939 S.W.2d 118
Tex.
1997

Lead Opinion

Justice BAKER

delivered the opinion of the Court,

in which Chief Justice PHILLIPS, Justice CORNYN, Justice ENOCH, and Justice SPECTOR join.

This case involves construction of royalty clauses in several oil and gas leases. Nati-onsBank sued Heritage contending that Heritage deducted transportation costs from the value of NationsBank’s royalty in violation of the leases.

The trial court rendered a partial summary judgment against Heritage deciding liability and damages through 1991. Nati-onsBank amended its pleading to include Heritage’s deductions through 1993. After a bench trial, the trial court awarded Nati-onsBank and other royalty owners the transportation costs Heritage deducted plus interest and attorney’s fees.

The court of appeals affirmed the trial court’s judgment. 895 S.W.2d 833. It held that the royalty clauses showed the parties’ intent not to deduct the post-production transportation costs when determining market value at the well. 895 S.W.2d at 836-37. The court of appeals also held that the division orders Heritage and the royalty owners executed did not bind the royalty owners and that Heritage was liable for the full amount deducted. 895 S.W.2d at 839.

We conclude the trial court and the court of appeals incorrectly interpreted the royalty clauses. We reverse the court of appeals’ judgment. We render judgment that Nati-onsBank take nothing. Further, we disapprove of the court of appeals’ language about the liability of an operator who underpays royalty interest owners.

Facts

NationsBank is the trustee for owners of interests in gas, oil, and other minerals inherited under David B. Trammel’s will. Heritage is the lessee and operator under a number of leases. Heritage also owns an undivided working interest in some of the leases. Heritage sold gas off the leased premises. Heritage deducted the cost to transport the gas from the wellhead to the point of sale as a post-production cost from the sales price before calculating royalties.

In January 1989, NationsBank noticed that Heritage was deducting severance taxes and transportation charges from the purchase price. NationsBank objected to the transportation charge deduction. NationsBank contended that the leases specifically prohibited the deduction. Three different leases are in issue. The relevant parts are:

3. The royalties to be paid Lessor are ...
(b) on gas, including casinghead gas or other gaseous substances produced from the land, or land consolidated therewith, and sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of ⅜ of the gas so sold or used, provided that on gas sold at the well the royalty shall be ⅜ of the amount realized from such sale provided, however, 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.

or:

3. In consideration of the premises, Lessee covenants and agrees ...
(b) To pay the Lessor ⅛ of the market value at the well for all gas (including substances contained in such gas) produced from 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, compres*121sion, transportation, or other matter to market such gas.

or

3. Lessee shah pay the following royalties subject to the following provisions: ...
(b) Lessee shall pay the Lessor ⅜ of the market value at the weh for all gas (including ah substances contained in such gas) produced from the leased premises and sold by Lessee or used off the leased premises, including sulphur produced in conjunction therewith; 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.

Although the court of appeals states that the leases are virtually identical, the first lease is distinctly different from the others. In the first lease, for gas sold on the lease, royalty is on proceeds, with no deduction for marketing costs, but if sold at a point off the lease, the royalty is the market value at the well. However, this difference is irrelevant for purposes of this opinion. All three leases require us to determine if Heritage improperly deducted transportation costs from the royalty payments. The critical clause in all three leases is the requirement that Heritage pay the royalty interest owners their fractional interest of “the market value at the well” of the gas produced.

Royalty Clause Construction

Heritage contends that the royalty clauses define the lessor’s royalty as a fraction of the market value at the well. Therefore, the clauses limiting deduction from the value of the lessor’s royalty simply means that Heritage cannot deduct an amount from the sales price that would make the royalty paid less than the required fraction of market value at the well. Because NationsBank concedes Heritage only deducted reasonable transportation costs from the market value at the point of sale, Heritage did not make a deduction from the “value of the Lessor’s royalty.”

The court of appeals rejected Heritage’s interpretation of the royalty clause. 895 S.W.2d at 836. The court of appeals reasoned that because royalty interests are normally subject to post-production costs, Heritage’s interpretation renders the post-production clause meaningless. 895 S.W.2d at 837. Although we do not disagree with the court of appeals’ reasoning in this respect, we find that applying the trade meaning of royalty and market value at the well renders the post-production clauses surplus-age as a matter of law.

(a) Applicable Law

Oil and Gas Lease Construction

The question of whether a contract is ambiguous is one of law for the court. R & P Enters. v. LaGuarta, Gavrel & Kirk, Inc., 596 S.W.2d 517, 518 (Tex.1980). A contract is ambiguous when its meaning is uncertain and doubtful or is reasonably susceptible to more than one interpretation. Coker v. Coker, 650 S.W.2d 391, 393 (Tex.1983). In construing an unambiguous oil and gas lease our task is to ascertain the parties’ intentions as expressed in the lease. Sun Oil Co. v. Madeley, 626 S.W.2d 726, 727-28 (Tex.1981); McMahon v. Christmann, 157 Tex. 403, 303 S.W.2d 341, 344 (1957). To achieve this goal, we examine the entire document and consider each part with every other paid so that the effect and meaning of one part on any other part may be determined. Steeger v. Beard Drilling, 371 S.W.2d 684, 688 (Tex.1963). We presume that the parties to a contract intend every clause to have some effect. Ogden v. Dickinson State Bank, 662 S.W.2d 330, 331 (Tex.1983). We give terms their plain, ordinary, and generally accepted meaning -unless the instrument shows that the parties used them in a technical or different sense. Western Reserve Life Ins. Co. v. Meadows, 152 Tex. 559, 261 S.W.2d 554, 557 (1953), cert. denied, 347 U.S. 928, 74 S.Ct. 531, 98 L.Ed. 1081 (1954). This Court will enforce the unambiguous document as written. Sun Oil Co., 626 S.W.2d at 728. Both the trial court and the court of appeals determined that the leases in question were unambiguous. We agree.

Royalty

Royalty is commonly defined as the landowner’s share of production, free of *122expenses of production. See Delta Drilling Co. v. Simmons, 161 Tex. 122, 338 S.W.2d 143, 147 (1960); Alamo Nat’l Bank v. Hurd, 486 S.W.2d 335, 338 (Tex.Civ.App.—San Antonio 1972, writ ref'd n.r.e.); 8 Williams & Meyers, Oil & Gas Law, 856-57 (1987); 3 Kuntz, Oil & Gas Law, § 42.2 (1989). Although it is not subject to the costs of production, royalty is usually subject to post-production costs, including taxes, treatment costs to render it marketable, and transportation costs. Martin v. Glass, 571 F.Supp. 1406, 1410 (N.D.Tex.1983), aff'd, 736 F.2d 1524 (5th Cir.1984); Williams & Meyers, supra, p. 857. However, the parties may modify this general rule by agreement. Martin, 571 F.Supp. at 1410.

Market Value at the Well

Market value at the well has a commonly accepted meaning in the oil and gas industry. See generally Wakefield, Annotation, Meaning of, and Proper Method for Determining, Market Value or Market Price in Oil and Gas Lease Requiring Royalty to be Paid on Standard Measured by Such Terms, 10 ALR 4th 732 (1981). Market value is the price a willing seller obtains from a willing buyer. See Exxon Corp. v. Middleton, 613 S.W.2d 240, 246 (Tex.1981). There are two methods to determine market value at the well.

The most desirable method is to use comparable sales. Middleton, 613 S.W.2d at 246; Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 872 (Tex.1968). A comparable sale is one that is comparable in time, quality, quantity, and availability of marketing outlets. Middleton, 613 S.W.2d at 246; Vela, 429 S.W.2d at 872.

Courts use the second method when information about comparable sales is not readily available. See, e.g., Le Cuno Oil Co. v. Smith, 306 S.W.2d 190, 193 (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); Clear Creek Oil & Gas Co. v. Bushmiaer, 165 Ark. 303, 264 S.W. 830, 832 (1924); see also Pierce, Royalty Valuation Principles in a Changing Gas Market, in State Bae of Texas PROF. Dev. PROGRAM, 11th Annual Advanced Oil, Gas and Mineral Law Course E, E-9 (1993). This method involves subtracting reasonable post-production marketing costs from the market value at the point of sale. Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24, 28 (Tex.App.—Texarkana 1984), dism’d as moot, 760 S.W.2d 960 (Tex.1988). Post-production marketing costs include transporting the gas to the market and processing the gas to make it marketable. Hagen, 683 S.W.2d at 29. With either method, the plaintiff has the burden to prove market value at the well. Hagen, 683 S.W.2d at 29.

(b) Application of Law to the Facts

The court of appeals disregarded the generally accepted meanings of “market value at the well” and “royalty” to determine that Heritage wrongfully deducted post-production costs. The court of appeals’ construction results in a royalty clause that specifies royalty payable as a fraction of the market value at the well, to mean the royalty is payable as a fraction of the market value at the point of sale with no deductions for post-production costs.

The terms “royalty” and “market value at the well” have well accepted meanings in the oil and gas industry. The post-production clauses in issue here plainly state that there “shall be no deduction from the value of the Lessor’s Royalty.” The leases clearly set the lessor’s royalty as a fraction (⅛ or ½) “of the market value at the well.” Under the leases, the lessee must determine the value of the lessor’s royalty. The lessee accomplishes this by determining market value at the well and multiplying it by the fraction specified in the royalty clause (⅝ or ⅜). This result is the value of the lessor’s royalty. The post-production clauses then specify that there can be no deduction from this value (the value of the lessor’s royalty) by reason of any post-production costs.

Here, the only conclusion we can draw is that the post-production clauses merely restate existing law. The post-production clauses illustrate that the lessee cannot pay the lessor less than his fractional value of the comparable sales price (market value). This could occur if the amount realized from the *123sale of the gas less the post production costs was less than the comparable sales price and the lessee calculated the lessor’s royalty by subtracting post production costs from amount realized. At times the amount realized from the sale of gas has varied greatly from the market value of the gas. See Vela, 429 S.W.2d at 875-76 (evidence sustained trial court’s finding that market value was 13.047 cents per mcf even though amount realized by lessee under long term gas sales contract was 2.3 cents per mcf). Even though the Vela scenario may be unlikely to reoccur in the future due to changes in the market place, see, e.g. Pierce, supra, E-l— E-3, the market value may differ from the amount realized.

We recognize that our construction of the royalty clauses in two of the three leases arguably renders the post-productions clause unnecessary where gas sales occur off the lease. However, the commonly accepted meaning of the “royalty” and “market value at the well” terms renders the post-production clause in each lease surplusage as a matter of law.

To determine if Heritage correctly paid royalties under the leases, we must first determine the market value of the gas at the well. NationsBank offered no evidence of comparable sales. However, Heritage conceded in its response to NationsBank’s motion for partial summary judgment that the price Heritage received for the gas was the market price at the point of sale. Nations-Bank conceded at oral argument that the transportation costs Heritage deducted were reasonable.

Because there is no evidence to support the comparable sales method of computing market value at the well, we use the alternate method. Under that method, Heritage must pay a royalty based on the market value at the point of sale less the reasonable post-production marketing costs. Hagen, 683 S.W.2d at 28. Based on the parties’ concessions, the amount Heritage paid is the correct amount in royalties to NationsBank under the leases.

Division Orders

Heritage entered into division orders with the royalty owners. The division orders contained the following language:

All proceeds from the sale of gas shall be paid to the undersigned or their assigns in the proportions as herein set out less taxes and any costs incurred in the handling and transportation to the point of sale, treating, compressing boosting, dehydrating or any other conditioning necessary, subject to the terms of any contract of purchase and sale which affects the above described property ...

The court of appeals held that the division orders were of no effect and that Heritage was liable for reimbursement to the royalty owners for transportation costs improperly withheld in payment to Urantia. The court of appeals’ discussion about the effect of a division order that contradicts the lease terms conflicts with our earlier opinion in Gavenda v. Strata Energy, Inc., 705 S.W.2d 690 (Tex.1986).

The general rule is that division orders are binding until revoked. Gavenda, 705 S.W.2d at 691; Middleton, 613 S.W.2d at 250. When an operator prepares a division order that allocates payments among the interest owners in a manner that differs from the lease provisions and the operator retains the benefits, the division order is not binding. Gavenda, 705 S.W.2d at 692. The basis of this rule is unjust enrichment. Gavenda, 705 S.W.2d at 692. The operator then becomes liable for the part of the interest owner’s payments the operator retained. See Gavenda, 705 S.W.2d at 693. The operator is not liable for the amounts it paid out to other interest owners. Gavenda, 705 S.W.2d at 693.

The court of appeals decision incorrectly states that “Heritage was liable for reimbursement to the royalty owners for transportation costs improperly withheld in payment to Urantia.” 895 S.W.2d at 839. Under Gavenda, Heritage would be liable, if at all, only for the amount of the unpaid royalty it retained. In this case, there were other working interest owners who were not parties to the suit. Absent an agreement *124otherwise, all the working interest owners would benefit from an improper deduction of transportation charges from the royalties paid to NationsBank. Therefore the trial court could only hold Heritage liable for an amount of unpaid royalties that Heritage retained.

Summary

In conclusion, we hold that the court of appeals erred in holding that the lease required Heritage to pay royalties based on the market value at the point of sale. Further, we specifically disapprove of the court of appeals discussion about an erroneous division order’s effects. We reverse the court of appeals’ judgment and render judgment that NationsBank take nothing from Heritage.





Concurrence Opinion

Justice OWEN, joined by Justice HECHT,

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.

Notes

. 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).



Dissenting Opinion

Justice GONZALEZ, joined by Justice ABBOTT,

dissenting.

The simple question presented in this case is whether Heritage can deduct transportation costs from the value of NationsBank’s royalties under these leases. The language at issue, which is common to each contract, reads as follows:

[T]here 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.1

What could be more clear? This provision expresses the parties’ intent in plain English, and I am puzzled by the Court’s decision to ignore the unequivocal intent of sophisticated parties who negotiated contractual terms at arm’s length. See M/S Bremen v. Zapata Off-Shore Co., 407 U.S. 1, 12, 92 S.Ct. 1907, 1914, 32 L.Ed.2d 513 (1972) (noting that, absent compelling reason, contracts “made in an arm’s-length negotiation by experienced *132and sophisticated businessmen ... should be honored by the parties and enforced by the courts”); accord Prudential Ins. Co. v. Jefferson Assoc., 896 S.W.2d 156, 161 (Tex.1995). In my opinion, both the trial court and the court of appeals correctly held that this language clearly forbids Heritage from deducting transportation costs to arrive at the market value of the gas on which the royalty payment is based.

Fundamental principles of Texas law hold that competent parties enjoy the utmost freedom of contract and that courts will enforce a contract freely and voluntarily made for a lawful purpose. Crutchfield v. Associates Inv. Co., 376 S.W.2d 957, 959 (Tex.Civ.App.—Dallas 1964, writ ref'd). Under basic rules of contract interpretation, this Court must give effect to the written expression of the parties’ intent. See Forbau v. Aetna Life Ins. Co., 876 S.W.2d 132, 133 (Tex.1994). To do so involves reading all parts of the contract together, giving effect to each individual part. Id. In this ease, however, the Court unnecessarily looks to the trade meaning of the words used to conclude that the post-production clause is surplusage as a matter of law. 939 S.W.2d 118. Similarly, the concurrence needlessly considers other judicial constructions of “market value at the well,” including several non-Texas cases, without analyzing whether those contracts bear any similarity to the ones at issue here. Id. at 124 (Owen, J., concurring). Neither the majority nor the concurrence give proper legal effect to specific language in these contracts which clearly denotes the parties’ intent that “there shall be no deductions from the value of Lessor’s royalty by reason of any ... cost of ... transportation.” See Forbau, 876 S.W.2d at 133-34.

Heritage was free to bargain over whether NationsBank would have the right to participate in post-production business activities and receive royalties derived from those activities. The lease provision incorporates all four of the distinct business activities into which most gas production operations can be divided: production, gathering, marketing, and processing. It clearly excludes deductions for “any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.” The drafters of this clause could have allowed for deductions of the cost of any of the distinct business activities that occur after the production of gas, but chose not to include language to that effect. The language in the lease provision is clear, and in the absence of fraud or misrepresentation, a party is charged with knowing the legal effect of a contract voluntarily made. Barfield v. Howard M. Smith Co., 426 S.W.2d 834, 838 (Tex.1968). Because the provision at issue is unambiguous, the Court errs by ignoring the clear intent of the parties.

The majority and the concurrence both state that they agree with the trial court and the court of appeals that the leases in question are unambiguous. 939 S.W.2d 118; id. at 124 (Owen, J., concurring). I find their agreement odd and amusing given that, interpreting the same contracts, both opinions reach a completely opposite result than the lower courts. By definition, if a contract is reasonably susceptible to more than one meaning, it is ambiguous. Coker v. Coker, 650 S.W.2d 391, 393 (Tex.1983); Shelly Oil Co. v. Archer, 163 Tex. 336, 356 S.W.2d 774, 778 (1961). By supplying a meaning not found in the leases for “market value at the well,” both the majority and the concurrence create'an ambiguity where none exists.

When a contract contains an ambiguity, we consider the words used in the instrument, in light of the surrounding circumstances, and apply the appropriate rules of construction to settle their meaning. Harris v. Rowe, 593 S.W.2d 303, 306 (Tex.1979). Assuming for the sake of argument that these contracts are ambiguous, we must apply two of the most basic rules governing interpretation of oil and gas leases: (1) contracts are to be construed against the scrivener; and (2) leases are to be construed against the lessee. The “construe against the scrivener” canon flows from basic contract law. See Kramer, The Sisyphean Task of Interpreting Mineral Deeds and Leases: An Encyclopedia of Canons of Construction, 24 Tex.Tech L.Rev. 1, 103 (1993). This canon allocates the burden of uncertainty caused by the use of inappropriate or vague language in a written instrument. To the extent the court can identify the party who either drafted the instrument *133or provided the form used, the canon requires that the uncertainty be resolved against that party. The “construe against the lessee” canon functions similarly. When an oil and gas lease is subject to two or more equally reasonable constructions, “the one more favorable to the lessor will be allowed to prevail.” Zeppa v. Houston Oil Co., 113 S.W.2d 612, 615 (Tex.Civ.App.—Texarkana 1938, writ ref'd); see also Stanolind Oil & Gas Co. v. Newman Bros. Drilling Co., 157 Tex. 489, 305 S.W.2d 169,176 (1957). In the present case, Heritage indisputably wrote the lease contracts and occupied the position of lessee. Thus, even if the provision is ambiguous, application of the basic rules of interpreting oil and gas leases would result in a construction against Heritage and in favor of NationsBank.

I have one final concern about today’s decision. By attributing an unequivocal, precise meaning to “market value at the well” in oil and gas leases, the Court announces a new rule that should be applied only prospectively. See generally Carrolton-Farmers Branch Indep. Sch. Dist. v. Edgewood Indep. Sch. Dist. 826 S.W.2d 489, 515-521 (Tex.1992) (discussing factors for deciding between retroactive and prospective operation). We have limited the effect of our decisions in this manner when considerations of fairness and policy preclude full retroactivity. See, e.g., Moser v. United States Steel Corp., 676 S.W.2d 99, 103 (Tex.1984) (limiting new rule concerning phrase “other minerals” in deeds to prospective application). This result is appropriate in the present case because, before now, the meaning of “market value at the well” was subject to specific negotiation by the parties. Indeed, as the concurring opinion notes, this Court has never decided previously whether ‘“market value at the well’ includes or excludes post-production costs,” 939 S.W.2d at 127 (Owen, J., concurring), and lower courts have not reached agreement on the issue. See id. at 126. Compare Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24, 28 (Tex.App.—Texarkana 1984) (concluding that “market value at the well” includes deduction for “the reasonable cost of transporting the gas to the market”), writ dism’d as moot, 760 S.W.2d 960 (Tex.1988) with Heritage Resources, Inc. v. Nationsbank, 895 S.W.2d 833, 836-37 (Tex.App.—El Paso 1995) (determining that market-value royalty clause did not allow deduction for transportation costs), rev’d, 939 S.W.2d 118 (Tex.1996). Today, the Court decides that question, but substitutes its own interpretation of the phrase for the meaning the parties intended. The Court blindsides Nations-Bank and other lessors by mandating that this decision apply retroactively.

This decision wrongfully denies parties such as NationsBank the right to collect royalty payments for which they clearly bargained. For the foregoing reasons, I dissent.

. The royalty clause in one lease differs slightly from the others. However, any differences are immaterial to resolving the issue presented.