From the 17th Judicial District Court, Tarrant County, Texas Trial Court No. 17-244547-10 Honorable Melody M. Wilkinson, Judge Presiding
Sitting: Sandee Bryan Marion, Justice Rebeca C. Martinez, Justice Luz Elena D. Chapa, Justice
OPINION
Sandee Bryan Marion, Justice
This appeal arises out of a dispute involving the construction of the royalty and overriding royalty clauses in an oil and gas lease (“the Hyder lease”) between Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc. (collectively “appellants”) and the appellees, who are royalty interest holders.
Appellees filed suit against appellants alleging a breach of the lease. Appellants counterclaimed to recover overpaid royalties. After a bench trial, the trial court entered a final judgment in favor of appellees, awarding appellees damages for breach of the royalty and overriding royalty clauses, attorney’s fees, and pre-judgment and post-judgment interest. We affirm.
BACKGROUND
The Hyder lease was originally entered into on September 1, 2004, between appellees and Four Sevens Oil Co., Ltd. Four Sevens assigned the lease to appellants. The lease covers approximately 1, 037 surface acres and approximately 948 mineral acres of land located in Johnson County and Tarrant County, Texas. In addition to the leased premises, the lease also allows appellants to drill from existing well sites that lie adjacent to or near the leased premises (“off-lease wells”). As of December 1, 2011, appellants have drilled and completed twenty-two wells on the leased premises and seven off-lease wells.
The dispute between the parties arose from each party’s interpretation of the royalty and overriding royalty clauses. Appellants contend the royalty clause applicable to the wells on the leased premises allows them to deduct appellees’ share of post-production costs and expenses incurred between the “point of delivery” and the “point of sale” from appellees’ royalty payment. Appellees counter that their royalty interest is not subject to any post-production costs and expenses, regardless of where such costs and expenses are incurred. Appellants further contend the overriding royalty clause applicable to the off-lease wells allows them to deduct appellees’ share of post-production costs and expenses from appellees’ overriding royalty. Appellees counter that their overriding royalty interest is not subject to any post-production costs or expenses.
STANDARD OF REVIEW
An oil and gas lease is a contract and must be interpreted as a contract. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005); Hitzelberger v. Samedan Oil Corp., 948 S.W.2d 497, 503 (Tex. App.-Waco 1997, pet. denied). Contract language that can be given a certain or definite meaning is not ambiguous and is construed as a matter of law. Chrysler Ins. Co. v. Greenspoint Dodge of Hous., Inc., 297 S.W.3d 248, 252 (Tex. 2009). Interpretation of an unambiguous contract is a question of law and we review the trial court’s interpretation of an unambiguous contract under a de novo standard. EOG Res., Inc. v. Hanson Prod. Co., 94 S.W.3d 697, 701 (Tex. App.-San Antonio 2002, no pet.). In construing an unambiguous lease, our primary duty is to ascertain the parties’ intent as expressed by the words of their agreement. Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002). In doing so, we consider the wording of the lease in light of the circumstances surrounding its adoption and apply the rules of construction to determine its meaning. Sun Oil Co. v. Madeley, 626 S.W.2d 726, 761 (Tex. 1981). We must give contractual terms their plain and ordinary meaning unless the instrument shows the parties’ intent to use the terms in a different sense. Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex. 1996). 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.” Coker v. Coker, 650 S.W.2d 391, 393 (Tex. 1983).
ROYALTY FOR WELLS ON LEASED PREMISES
A. Background
Because of its relevance to our determination, a brief summary of appellants’ organizational and operational structure is warranted. Chesapeake Exploration, L.L.C., Chesapeake Operating, Inc. (“COI”), Chesapeake Energy Manufacturing, Inc. (“CEMI”), and Chesapeake Midstream Partners, L.P. (“CMP”) are affiliated companies. COI is responsible for the production of gas from the Hyder lease. After gas is produced, COI sells the gas to CEMI. At that point, CEMI takes title to the gas. CMP gathers the gas and transports it to a central point. CEMI then delivers the gas to one of several “points of delivery, ” which are physical locations where CMP’s system connects to larger interstate pipelines owned and operated by unaffiliated third party interstate pipeline companies. The gas is then transported downstream from these points of delivery to various “ points of sale.” At these points of sale, title to the gas passes from CEMI to the third party purchaser. Appellants made royalty payments to appellees based on a weighted average sales price calculated on these sales to various third party purchasers.
B. The Royalty Clause
The royalty clause in the Hyder lease applies to the wells located on the leased premises. In their first issue, appellants contend this clause entitles them to deduct certain post-production costs and expenses. The relevant portion of the royalty clause sets forth appellants’ royalty obligation as follows:
[Appellants] covenant[] and agree[] to pay [appellees] the following royalty: (a) twenty-five percent (25%) of the market value at the well of all oil and other liquid hydrocarbons produced and saved from the Leased Premises as of the day it is produced and stored; and (b) for natural gas, including casinghead gas and other gaseous substances produced from the Leased Premises and sold or used on or off the Leased Premises, twenty-five percent (25%) of the price actually received by [appellants] for such gas . . . . The royalty reserved herein by [appellees] shall be free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and [appellant's] point of delivery or sale of such share to a third party. [emphasis added]
Appellants acknowledge production costs and expenses incurred before the gas is extracted are excluded from appellees’ royalty interest. However, they argue the royalty clause is constructed in a manner that permits deduction of post-production costs and expenses, such as third party transportation costs incurred between the point of delivery and the point of sale. At trial, the parties stipulated that appellants incurred unaffiliated third party transportation costs of $1, 750, 000 allocable between the point of delivery and the point of sale. Because appellants had not deducted this amount from payments to appellees, appellants asserted a counterclaim for money had and received based on alleged mistaken overpayments of this royalty.
Appellees argue the royalty clause prohibits deduction of all post-production costs and expenses, regardless of whether they are incurred between the point of delivery and the point of sale. Appellees emphasize the “free and clear” provision of the royalty clause and assert that the list of excluded post-production costs and expenses is demonstrative of the broad nature of this clause. Conversely, appellants’ interpretation of the royalty clause focuses on the language “incurred between the wellhead and [appellants'] point of delivery or sale of such share to a third party.” Appellants emphasize the word “or” between “delivery” and “sale, ” arguing its use is disjunctive. Because of this disjunctive nature, appellants assert the royalty clause allows them to choose either the point of delivery, or the point of sale to determine whether the royalty clause permits deduction of post-production costs and expenses incurred after the point of delivery but before the point of sale.
Royalty is defined as the landowner’s share of production, free of the expenses of production. Heritage, 939 S.W.2d at 121–22; see Alamo Nat’l Bank of San Antonio v. Hurd, 485 S.W.2d 335, 338 (Tex. App.-San Antonio 1972, writ ref’d n.r.e.). “Although not subject to the costs of production, royalty is normally subject to post-production costs, including taxes, treatment costs to render it marketable, and transportation costs. However, the parties may modify this general rule by agreement.” Heritage, 939 S.W.2d at 122 (internal citations omitted).
We note that the royalty clause here expressly states: “[Appellees] and [appellants] agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 188 (Tex. 1996) shall have no application to the terms and provisions of this Lease.” Heritage involved the question of how to properly calculate the royalties owed a group of lessors under oil and gas leases. Id. at 121. The relevant royalty provisions required the lessee to pay the lessors a certain percentage of the “market value at the well for all gas . . . produced from the leased premises.” Id. at 120–21. The leases also contained a “no deduct” provision, which provided that “there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.” Id.
The lessee in Heritage deducted the post-production cost to transport gas from the wellhead to the point of sale from the sales price before calculating the lessors’ royalties. Id. at 120. The lessors sued for breach of contract, arguing that the deductions violated the leases’ “no deduct” provision. In assessing this claim, the Texas Supreme Court did not directly address the apparent conflict between the definition of “market value at the well” (which required that post-production costs be deducted from lessors’ royalty) and the “no deduct” provision (which appeared to prohibit deducting such costs). Rather, the Court looked first to the applicability of the “no deduct” provision, which prevented deductions only from the “value of the Lessor’s royalty.” Id. at 122. According to the Court, the “value of the Lessor’s royalty” was the market value of the gas at the well-a measure that required a deduction for post-production costs. Id. The Court thus concluded that the leases’ “no deduct” provision was “surplusage as a matter of law.” Id. at 123.
Here, we disagree with appellants’ interpretation because it ignores the “free and clear” provision of the royalty clause when we are required to consider the entire writing so that no provision will be rendered meaningless. An interpretation of the Hyder lease that excludes post-production costs and expenses from the wellhead to the point of delivery, but includes post-production costs and expenses from the point of delivery to the point of sale, is contrary to the plain reading of the royalty clause. The parties modified the general rule by agreement, and we interpret the parties’ agreement as the royalty clause excluding all costs and expenses of production and post-production, including post-production costs and expenses incurred between the point of delivery and the point of sale.[1] Our conclusion is reinforced by the parties’ agreement that the holding in Heritage-that the measure of the “value of the Lessor’s royalty” required a deduction for post-production costs, and therefore, the leases’ “no deduct” provision was “surplusage as a matter of law”-did not apply to the terms and provisions of the Hyder lease.
OVERRIDING ROYALTY FOR OFF-LEASE WELLS
The overriding royalty clause in the Hyder lease applies to the off-lease wells. In their second issue, appellants assert they did not breach the overriding royalty clause because it allows for deduction of post-production costs and expenses. Appellees counter that appellants breached the overriding royalty clause because appellees’ “cost-free overriding royalty” entitled them to an overriding royalty free of production costs and post-production costs. The relevant portion of the overriding royalty clause provides:
[Appellants] shall, within sixty (60) days from the date of the first production from each off-lease well, convey to [appellees] a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5%) of gross production obtained from each such well payable to [appellees] (which overriding royalty shall be carved out of the leasehold estate by virtue of which such production is obtained), same to be effective from first production from the well to which such overriding royalty pertains. [emphasis added]
The parties’ disagreement centers on the term “cost free.” Appellants’ contention is that “cost free” merely reinforces current Texas law that an overriding royalty is free of production costs, but subject to its proportionate share of post-production costs. Appellees assert “cost free” refers to all costs (except appellees’ portion of production taxes), including post-production costs.
A. Analysis
“An overriding royalty is an interest in the oil and gas produced at the surface, free of the expense of production.” Paradigm Oil, Inc. v. Retamco Operating, Inc., 372 S.W.3d 177, 180 n.1 (Tex. 2012); see also Hurd, 485 S.W.2d at 339 (“The term ‘overriding royalty’ as used in an oil and gas lease means a given percentage of the production carved from the working interest, but by agreement, not chargeable with any of the expenses of operation.”). “Production costs are the expenses incurred in exploring for mineral substances and in bringing them to the surface.” Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 444–45 (Tex. App.-Corpus Christi 2006, pet. denied). Absent an express term to the contrary, production costs are not chargeable to the non-operating royalty interest. Id. “[G]as is ‘produced’ when it is severed from the land at the wellhead.” Martin v. Glass, 571 F.Supp. 1406, 1415 (N.D. Tex. 1983), aff’d, 736 F.2d 1524 (5th Cir. 1984). Whatever costs are incurred after production of the gas or mineral are normally proportionately borne by both the operator and the royalty interest owners. Id. “These post-production costs include taxes, treatment costs to render the gas marketable, compression costs to make it deliverable into a purchaser’s pipeline, and transportation costs.” Id. Under Texas law, it is clear that an overriding royalty is normally free of production costs, but subject to post-production costs. See Martin, 571 F.Supp. at 1410; Heritage, 939 S.W.2d at 122; Retamco, 372 S.W.3d at 180 n.1. However, the parties may modify this default rule by agreement. Heritage, 939 S.W.2d at 122.
The trial court ruled appellants breached the lease’s overriding royalty clause by deducting post-production costs and expenses from appellees’ overriding royalty payment. Appellants argue the trial court erred in construing the overriding royalty clause because the trial court failed to recognize the nature of an overriding royalty-namely, that an overriding royalty is subject to post-production costs. Therefore, appellants assert the trial court erroneously construed the parties’ intent when it determined appellees’ overriding royalty was free of both production and post-production costs. Appellants further argue the term “cost free” should not be construed in a vacuum; instead, it should be construed in light of the fact that, by definition, an overriding royalty is free of production costs, but not free of post-production costs.
In support of their position, appellants cite four cases analyzing similar overriding royalty clauses. The first case is a decision from the Supreme Court of Oklahoma. In XAE Corp. v. SMR Prop. Mgmt. Co., overriding royalty interest owners sued to recover post-production costs incurred to convert the gas to a marketable product. XAE Corp. v. SMR Prop. Mgmt. Co., 968 P.2d 1201, 1202 (Okla. 1998). The XAE court determined that the implied covenant of marketability could not be enforced by the overriding royalty interest owner. Id. at 1207. The court also determined the overriding royalty interest was an in-kind interest, which made the point of delivery at the wellhead. Id. Because the lease in question contained no other duty required by the lessee other than to deliver the gas, the court determined the lessee was not responsible for the lessor’s share of post-production costs and expenses. Id. at 1208.
Here, we first note this case does not involve the taking of gas in-kind.[2] However, appellants argue the overriding royalty interest is an in-kind interest, which entitled them to a percentage of production “at the wellhead” rather than a percentage of the proceeds of the sale of such gas. Therefore, appellants conclude because production for an in-kind interest is measured at the wellhead, “[t]he Hyders’ overriding royalty interest certainly cannot impliedly enjoy more dignity than the working interest from which it derived.” We disagree with appellants’ argument because the overriding royalty clause of the Hyder lease contains a provision that expressly provides appellees’ overriding royalty is “cost free.” Consequently, appellants’ reliance on XAE is unpersuasive.
Appellants next cite to Heritage in support of their argument. However, as noted above, the Hyder lease explicitly provides “[appellees] and [appellants] agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank . . . shall have no application to the terms and provisions of [the Hyder lease].” As a result, appellants’ reliance on Heritage is unpersuasive.
Appellants also assert the term “cost free” in the Hyder lease is equivalent to the “free and clear” language found in Martin v. Glass and Dancinger Oil Refineries v. Hamill Drilling Co. In Martin v. Glass, the lease contained two overriding royalty clauses. Martin, 571 F.Supp. at 1410. The first overriding royalty clause provided for an overriding royalty “free and clear of all cost of drilling, exploration or operation . . . .” Id. The second overriding royalty clause provided for an overriding royalty “free and clear of all cost of exploration, development, completion and operation . . . .” Id. In Dancinger Oil & Refineries v. Hamill Drilling Co., the lease provided for an overriding royalty “free and clear of operating expenses.” Dancinger Oil & Refineries v. Hamill Drilling Co., 171 S.W.2d 321, 323 (1943). In each case, the courts held such language properly allowed for deduction of post-production costs from the lessor’s royalty payment.
The overriding royalty clauses in Martin and Dancinger expressly limited the costs that were to be excluded from the overriding royalty to exploration, development, drilling, completion, and operation costs-all of which are production costs, as opposed to post-production costs. The Martin court itself acknowledged these expenses were attributable to production costs. See Martin, 571 F.Supp. at 1416–17 (referencing costs of “drilling, exploration, development, completion and operating expenses” and determining such costs “refer only to costs incident to getting the gas to the surface”). Here, the overriding royalty clause in the Hyder lease can be distinguished because it does not limit the types of costs to be excluded from the overriding royalty to production costs alone. Accordingly, appellant’s reliance on Martin and Dancinger is unpersuasive.
While we acknowledge an overriding royalty is normally subject to post-production costs, we also acknowledge Texas law allows the parties to modify this default rule. Heritage, 939 S.W.2d at 122. We must also “presume that the parties to a contract intend every clause to have some effect.” EOG Res., Inc., 94 S.W.3d at 701. Although the lease recites the parties agreed to a “cost free (except only its portion of production taxes) overriding royalty, ” adopting appellants’ interpretation would render the term “ cost free” meaningless and require us to determine the parties’ true intent was to provide a traditional “overriding royalty, ” or a “ cost free (except only to its portion of production taxes and post-production costs) overriding royalty.” Consequently, adopting such interpretation would require us to rewrite the lease and alter the parties’ contract which we may not do. See Am. Mfrs. Mut. Ins. Co. v. Schaefer, 124 S.W.3d 154, 162 (Tex. 2003); see also Eagle Life Ins. Co. v. G.I.C. Ins. Co., 697 S.W.2d 648, 651 (Tex. App.-San Antonio 1985, writ ref’d n.r.e.) (“Courts are not at liberty to rewrite the contract between the parties without pleading and proof of fraud or mutual mistake.”). Accordingly, we conclude appellees are entitled to an overriding royalty free of all production and post-production costs, subject only to their portion of production taxes.
INTEREST RATE
The trial court awarded appellees pre-judgment and post-judgment interest for damages resulting from appellants’ breach of the royalty clause at a rate of one percent per month pursuant to paragraph five of the lease. With respect to damages arising from appellant’s breach of the overriding royalty clause, the trial court applied an interest rate of five percent per annum pursuant to Texas Finance Code section 304.003.
In their second issue on cross-appeal, appellees argue the trial court incorrectly determined the applicable interest rate on their overriding royalty damages was five percent annually instead of the interest rate of one percent per month for all past due payments as provided in paragraph five of the lease. Appellants counter that the one percent per month interest rate applies only to the royalty clause applicable to the wells located on the leased premises, and does not apply to the overriding royalty clause attributable to the off-lease wells. We agree with appellants.
Paragraph five of the lease contains three subparagraphs. The first subparagraph sets the amount of the royalty attributable to wells on the leased premises, states (as we have held above) that the royalty is free and clear of all costs and expenses of production and post-production, provides the holding in Heritage has no application, allows each appellee the option of taking its royalty share in-kind and separately market its royalty share, and sets forth other agreements specific to the royalty attributable to the wells on the leased premises. The second subparagraph states the terms of the parties’ agreement with regard to commingling of gas produced from the leased premises with gas produced from any other lands. Finally, the third subparagraph states:
Royalty payments shall be secured by a vendor’s lien and superior title to secure payment. The payment shall be paid for gas on or before the last day of the second month succeeding the month of production. [Appellants] shall pay a late fee and interest for all past due payments at the rate of one percent (1%) per month or fractional part.
Paragraph ten, which is a single paragraph, permits the appellants to drill off-lease wells, sets the amount of the overriding royalty attributable to the off-lease wells, and provides that the overriding royalty is “a perpetual, cost-free (except only its portion of production taxes) royalty. The paragraph is silent with respect to any late payment interest rate.
We conclude the three subparagraphs of paragraph five are specific to only the wells on the leased premises. Therefore, we conclude the requirement that appellants “shall pay a late fee and interest for all past due payments at the rate of one percent (1%) per month or fractional part” applies only to royalties attributable to the wells on the leased premises. Because paragraph ten, which applies to off-lease wells, contains no provision for interest on past due payments, we conclude the trial court properly applied the default statutory interest rate allowed by Finance Code section 304.003.
ROYALTY ON GAS LOST AND UNACCOUNTED FOR
In their first issue on cross-appeal, appellees contend the trial court erred in holding appellants do not owe royalty on gas lost and unaccounted for. Appellees argue appellants owe royalty on all gas produced from Hyder acreage. Appellants counter they do not owe royalty on gas lost or unaccounted for because there is no “price actually received” for such gas.
Gas lost and unaccounted for is the gas lost between the wellhead and the point of sale. The relevant portion of the royalty clause required appellants to pay appellees: “for [gas] produced from the Leased Premises and sold or used on or off the Leased Premises, twenty-five percent (25%) of the price actually received by [appellants] for such gas.” Appellees also cite the third paragraph of the royalty clause, which provides:
Except in the case of a well that is pooled with other lands, gas produced from the Leased Premises shall not be commingled with gas produced from any other lands prior to the point where the gas produced from the Leased Premises passes through the meter which will measure the gas for calculating the payment made by the purchaser of gas production. Appellees contend their royalty payment should be calculated based on gas volume measured at the wellhead instead of at the point of sale to a third party. The Hyder lease includes a bifurcated royalty clause, providing that the royalty for oil is twenty-five percent of the “market value at the well (a “market value” royalty), ” while the royalty for gas is twenty-five percent of the “ price actually received (a “proceeds” royalty).” See Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372 (Tex. 2001) (comparing “market value” and “proceeds” royalties). “Proceeds” royalties base the royalty payment on the “price actually received” for the gas. Union Pac. Res. Grp., Inc. v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003); Yzaguirre, 53 S.W.3d at 372. For “proceeds” royalties, the proper payment-measuring point is the amount of gas sold, not the amount delivered at the wellhead. Dynergy Midstream Svcs., Ltd. P’ship v. Apache Corp., 294 S.W.3d 164, 174 (Tex. App. 2009) (“[A] ‘percentage of proceeds’ contract measures payment solely as a percentage of proceeds from actual sales.”). Here, appellees concede they were fully paid on all gas actually sold, but contend they are owed for gas lost.
Appellees also argue the sale at the wellhead between the affiliated companies, COI and CEMI, is the point where appellants obtain the “price actually received” for such gas. Although the parties stipulated that a sale between COI and CEMI takes place at the wellhead, the parties also stipulated COI and CEMI are affiliated companies. In addition to the language cited by appellees, the lease also defines appellees’ royalty interest as free of all costs and expenses prior to a sale of such gas “to a third party.” As such, we conclude that even if production is measured at the wellhead, such sale between COI and CEMI does not constitute a sale to a “third party.”
Finally, appellees contend the fact that appellants do not actually receive payment for such gas is irrelevant because they are compensated in other situations where appellants do not actually receive payment, such as when gas is used for fuel or other operations. The royalty clause provides that royalty is owed on gas produced and “sold” or “used.” Adopting appellees’ construction would render the words “sold” and “used” meaningless, effectively requiring us to rewrite the lease so that appellees are owed royalty solely on the basis that gas was “produced” from the leased premises, regardless of whether it is subsequently “sold” or “used.” Gas is “used” when it is delivered or consumed. Exxon Corp. v. Middleton, 613 S.W.2d 240, 244 (Tex. 1980). “The time gas is ‘sold’ is the same time gas is ‘used’ when it is delivered.” Id. at 245. Thus, before appellants’ royalty obligation is triggered, gas must first be produced, then must either be sold or used. Appellees’ assertion that they should receive royalty payments based on amounts of gas not actually sold because they are compensated for such gas in other circumstances is misguided. When appellants use gas for fuel or other operations, royalty is owed on such volumes not solely because the gas was produced from the leased premises, but because appellants also used or consumed such gas. Gas lost or unaccounted for is neither sold nor used. Consequently, we conclude the trial court correctly determined appellees are not entitled to recover on their counterclaim for lost and unaccounted for gas.
ATTORNEY’S FEES
A person may recover reasonable attorney’s fees in addition to the amount of a valid claim and costs if the claim is for an oral or written contract. Tex. Civ. Prac. & Rem. Code § 38.001(8) (West 2008). An award of reasonable attorney’s fees to a plaintiff recovering on a valid claim founded on a written or oral contract is mandatory under Texas law. In re Smith, 966 F.2d 973, 978 (5th Cir. 1992); AMX Enters., L.L.P. v. Master Realty Corp., 283 S.W.3d 506, 516 (Tex. App.-Fort Worth 2009, no pet.).
Appellants argue that if we find appellants did not breach the lease, appellees are not entitled to attorney’s fees.[3] Because we have already concluded appellants breached the lease, we affirm the trial court’s award of attorney’s fees.
CONCLUSION
For the reasons stated above, we overrule appellants’ issues and appellees’ cross-issues on appeal, and we affirm the trial court’s judgment.
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Notes:
[1] Appellants also argue their interpretation is consistent with “industry customs” and “traditional notions” that a royalty interest is subject to its share of third party post-production costs. However, these industry customs and traditional notions may be modified by the parties. See Heritage, 939 S.W.2d at 122. Although royalty is normally subject to its share of post-production costs, the parties here agreed to modify the industry norm. As a result, these “industry customs” and “traditional notions” are not applicable to the Hyder lease. Because we have concluded the royalty clause excludes all production and post-production costs, we need not address appellees’ third issue on cross-appeal pertaining to waiver or estoppel of appellants’ interpretation of the royalty clause. See Tex. R. App. P. 47.1.
[2] Although the lease agreement here does not involve the taking of gas in-kind, the Hyder lease includes an option for appellees to take their royalty share in-kind, and to separately market their royalty share. However, the evidence shows this option was never exercised.
[3] Appellants do not argue the amount of attorney’s fees awarded was unreasonable.
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