concurring.
I concur in the judgment of the Court. The meaning of “market value at the well,” upon which the resolution of this case ultimately turns, is not as clear-cut as the Court’s opinion indicates when determining whether post-production costs are to be shared by a royalty owner. I write separately to consider the meaning of “market value at the well” more fully and to recognize that the construction we are compelled to give to the leases at issue may not comport with the subjective intent of at least some of the parties to those agreements.
I
NationsBank, as trustee, is an owner of royalty interests under six leases that are the subject of this suit. Heritage is a working interest owner under each of the leases and is the operator of the wells located on those leases. The specific lease provisions that have given rise to this dispute are set forth in the Court’s opinion.
The royalty clauses in contention specifically address marketing costs that may be incurred after the gas leaves the wellhead, including processing, dehydration, compression, and transportation costs. These are sometimes called post-production costs. The only costs at issue in this suit, however, are transportation charges. Simply put, the issue is how the cost of transporting the gas to market is to be allocated under the terms of these leases. This is a question of law. There are no factual disputes. NationsBank has conceded that the transportation charges were reasonable and in line with market rates. Heritage and NationsBank agree that the prices at which the gas was sold reflected its market value at the point of sale. It is undisputed that the sales of gas at issue have taken place off of the leased premises. The trial court, the court of appeals, and this Court correctly concluded that none of the leases are ambiguous.
II
At the outset, it is important to note that we are construing specific language in specific oil and gas leases. Parties to a lease may allocate costs, including post-production or marketing costs, as they choose. See generally 3 Williams, Oil & Gas Law § 645 (1990). Our task is to determine how those costs were allocated under these particular leases.
Each of the royalty provisions begins with the statement that royalties are to be paid on gas sold off the lease based on the market value of the gas at the well. The proviso that follows, prohibiting the deduction of marketing costs from the value of the royalty, is virtually identical in all of the leases. Accordingly, any differences among the leases are immaterial for purposes of determining the royalty obligation.1
The starting point in construing the leases is the language chosen by the parties. We first must ascertain the meaning of “market value at the well,” which the agreements set *125out as the initial benchmark for valuing the royalty. “Market value at the well” tells us how and where the value of the royalty is measured, subject to any other provisions that bear on valuation.
A number of courts in producing states across the country have considered the meaning of various royalty clauses, including “market value at the well” clauses, in deciding which marketing costs, if any, are to be borne by the royalty owner. The decisions, including those under Texas law, are not uniform. There are two diverse viewpoints, with some decisions picking and choosing between the two, depending on the specific marketing cost under consideration.2 At one end of the spectrum is the view that because the operator has an implied duty or an implied covenant to market the gas, all costs of marketing must be borne by the operator. Generally speaking, this is the minority view. On the other end of the spectrum, many decisions recognize that while there is an implied duty or covenant to market the gas, this duty does not extend to expenses incurred in sales off the lease; marketing costs are to be shared proportionately by the working interest and royalty owners. '
In examining decisions in this area, it must be borne in mind that not all royalty clauses were created equal. Some are based on “proceeds,” some on “amount realized,” while others are based on “market value.” Some specify the point at which the value of the royalty is determined, such as “at the well.” Some do not. Some leases have more than one method for valuing royalty depending on whether the gas is sold or used off the leased premises or is sold at the well. Different courts have accorded differing meanings to the same language.
With these distinctions in mind, I consider Texas decisions first.
A
The concept of “market value” is well-established in our jurisprudence. It is what a willing buyer under no compulsion to buy will pay to a willing seller under no compulsion to sell. See, e.g., Exxon Corp. v. Middleton, 613 S.W.2d 240, 246 (Tex.1981). This would seem to be a straight-forward measure, but how market value is determined in the context of an oil and gas lease is a question that has been before this Court on more than one occasion. We held in Texas Oil & Gas Corp. v. Vela that the price paid under a gas purchase contract between the lessee and the purchaser is not necessarily the market price within the meaning of the lease. 429 S.W.2d 866, 871 (Tex.1968). The parties in that case agreed that the market price of gas is to be determined by sales comparable in time, quality, and availability of marketing outlets. Id. at 872. See also First Nat’l Bank in Weatherford, Texas v. Exxon Corp., 622 S.W.2d 80, 82 (Tex.1981) (intrastate sales of gas not comparable to interstate sales regulated by the Federal Power Commission).
In Middleton, we considered when gas is sold within the meaning of a royalty clause based on “market value at the well.” Exxon contended that the gas was sold at the time Exxon entered into a long term contract with the purchaser, and that market value should be determined as of then. We disagreed, holding that market value is determined at the point in time when the gas is actually produced and delivered. 613 S.W.2d at 245. We also concluded that “sold at the wells” means sold at the wells within the lease, not sold at wells within the field. Id. at 243.
We had occasion to consider whether an operator owes a duty to a non-participating interest owner to process gas in Danciger Oil & Refineries, Inc. v. Hamill Drilling Co., 141 Tex. 153, 171 S.W.2d 321 (1943). We determined that the operator was not obligated to process the gas where the agreement provided that an overriding royalty interest would be computed on %th of the gas “produced, saved and marketed at the prevailing market price paid by major companies ... free and clear of operating expenses.” Id., 171 S.W.2d at 322-23. The only market in the vicinity was for processed *126gas. There was no market for gas produced in its raw state at the wellhead. We reasoned that the overriding royalty payments were to be made out of gas “if, as and when produced,” not out of its value after it had been processed into a more valuable product, even though the clause also referred to gas “marketed.” Id. at 322. We further held that “operating costs” meant the expenses necessary to market the gas, not processing the gas into some other product. Id. at 323.
We have recognized that for occupation tax purposes, the market value of processed gas is measured as to all ownership interests, including royalty interests, by the total proceeds of the sale of the component parts of the gas after processing, less transportation and processing costs. Mobil Oil Corp. v. Calvert, 451 S.W.2d 889, 892 (Tex.1970). In Mobil, market value was defined in the tax statute as value “at the mouth of the well.” Id. at 891.
But these decisions do not directly answer the question of who bears marketing costs under a “market value at the well” royalty clause in a lease. Our Court has spoken to this issue only obliquely. In Upham v. Ladd, 128 Tex. 14, 95 S.W.2d 365, 366 (1936), we concluded that a lessor suing for underpayment of royalties based on a clause calling for payment of “proceeds” had stated a cause of action, but noted that the question of construction of the lease was not yet before the Court.
Decisions of the courts of appeals and other courts applying Texas law have confronted the question of whether post-production costs may be allocated to the royalty interest owners, but the holdings are not entirely consistent and construe differing provisions.
One of the earliest decisions dealing with Texas law on the subject of marketing costs and payment of royalties was Phillips Petroleum Co. v. Bynum, 155 F.2d 196 (5th Cir.1946). In discussing how to arrive upon the market value of gas, the Fifth Circuit observed that in the absence of available evidence of market price at the well, it “would seem appropriate” to look at the market price paid by the purchasers in the area at the point of sale, and to then deduct transportation costs. Id. at 198. The Fifth Circuit assumed without discussion that transportation charges should be deducted in arriving upon market value. See also Phillips Petroleum Co. v. Johnson, 155 F.2d 185, 189 (5th Cir.), cert. denied, 329 U.S. 730, 67 S.Ct. 87, 91 L.Ed. 632 (1946) (decided the same day, holding that royalty on processed gas is Jéth of the sale proceeds less a credit for transportation, separation, and sales costs under a royalty clause that called for “⅜⅛ of net proceeds derived from the sale of the gas at the mouth of the well”); Holbein v. Austral Oil Co., Inc., 609 F.2d 206, 209 (5th Cir.1980) (dehydration costs deductible from royalty under clause basing royalty on amount realized from the sale of gas).
At least two decisions from Texas courts of appeals are at odds with the approach taken by the Fifth Circuit. The royalty in Miller v. Speed, 248 S.W.2d 250, 256 (Tex.Civ.App.—Eastland 1952, no writ), was held to be free of any marketing costs. The provision under consideration was not expressly a market value clause. It simply provided for a royalty of ½4⅛ of all gas produced, saved and made available for market. The case of Pan American Petroleum Corp. v. Southland Royalty Co., 396 S.W.2d 519, 524-25 (Tex.Civ.App.—El Paso 1965, writ dism’d w.o.j.), relied on Miller and reasoned that a royalty interest is free of the cost of production and marketing costs. The poorly worded royalty clause in Pan American was based on proceeds and also provided for delivery of the lessor’s share of the minerals “free of cost.” See also Skaggs v. Heard, 172 F.Supp. 813 (S.D.Tex.1959) (compression costs could not be charged to the lessor where the sale occurred on the lease and the royalty clause provided for royalties based on proceeds).
In contrast, other Texas courts of appeals have allowed certain marketing costs to be allocated to the royalty owner. Only one of those cases dealt with a market value royalty clause, Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24 (Tex.App.—Texarkana 1984), writ dism’d as moot, 760 S.W.2d 960 (Tex.1988). Hagen held that market value at the well is the market value of the gas where sold, less reasonable and necessary transportation and processing costs. Id. at 28. Similarly, in *127Parker v. TXO Prod. Corp., 716 S.W.2d 644 (Tex.App.—Corpus Christi 1986, no writ), the royalty owner was required to share in post-production compression costs. In dicta, the Parker court indicated that all post-production costs could be charged to the royally owners. Id. at 648. The specific terms of the royalty clause cannot be discerned from the opinion in Parker.
Marketing costs were also charged to the royalty owners in Le Cuno Oil Co. v. Smith, 306 S.W.2d 190 (Tex.Civ.App.—Texarkana 1957, writ ref d n.r.e.), cert. denied, 356 U.S. 974, 78 S.Ct. 1137, 2 L.Ed.2d 1147 (1958). The parties agreed that a division order calling for ⅛⅛ of the price received at the wells governed the royalty, and the court held costs of dehydration, gathering, transporting, and processing could be deducted from the gross sales price received by the operator. Id, at 193. See also Martin v. Glass, 571 F.Supp. 1406, 1411-15 (N.D.Tex.1983), aff'd, 736 F.2d 1524 (5th Cir.1984) (post-production compression charges held deductible under a royalty clause based on net proceeds at the well). The court found that “net proceeds” contemplated deductions. 571 F.Supp. at 1411. See also Maddox v. Texas Co., 150 F.Supp. 175, 180 (E.D.Tex.1957) (“fair value” was the measure where there was no market and marketing costs must be considered where the lease required the lessor to bear its proportionate cost of rendering gas merchantable).
To add another point of view on this subject, a Texas court of appeals recently held that a royalty clause based on “market value at the well” was ambiguous. That court upheld a jury finding that the parties did not intend to allow the deduction of compression charges from royalties. Judice v. Mewbourne Oil Co., 890 S.W.2d 180 (Tex.App.—Amarillo 1994), reversed today by this Court in a companion decision, 939 S.W.2d 133.
While it is fair to say that the greater number of courts considering Texas law have permitted allocation of post-production costs to royalty owners, there are decisions reaching the opposite conclusion. It remains for this Court to determine whether “market value at the well” includes or excludes post-production costs. Decisions from other jurisdictions illuminate the arguments on both sides of the issue and offer a variety of potential resolutions.
B
One of the most comprehensive discussions of “market value at the well” royalty clauses is Judge Wisdom’s decision in Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir.1984), cert. denied, 471 U.S. 1005, 105 S.Ct. 1868, 85 L.Ed.2d 161 (1985). Although that decision applies Mississippi law, the court’s review of the law is not restricted to Mississippi jurisprudence. Among other authorities, the opinion considers at some length the meaning attributed to “market value at the well” by numerous commentators, concluding that the purpose in specifying “at the well” is to distinguish between gas sold in the form in which it emerges from the wellhead and gas which thereafter has had value added by transportation or processing. Id. at 231, 240. The Fifth Circuit held that royalties under a “market value at the well” clause should compensate only for the value of the gas at the well, before the operator adds value. Id. Accordingly, that court concluded that royalty owners may be charged with all expenses subsequent to production including processing, transportation, removal of sulfur, and other marketing costs where the royalty provision measures value “at the well.” Id. This reasoning is persuasive.
It has not been followed, however, by the highest courts of some of our sister states. The implied obligation to market gas was held to be paramount in Garman v. Conoco, Inc., 886 P.2d 652 (Colo.1994). After surveying the law in other jurisdictions and examining the rationale underpinning the various decisions, the Supreme Court of Colorado concluded that the implied covenant to market gas obligates the lessee to incur post-production costs necessary to place the gas in a condition acceptable for market. Id. at 659. Examples of costs borne solely by the lessee included gathering and compression costs to move the gas from the wellhead to a processing plant, and dehydration costs. Id. at 655-56 n. 8. The court did draw a distinction, though, between costs necessary to *128market the gas and those that increased value after the gas had been rendered marketable. Id. at 661. The court imposed the burden on the lessee to demonstrate that costs enhancing an already marketable product are reasonable and that they increase royalty revenues in proportion -with those costs. Id. at 661. It should be noted that this case was decided essentially in a vacuum, without reference to any specific lease clause. A general question had been certified to the court.
The Oklahoma supreme court, after similarly surveying other states’ decisions, concluded that the implied duty to market gas is a duty to “get the product to the place of sale in marketable form.” Wood v. TXO Prod. Corp., 854 P.2d 880, 882 (Okla.1992). A “market value at the well” clause was at issue. The court held that compression charges necessary for the gas to enter the purchaser’s pipeline could not be deducted from the royalty where the sale occurred on the lease premises. Id. In the dissenting opinion, four members of the court found this result “harsh and untenable” and would have adopted the “better-reasoned” approach of allowing the deduction of compression costs. Id. at 883.
The majority in Wood v. TXO distinguished that court’s prior decision in Johnson v. Jernigan, 475 P.2d 396 (Okla.1970), which held that the obligation to market did not require the operator to absorb the cost of transporting gas ten miles by pipeline to the point of sale off the lease. Johnson extended the duty to market only to the lease boundaries. Id. at 399. The Johnson court reached this conclusion even though the lease called for royalties based on the “gross proceeds at the prevailing market rate for all gas sold off the premises.” Id. at 397. The court reasoned that “gross proceeds” had reference to the value of the gas on the lease property “without deducting any of the expenses involved in developing and marketing the dry gas to this point of delivery.” Id. at 399.
Kansas courts have also seemed to draw a distinction between sales on the lease premises and those off the premises in deciding whether marketing costs may be passed on to the royalty owner. Language in the lease specifying that royalty is to be determined “at the well” has not appeared to be a factor in the courts’ decisions. Compare Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964) (lessee cannot deduct post-production compression costs where sale occurred on the lease and royalty clause was based on proceeds at the mouth of the well; court noted that compression was installed without consulting royalty owners as to size, location and number of compressors); and Gilmore v. Superior Oil Co., 192 Kan. 388, 388 P.2d 602 (1964) (could not recover compression costs under lease based on “proceeds from the sale of gas at the mouth of the well”; court emphasized that compression was installed on the lease and recognized duty to market, distinguishing situations where market is distant from the lease) with Matzen v. Hugoton Prod. Co., 182 Kan. 456, 321 P.2d 576, 581-82 (1958) (where gas gathered, processed and sold off premises, lessee may deduct these costs from gross proceeds under clause based on proceeds from the sale of gas, even though lease silent as to where market must be found); and Molter v. Lewis, 156 Kan. 544, 134 P.2d 404, 406 (1943) (implied covenant to market does not require lessee to bear cost of transporting oil by truck to a distant place even though lease provided for delivery by lessee to lessor into pipeline “free of cost”). See also Ashland Oil & Refining Co. v. Staats, Inc., 271 F.Supp. 571, 575 (D.Kan.1967) (refusing to enlarge lessee’s duty to market to require it to bear full cost of 153-mile pipeline system).
Arkansas seems to recognize a distinction between royalty based on “proceeds” versus “market value at the well,” even if the proceeds are to be determined “at the well.” Compare Hanna Oil & Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563, 564-65 (1988) (compression costs necessary to market gas not deductible under lease providing for royalty on proceeds received at the well), with Clear Creek Oil & Gas Co. v. Bushmiaer, 165 Ark. 303, 264 S.W. 830, 832 (1924) (under lease calling for royalty based on market price at the wells, royalty was net price after deducting transportation costs).
*129Kentucky and Wyoming decisions appear to permit the deduction of at least transportation charges where the sale occurs off the lease. Reed v. Hackworth, 287 S.W.2d 912, 913-14 (Ky.Ct.App.1956) (where lease silent as to place of market, royalty is based on market at the well); Kretni Dev. Co. v. Consolidated Oil Corp., 74 F.2d 497, 500 (10th Cir.1934), cert. denied, 295 U.S. 750, 55 S.Ct. 829, 79 L.Ed. 1694 (1935), (obligation to market did not extend to providing ninety-mile pipeline for distant market at sole cost of lessee).
California law appears to allow the deduction of marketing costs under a “market price at the well” clause, absent language to the contrary. Atlantic Richfield Co. v. State, 214 Cal.App.3d 533, 262 Cal.Rptr. 683, 688 (1989, review denied) (unless there is clear language to the contrary, lessor bears proportionate share of processing and transportation costs when term “market price at the well” is used).
The North Dakota supreme court took a route similar to that of our court of appeals in Judice. West v. Alpar Resources, Inc., 298 N.W.2d 484, 490-91 (N.D.1980). The North Dakota court found a royalty clause ambiguous where it specified only that the royalty was “one-eighth of the proceeds from the sale of the gas,” and did not specify whether proceeds were to be determined at the well or at the point of sale. The North Dakota court proceeded to construe the lease against the lessor as a matter of law, requiring the lessor to bear all costs. Id. at 491.
Finally, courts applying Louisiana law have uniformly held that post-production costs are deductible under a “market value at the well” clause, commencing with the Louisiana supreme court’s decision in Wall v. United Gas Pub. Serv. Co., 178 La. 908, 152 So. 561, 564 (1934) (market price means market value in the field and the lessee is not required to bear all the expense of carrying gas to a market beyond the field). Louisiana has applied a “reconstruction” approach to determine market value. Value is “reconstructed” by beginning with the gross proceeds from the sale of the gas and deducting any costs of taking the gas from the wellhead to the market. See Merritt v. Southwestern Elec. Power Co., 499 So.2d 210, 213 (La.Ct.App.1986) (compression charges to market gas, as opposed to produce it, could be deducted). For a good discussion of the rationale underpinning Louisiana law in this area, see Freeland v. Sun Oil Co., 277 F.2d 154 (5th Cir.1960), cert. denied 364 U.S. 826, 81 S.Ct. 64, 5 L.Ed.2d 55 (processing costs can be deducted). See also Sartor v. United Gas Pub. Serv. Co., 84 F.2d 436, 440 (5th Cir.1936) (transportation charges deductible under “market value at the well” leases).
Having canvassed the law of other states, it can fairly be said that there is no consensus among other jurisdictions as to when post-production costs are to be shared by the royalty owner, although the majority view appears to be that royalty owners do share in costs, at least where the sale occurs off the lease.
C
In the case before us, the court of appeals concluded that “market value at the well” meant that the royalty interests were subject to costs incurred after production, including taxes, costs of treating the gas, and costs of transportation to market, unless other language in the lease modified this provision. 895 S.W.2d at 836. This is the better-reasoned view.
While Texas recognizes that the lessee has an implied duty to market gas, Cabot Corp. v. Brown, 754 S.W.2d 104, 106 (Tex.1987), we have never determined who bears the cost of marketing gas beyond the wellhead in the absence of an express agreement. There is an express agreement in this case as to how and where royalty will be determined. The implied duty to market gas cannot override that agreement. The words “at the well” should be given their straightforward meaning. Market value “at the well” means the value of gas at the well, before it is transported, treated, compressed or otherwise prepared for market.
In construing language commonly used in oil and gas leases, we must keep in mind that there is a need for predictability and uniformity as to what the language used means. Parties entering into agreements expect that *130the words they have used will be given the meaning generally accorded to them. As we have seen, the decisions under Texas law are not entirely consistent, but the weight of the precedent is that post-production costs are to be shared by the royalty owner under a lease that values the gas based on “market value at the well.” See Phillips Petroleum Co., 155 F.2d at 198; Martin, 571 F.Supp. at 1411-15; Hagen, 683 S.W.2d at 28; and Le Cuno Oil Co., 306 S.W.2d at 193. See also Parker, 716 S.W.2d at 648. These decisions are not binding, but are persuasive.
Having concluded that marketing costs are to be shared by the royalty interest owners under a “market value at the well” clause, absent language to the contrary, it must be determined whether there is language in the leases in this case that re-allocates these costs.
Ill
The language of the pertinent clause states:
Lessee shall pay the Lessor ... market value at the well for all gas ... sold ... off the leased premises ... provided, however, that there shall be no deductions from the value of Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.
It is clear certain “deductions” are prohibited. The question that must be answered is from what are deductions prohibited. The clause says “from the value of Lessor’s royalty.” The value of Lessor’s royalty is “market value at the well” for gas sold off the leased premises.
The court of appeals correctly observed that the intent of the parties is determined from what they actually expressed in the lease as written, not what they may have intended but failed to express. 895 S.W.2d at 836. However, the court of appeals did not apply this principle. It reasoned that the parties “must have intended something by this language,” and in order to give the language some meaning, the court construed the proviso to mean that royalty owners do not share in post-production costs. Id.
There is little doubt that at least some of the parties to these agreements subjectively intended the phrase at issue to have meaning. However, the use of the words “deductions from the value of Lessor’s royalty” is circular in light of this and other courts’ interpretation of “market value at the well.” The concept of “deductions” of marketing costs from the value of the gas is meaningless when gas is valued at the well. Value at the well is already net of reasonable marketing costs. The value of gas “at the well” represents its value in the marketplace at any given point of sale, less the reasonable cost to get the gas to that point of sale, including compression, transportation, and processing costs. Evidence of market value is often comparable sales, as the Court indicates, 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. But, regardless of how value is proven in a court of law, logic and economics tell us that there are no marketing costs to “deduct” from value at the wellhead. See Piney Woods Country Life Sch., 726 F.2d at 231.
Further, prohibiting deductions “from the value of Lessor’s royalty” is not the equivalent of directing that value be based on anything other than “market value at the well.” The Court is not presented with a clause similar to one at issue in Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 136 (Tex.1996), where a division order directed royalties to be based on “gross proceeds realized at the well.” There is an inherent, irreconcilable conflict between “gross proceeds” and “at the well” in arriving at the value of the gas. That conflict renders the phrase ambiguous. The proviso in the Heritage leases does not create an ambiguity. It is simply ineffective.
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 *131issue 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 surplus-age.
However, the proviso prohibiting the deduction of marketing costs would not be sur-plusage if we interpreted “market value at the well” to obligate the lessee to pay some, but not all, marketing costs. For example, it has been argued that at least some post-production costs, such as compression, should be borne solely by the lessee as part of its duty to market the gas, but that other costs, such as processing, should be shared by the lessor. See, e.g., Garman v. Conoco, Inc., 886 P.2d at 654. Such an interpretation of a royalty clause would mean that value is determined on a basis other than value “at the well.” If “value” were not referable to “market value at the well,” but encompassed other considerations, then the proviso could be construed to prohibit the deduction of any costs “required ... to market such gas.” But such an approach injects uncertainty into the meaning of “market value at the well” leases, and could lead to a fact-finding inquiry in virtually every case as to what was and was not a cost “required to market the gas.” This weighs heavily against adopting the approach apparently taken in Colorado where the lessee has a duty to “create a marketable product,” and a fact question exists as to what costs are required to make the gas marketable. Id. at n. 3. Our Court has correctly concluded that “market value at the well” means just that, what a willing buyer would pay at the well, recognizing there would be costs to get the gas from the wellhead to a market.
There are any number of ways the parties could have provided that the lessee was to bear all costs of marketing the gas. If they 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. If they had intended that in addition to the payment of market value at the well, the lessee would pay all post-production costs, they could have said so. They did not. There is no direct statement in the leases that the royalty owners are to receive anything in addition to the value of their royalty, which is based on value at the well. To the contrary, the leases only prohibit any deduction from value at the well. This distinction may be a fine one, but the language used is not ambiguous and must be given its ordinary meaning.
We cannot re-write the agreement for the parties. See, e.g., Exxon v. Middleton, 613 S.W.2d at 245 (quoting Vela, 429 S.W.2d at 871) (explaining that if Exxon had intended its royalty obligation to be based on the prices it actually received under long term sales contracts, it could have agreed in the lease that royalty would be based on the “amount realized” from the sale, rather than “market value at the well”).
*|v ⅜ ⅜ ¾* H*
For the foregoing reasons, I concur in the judgment of the Court.
. One of the leases differs somewhat from the others. Because of the way in which the royalty clause of that lease is structured, an argument could be made that the proviso prohibiting the deduction of marketing costs from the value of the royalty applies only when the sale of gas occurs at the well and that the proviso does not apply when determining the market value of gas sold off the lease. It is unnecessary to decide that issue, however, because the parties agree that the proviso does apply under this lease as well as under the other leases in determining the market value of gas at the well when it is sold off the premises.
. For a general discussion of these competing principles and some of the divergent decisions, see Wood v. TXO Production Corp., 854 P.2d 880 (Old.1992). See also 3 Williams. Oil & Gas Law § 645 (1990).