (“When a deed is delivered and accepted as performance of a contract to convey, the contract is merged in the deed. Though the terms of the deed may vary from those contained in the contract, still the deed must be looked to alone to determine the rights of the parties.”); see Devon Energy Prod. Co. v. KCS Res., LLC, 450 S.W.3d 203, 211 (Tex. App.—Houston [14th Dist.] 2014, pet. denied); GXG, Inc. v. Texacal Oil & Gas, 977 S.W.2d 403, 415 (Tex. App.—Corpus Christi 1998, pet. denied) (“The doctrine of merger by deed operates to merge all prior transactions between the parties into the deed.”); see also Tex. Indep. Exploration, Ltd. v. Peoples Energy Prod.-Tex. LP, No. 04-07-00778-CV, 2009 WL 2767037, at *9 (Tex. App.—San Antonio Aug. 31, 2009, no pet.) (mem. op.) (applying merger doctrine to conveyance of ORRI). “The merger doctrine is an analogue of the parol evidence rule and functions to prevent enforcement of prior or contemporaneous transactions on the assumption that all agreements merged into the final executed contract.” Devon Energy, 450 S.W.3d at 211; see GXG, Inc., 977 S.W.2d at 415. Accordingly, even assuming that the PDA and JOA contemplated only the reservation of “typical” ORRIs, which would bear post-production costs, the assignments themselves are the only instruments we must look to in determining whether such “typical” ORRIs were, in fact, conveyed.

We conclude that they were not. Instead, we find that, as in Hyder, the assignments at issue specifically provide for the allocation of post-production costs based on the manner in which the royalty is taken—in-kind or in cash. In particular, the plain language of the assignments unambiguously provides that, when the royalty is taken in cash and the minerals are sold at an arm’s-length sale, as here, the royalty is based on the “amount realized” by Burlington from the sale, and is therefore free of post-production costs. See Hyder, 483 S.W.3d at 873 (noting, with respect to the 25% gas royalty owed to the Hyders, that “the price-received basis for payment in the lease is sufficient in itself to excuse the lessors from bearing post[-]production costs,” and that such a clause is often referred to as a “proceeds lease”); see also 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.”); Occidental Permian Ltd. v. Helen Jones Found., 333 S.W.3d 392, 399 (Tex. App.—Amarillo 2011, pet. denied) (“ ‘Amount realized’ means the proceeds received from the sale of gas or oil.”).

Burlington argues that this plain language ought to be disregarded because of the specific language used in the granting clause of the assignments. Specifically, it contends that the provision that the ORRI “shall be delivered ... into the pipelines, tanks or other receptacles with which the wells may be connected” necessarily means that the ORRI “bears its share of post-production costs incurred after that point.” It cites numerous scholarly works establishing that a provision for delivery of a royalty interest “in the pipeline” or “at the well” means that the royalty owner is responsible for any costs incurred after such delivery. See 3 Howard R. Williams & Charles J. Meyers, Oil <& Gas Law § 645 at 598 (Patrick H. Martin & Bruce M. Kramer, eds., 2015) (noting that a provision for delivery “free of cost in the pipe line to which Operator may connect his wells” means that post-production costs “must be shared by the owner of the non-operating interest”); Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically? (Part II), 37 Nat, Resources J. 611, 650 (1997) (noting that a “free of cost, in the pipeline” royalty clause “contemplates that the lessee must absorb all costs of delivering oil or gas into a pipeline near a well, but is not obligated to deliver oil or gas to some distant pipeline or market”); 3 Eugene O. Kuntz, Treatise on the Law of Oil & Gas § 40.5(a) (1989) (“If the royalty clause provides for delivery of royalty gas to the lessor’s credit free of cost in the pipeline to which the well is connected, the parties contemplate a delivery of royalty gas at the well.... ”); A. W. Walker Jr., The Nature of the Property Interests Created by an Oil and Gas Lease in Texas, 10 Tex. L. Rev. 291, 313 (1932) (noting that a provision for delivery “in the pipe line to which the wells” may be connected or “at the wells” or “into storage tanks” means that post-production costs must be borne by the royalty owner); see also Heritage Res., 939 S.W.2d at 130 (concluding that post-production costs “are to be shared by the royalty interest owners under a ‘market value at the well’ clause, absent language to the contrary”).

Even assuming that, under the granting clause, the ORRI is generally to be delivered “at the well,” the parties are still free to allocate post-production costs as they see fit. As the Hyder majority stated, “[specifying that the volume on which a royalty is due must be determined at the wellhead says nothing about whether the overriding royalty must bear post[-]production costs.” Hyder, 483 S.W.3d at 874. And as set forth above, according to the plain language of the assignments, because the royalties were taken in cash and the minerals were sold at arm’s length, the royalties are based on the “amount realized” by Burlington from those sales and are therefore free of post-production costs. See id. at 873; Bowden, 247 S.W.3d at 699; Occidental Permian, 333 S.W.3d at 399.

Burlington claims Hyder is distinguishable because the lease in that case provided for an unmodified “cost-free” royalty, whereas the assignments at issue here specify that the ORRI is “free and clear of all development, operating, production and other costs.” It contends that, under the doctrine of ejusdem generis, the phrase “and other costs” in the assignments’ granting clause must include only costs “in the category framed by the previous specific words”—i.e, not post-production costs. The doctrine of ejusdem generis, applicable to contract construction, provides that “general terms and phrases should be limited to matters similar in type to those specifically enumerated.” Univ. of Tex. at Arlington v. Williams, 459 S.W.3d 48, 52 (Tex. 2015); see Boss v. St. Luke’s Episcopal Hosp., 462 S.W.3d 496, 504 (Tex. 2015) (“Where the more specific items, [a] and [b], are followed by a catchall ‘other,’ [c], the doctrine of ejusdem generis teaches that the latter must be limited to things like the former.”); Hilco Elec. Co-op. v. Midlothian Butane Gas Co., 111 S.W.3d 75, 81 (Tex. 2003) (noting that “when words of a general nature are used in connection with the designation of particular objects or classes of persons or things, the meaning of the general words will be restricted to the particular designation”). Even assuming that this doctrine applies here and thereby limits the “free and clear” clause to production costs only, that does not mean that the assignments may not provide elsewhere for the allocation of post-production costs.

Burlington also asserts that Hyder is distinguishable because the lease considered in that case did not specify a royalty valuation point. However, the Hyder lease conveyed an ORRI of five percent “of gross production,” and the Texas Supreme Court majority interpreted “gross production” as “the entire amount of gas produced, including gas used by Chesapeake or lost in post[-]production operations.” 483 S.W.3d at 874. That is, the Court construed the lease as providing that the valuation point of the royalty, at least in cases where the royalty was taken in-kind, would be at the well, before post-production costs are incurred. See id. Even so, the Court found that the parties validly contracted for the Hyders to have the choice of whether to accept the royalty in-kind at the well—and thus to be responsible for any post-production costs they may incur after that point—or to accept the royalty in cash. See id. at 875. And, crucially, “[t]he fact that the Hyders might or might not be subject to post[-]production costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash.” Id. The same rationale applies here. Even if the granting clause generally provided that the royalty valuation point would be at the well, the assignments gave the as-signee the option to take its interest in cash, in which case the royalty must be based on the “amount realized,” and would therefore not be subject to deductions for post-production costs. See id. at 873; Bowden, 247 S.W.3d at 699; Occidental Permian, 333 S.W.3d at 399.

Finally, Burlington argues that the reference to “amount realized” in the assignments does not necessarily mean that the payment is free of post-production costs, citing Warren v. Chesapeake Exploration, LLC, 759 F.3d 413 (5th Cir. 2014). We disagree because Warren is distinguishable. The lease at issue there stated that the lessor was entitled to a royalty payment of “[22.5%] of the amount realized by Lessee, computed at the mouth of the ivell .... Id. at 416 (emphasis added). The Fifth Circuit' held that the term “amount realized .'.. computed at the mouth of the well” means “proceeds net of reasonable post-production costs incurred beyond the mouth of the well,” and so the deduction of post-production costs was proper. Id. at 419. There is no similar language attached to the term “amount realized” in the assignments here. Accordingly, the assignments require cash payments without deduction of post-production costs. See Hyder, 483 S.W.3d at 873; Bowden, 247 S.W.3d at 699; Occidental Permian, 333 S.W.3d at 399.

In light of the foregoing, we conclude that the trial court did not err in rendering summary judgment in favor of appellees on the issue of post-production costs, and we overrule Burlington’s issues on appeal.

III. Conclusion

The trial court’s judgment is affirmed. 
      
      . A "working interest” is an operating interest under an oil and gas lease that bears all the costs of production and is held subject to the payment of royalties. Sw. Energy Prod. Co. 
        v. Berry-Helfand, 491 S.W.3d 699, 728 n.9 (Tex. 2016).
     
      
      . The amount of the ORRI to which Texas Crude was entitled varied from zero to 6.25% depending on what percentage of the lease in question was burdened by royalties owed to the landowner and other third parties, according to a table set forth in the PDA.
     
      
      . The petition stated: "Plaintiffs seek damages from Burlington in an amount equal to 87,5% of these underpaid royalties, which is the benefit that Burlington, as an owner of 87.5% of the working interest, has retained from its underpayment of the overriding royalties to Plaintiffs.”
     
      
      . The trial court noted as follows in the April 20, 2016 order:
      The Court and parties anticipate that a trial would be necessary to determine the propriety and amounts of deductions taken by Burlington as to Burlington’s 87.5 percent working interest. [Amber] makes no claim for recovery of such deductions taken from Texas Crude's and Texas Crude’s assignees’ interests in the remaining 12.5 percent of the working interest. Defendant Burlington has also asserted a claim for indemnity against Texas Crude based on those parties’ [JOA] that may or may not become ripe, depending on final resolution of the question of law decided by this Order.
     
      
      . The parties agree that the assignments at issue are unambiguous; they just disagree about what the assignments unambiguously mean.
     
      
      . The 25% gas royalty provision also stated that it is "free and clear of all production and post-production costs and expenses.” Chesapeake Exploration, LLC v. Hyder, 483 S.W.3d 870, 873 (Tex. 2016). But the majority in Hyder noted that "[tjhis addition has no effect on the meaning of the provision” and may be regarded as surplusage. Id. (holding that "the price-received basis for payment in the lease is sufficient in itself to excuse the [Hyders] from bearing post[-]production costs”).
     
      
      . Burlington suggested at oral argument that the ORRI assignments stated that the terms of the JOA and PDA control in the event of conflict with the assignments. The instruments from Texas Crude conveying 87.5% working interests to Burlington did contain such a clause, but the ORRI assignments, which are the only conveyances at issue in this appeal, did not. In fact, though the ORRI assignments stated that the ORRIs are "[s]ub-ject to all burdens of record” and "pursuant to the terms and conditions” of the underlying leases, they did not explicitly refer to the PDA or JOA.
     