with whom WATT, Justice, joins, dissenting in part.
¶ 1 Pursuant to the provisions of the Uniform Certification of Questions of Law Act, 20 O.S.1991 § 1601 et seq, the United States Court of Appeals for the Tenth Circuit (certifying court) certified the following question:
Is an oil and gas lessee who is obligated to pay ‘3/16 of the gross proceeds received for the gas sold’ entitled to deduct a proportional share of transportation, compression, dehydration, and blending costs from the royalty interest paid to the lessor?
Today’s opinion adopts the Garman1 approach to determining the point of first marketability of gas. The court holds that (a) a lessee may not deduct a proportionate share of transportation, compression, dehydration, and blending costs from the royalty interest when such costs are associated with creating a first-marketable product; (b) the lessor must bear a proportionate share of these costs if the lessee can show that (1) post-production costs enhanced the value of an already marketable product and are reasonable and (2) actual royalty revenues increased in proportion to the costs assessed against the nonworking interest; and (c) cus*1211tom and usage should be considered in determining the scope of duties due under the lease.
¶ 2 Because I would apply the Anderson first-marketable product analysis,2 I recede from today’s pronouncement. Under the Anderson approach (a) royalty will be paid on the price the lessee obtained or could have obtained for the sale of the first-marketable form of the gas and (b) the point of first-marketability is a question of fact. The lessee has no obligation to pay royalty on any additional value that post-production activities add to a marketable product. Generally no work-back calculations should be necessary other than a possible deduction of transportation costs if the point of first-marketability is not in the vicinity of the well.
I
ANATOMY OF LITIGATION
¶3 Ted and Ruth Mittelstaedt [Mittel-staedts or lessors] claimed they were not receiving the full 3/16 of the gross proceeds from the gas sold due them under the terms of a lease for their two gas wells in Canadian County. Santa Fe Minerals, Inc. [Santa Fe or Lessee] responded that it rightfully deducted from the 3/16 royalty payment the lessors’ share of certain marketing expenses.
¶4 Santa Fe performed some compression operations and incurred related expenses at the wellhead but did not charge the royalty interests with these costs. The gas was then moved to a location off the leased premises, where Santa Fe paid fees to unaffiliated third parties for transportation, blending, dehydration, and compression of the gas. Santa Fe did charge a portion of these costs against the royalty interests. The gas was then transported further downstream where it was placed into the purchaser’s pipeline. The lessors sued Santa Fe to recover the portion of costs that Santa Fe charged against their royalty interests.
II
THE NATURE OF THIS COURT’S FUNCTION WHEN ANSWERING A CERTIFIED QUESTION FROM A FEDERAL COURT
¶ 5 While in answering the queries posed by a federal court the parameters of state-law claims or defenses (identified by the submitted questions) may be tested, it is not this court’s province to intrude (by its responses) upon the certifying court’s decision-making process.3 The latter court must be left entirely free to assess the impact of the answers and to make its own appraisal of the proof in the case before it.4 Because this action is not before this court for decision, we must refrain from applying the declared state-law responses to the facts now known or to be elicited in the federal court litigation, which are in use or will be used in the summary adjudication process.5 The task of analyzing today’s answers for their application to this case is deferred to the certifying court.
III
OKLAHOMA’S ROYALTY JURISPRUDENCE
¶ 6 My analysis requires an examination of three Oklahoma cases and an explanation why we should depart from their holdings: Johnson v. Jernigan [Johnson];6 Wood v. TXO Prod. Corp. [Wood];7 and TXO v. State ex rel. Comm’rs of the Land Office [CLO].8
Johnson v. Jernigan
¶ 7 In Johnson, gas lessors alleged that the lessees wrongfully deducted transportation costs from their l/8th royalty interest in *1212the “gross proceeds” from gas production under the lease. Since there was no market on the leased premises (i.e., no willing buyer), the court allowed the-lessee to charge against the lessor’s royalty interest a share of the costs of transporting the gas to the nearest market.9 The court declared that the lessee’s duty to market the gas does not include bearing the full cost burden of transportation to an off-site purchaser.10 Rather, the lessee’s financial obligation ends when the gas is made available for market, and any further expenses beyond the leased property must be shared by the lessor.11
Wood v. TXO
¶ 8 In Wood, the court declined to extend the Johnson holding to allow lessees to deduct compression costs from royalty interests. The lessee in Wood built compressors on the premises because the natural pressure from the wells turned out insufficient to deliver the gas into the purchaser’s on-site pipeline.12 The lessee then subtracted from the royalty payments the lessors’ proportionate share of the compression costs. The lessors sought to recover these costs.13 The court held that, absent an agreement between the parties to share compression costs, the lessee must bear the entire expense of gas compression.14
¶ 9 The pronouncement noted that other jurisdictions are split on the question whether the lessors must bear their proportionate share of compression costs. While Louisiana and Texas jurisprudence allows the lessee to deduct compression costs,15 the court preferred the Kansas and Arkansas approach that prohibits such deductions.16 Hesitant to assign costs to the lessor who has no input into the lessee’s marketing decisions, the court concluded that the lessee’s implied duty to market encompasses all market preparation costs, including compression.17
¶ 10 Rejecting the lessee’s argument that compression used to “push” the gas into the purchaser’s pipeline is analogous to transportation and therefore deductible under Johnson, the opinion distinguished the facts in Wood from those in Johnson. In the latter case, the court held that the lessor must bear its share of transportation costs when the only possible point of sale is off the leased premises.18 When (as in Wood) the point of sale is on the leased premises, the court does not require the lessor to share in the transportation costs.19 In order to deduct compression costs from the royalty interest, the lessee must include in the lease a cost-apportionment clause.20
¶ 11 In Wood I was in dissent, preferring the Louisiana and Texas view that distinguishes production from post-production costs.21 Under the latter approach, the lessee is responsible for all costs of production *1213while post-production costs are shared proportionately by both parties.22 Production should be considered completed and royalty determined at the wellhead, the point at which the gas or oil is severed from the ground.23 If compression is necessary solely to deliver the gas from the wellhead into the purchaser’s pipeline, it is a post-production cost to be shared by both parties.24 On the other hand, if compression is necessary to 'produce the gas or to “lift” the gas up to the wellhead, then it is a cost of production which the lessee alone, should bear.25
¶ 12 My dissent noted that the Kansas and Arkansas royalty approach unduly saddles the lessee with the entire expense of gas compression, including post-production compression costs, as an unfair burden for failing to include a cost-apportionment clause in the lease.26 I took the position that we should not assign to one party the duty of including the critical provision and then freeing the other from responsibility.27
TXO v. State ex rel. Comm’rs of the Land Office
¶ 13 In CLO, the court held that compression, dehydration and gathering costs are not deductible from royalty interests but are the lessee’s responsibility as part of the implied duty to market. While concentrating on the language of the lease,28 the court expressly adopted the Wood test: cost de-ductibility turns on whether the process is necessary to prepare the product for market.29 If so, the lessee’s implied duty to market the gas requires him to bear the costs of these processes alone.
¶ 14 Applying this test, the court reasoned that without compression gas is completely unmarketable.30 Turning to dehydration costs, the court held that the removal of moisture from gas is another process necessary to make the product marketable.31 The opinion treated gathering — “the process of collecting gas at the point of production (the wellhead) and moving it to a collection point for further movement through a pipeline’s principal transmission system”32 — in the same manner. Since gathering costs are incurred before the gas enters the purchaser’s pipeline, the court deemed these costs to be necessary to obtain a marketable product.33 The lessee was held responsible for all of these costs as part of the implied duty to market oil and gas.
IY
OKLAHOMA’S ROYALTY CALCULATION METHOD IS FLAWED
¶ 15 Wood and CLO suffer from a common infirmity. Both correctly require the lessee to prepare the product for sale, but err in treating marketability as a question of law rather than one of fact.34 Absent any *1214factual inquiry into the actual market conditions relevant to the gas in question, the court arbitrarily declares certain costs as necessary to produce a marketable product. Sans factual inquiry, it is impossible to determine the very existence of a market.35 There may be actual arms-length equivalent sales of similar gas wherein the buyer, after purchase, will perform certain activities that, according to the court’s pronouncements in Wood and CLO, would fall upon the lessee as a matter of law. Treating marketability as a question of law ignores market realities.36
¶ 16 Oklahoma royalty jurisprudence allows the physical location of marketing activities to cloud the determination of cost deduc-tibility. The practice of requiring the lessee to pay for all on-site costs, which originated in Johnson,37 was expressly accepted in Wood.38 Even CLO, which seems to cast away the location-based analysis in favor of the more widely accepted marketability model, perpetuates the infirmity by citing with approval Wood’s compression cost analysis.39 There is no pre-Johnson authority for requiring the lessee to pay for all activities that take place on the leased premises. More importantly, it should make no difference to the lessor whether the lessee performs marketing functions at the well or at some other place. The Johnson location-based royalty analysis illogically regards the cost of transportation to off-site purchasers differently from all other marketing costs. I would (as today’s opinion appears to do) excise this arbitrary distinction from Oklahoma oil-and-gas jurisprudence.
¶ 17 After studying Professor Anderson’s research and noting recent case law evolving in other jurisdictions, I now realize that the alternative solution I proposed in Wood — the Texas and Louisiana'approach to royalty calculation — is equally flawed. Measuring the royalty payment at the wellhead is a property-based approach that requires the lessor to share costs once the extracted gas changes from real to personal property (i.e., the time of severance from the ground).40 As Professor Anderson notes in his detailed study of royalty law, history does not support a property-law interpretation of royalty clauses.41
*1215¶ 18 Extant body of United States jurisprudence demonstrates an absence of property-law type interpretation of royalty clauses, notwithstanding modern cases to the contrary.42 Courts have traditionally applied contract principles to interpret royalty obligations, concentrating on the language of the lease and the intent of the parties.43 Professor Anderson notes that case law has not allowed the lessor to receive cost-free transportation of the product to a distant point of sale.44 Under typical royalty clauses, the lessor should not receive royalty on the enhanced value of gas that was marketable in fact prior to its enhancement.45 We should follow this historically true model and refuse to apply property-law notions to determine royalty payments at the wellhead.
¶ 19 In addition to its historical inaccuracy, the wellhead-based royalty determination uses an unrealistic mathematical calculation to determine the royalty amount. Since there are often no sales at the wellhead46 to help determine wellhead market value, it becomes necessary to subtract all post-wellhead costs from the final selling price.47 The flaw in this “work-back” process is that it ignores the realities of the market.48 Market price is determined in the real world by both willing sellers and buyers working at arm’s length, not by a mathematician’s hypothetical calculations.49 The “work-back” view assumes that there is an eager buyer for every gallon of oil or gas that is pumped from the earth, no matter how unfit for use. In reality, the raw wellhead product may be completely unmarketable or of little value to buyers.50
¶20 The party in the best position to calculate costs and assign them to each stage of the marketing process is the lessee.51 When confronted by a court that employs a wellhead-based calculation in order to minimize royalty payments, the lessee can too easily shift profits downstream in the production process, pass costs upstream, or both.52 Skillful and self-serving accounting can skew the royalty calculation, minimizing the lessor’s share.
*1216y
OKLAHOMA SHOULD DETERMINE ROYALTY OBLIGATIONS BY USING THE FIRST-MARKETABLE PRODUCT MODEL
¶21 The question before us today provides the opportunity to re-analyze our approach toward oil and gas royalty clauses and the deductibility of transportation, compression, dehydration and blending costs from the royalty interest. Absent a lease provision to the contrary, the lessee should be solely responsible for producing a product marketable in fact. At this point “production” is complete, and any further costs should be shared proportionately by the lessor. In other words, the lessor should not receive any of the value added by the lessee’s post-production refining. In coming to this conclusion, I have found instructive the writings of both Owen L. Anderson and Eugene Kuntz.53 Professor Kuntz differentiates between production costs and processing costs:
“Unquestionably, under most leases, the lessee must bear all costs of production. There is, however, no reason to impose on the lessee the costs of refining or processing the product, unless an intention to do so is revealed by the lease. It is submitted that the acts which constitute production have not ceased until a marketable product has been obtained. After a marketable product has been obtained, then further costs in improving or transporting such product should be shared by the lessor and lessee if royalty gas is delivered in kind, or such costs should be taken into account in determining market value if royalty is paid in money.”54
Professor Anderson agrees with this approach:
“A court should begin its analysis of royalty clauses by recognizing three fundamental principles: First, a royalty clause should be construed in its entirety and against the party who offered it, and in light of the fact that the royalty clause is the means by which the lessor receives the primary consideration for a productive lease. Second, in light of legal history and absent an express lease provision, a lessee that discovers oil or gas in paying quantities is obliged to ‘produce’ a ‘marketable product’ so that the lessor can realize royalty income. Third, the point where a marketable product is first obtained is the logical point where the exploration and production segment of the oil and gas industry ends, is the point where the primary objective of the lease contract is achieved, and therefore is the logical point for the calculation of royalty.”55
¶22 While I believe the distinction between production and post-production marketing activities is the key to royalty analysis, I no longer accept the property-based notion that production is complete when the gas or oil is severed from the ground at the wellhead.56 Instead, I now embrace Professor Anderson’s view that production should be considered complete when a first-marketable product is obtained. The model I espouse conforms to the historical interpretation 57 of royalty clauses and does not suffer from the infirmities of past Oklahoma royalty jurisprudence.
¶ 23 We should not needlessly complicate royalty-clause interpretation by focusing solely on specific terms, such as “market value,” “market price,” “proceeds,” or “amount realized.”58 It is important to remember that oil and gas lease contracts are printed by the lessee on standard forms and are rarely negotiated.59 Rather than pick *1217apart the precise phraseology of each clause, we should examine the plain meaning of the entire contract.60 Royalty clauses may contain slightly different terminology, but most create similar obligations.61 All of these terms should be viewed as synonyms, and, in the absence of evidence demonstrating a contrary intent, the choice of “gross proceeds” over another phrase should not remove the royalty calculation from the point of first-marketability.62
¶ 24 The ■point at which a first-marketable product is obtained should be a question of fact. The exact nature of the market must be determined by the trier of fact to discover the point of production at which there are both willing sellers and buyers, and royalty should be determined by the market value of the product at that point, less any actual and reasonable deductions for transportation costs incurred in the event that the marketing point is not in the vicinity of the well.63
¶ 25 Today’s opinion relies heavily on two recent variations of the first-marketable product theory—Garman v. Conoco, Inc.64 and Sternberger v. Marathon Oil Co.65 In Garman the Colorado Supreme Court held that:
“absent an assignment provision to the contrary, overriding royalty interest owners are not obligated to bear any share of post-production expenses, such as compressing, transporting and processing, undertaken to transform raw gas produced at the surface into a marketable product.”66
Referring to Kuntz’s treatise, the court declared that any costs incurred to enhance the value of an already marketable gas are chargeable against royalty interests.67 The Supreme Court of Kansas adopted a somewhat similar approach to transportation costs in Stemberger:68
“We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo.1994). That case involves a certified federal question. In it, the Colorado Supreme Court held as we believe the law in Kansas to be: Once a marketable product is obtained, reasonable costs incurred to transport or enhance the value of the marketable gas may be charged against nonworking interest owners. The lessee has the burden of proving the reasonableness of the costs. Absent a contract providing to the contrary, a nonworking interest owner is not obligated to bear any share of production expense, such as compressing, transporting, and processing, undertaken to transform gas into a marketable product.”69
¶ 26 The court’s reliance on Garman and Stemberger is misplaced since neither represents a perfect incarnation of a true first-marketable product model. Garman diverges from that theory by requiring that the lessee show that post-production costs are reasonable and that they led to a proportionate increase in the lessor’s royalty revenues.70 Professor Anderson notes that this work-back calculation is unnecessary under the true or pure first-marketable product approach.71 Royalty will be paid on the price the lessee obtained or could have obtained for the sale of the first-marketable *1218form of the gas.72 The lessee has no obligation to pay royalty on any value that post-production activities add to the product.73 The lessee’s duty of good faith and fair dealing will apply to ensure that the first-market is “real, existing and substantial.”74 The Gorman barnacles (embraced by today’s pronouncement) — that the costs charged to the lessee be reasonable and lead to a proportionate increase in royalty revenue — are unnecessary. This is so because, under the Anderson model, the lessor does not share the revenues of a product that is enhanced beyond its first-marketability state.
¶27 Stemberger, which incorrectly requires the lessee to demonstrate the reasonableness of post-production costs, fails by treating marketability as a question of law rather than one of fact.75 The court today perpetuates this error by relying on Johnson, Wood and CLO to determine whether certain costs (as a matter of law) are necessary to make the product marketable. By its reliance on these three eases, the court adopts in effect a royalty evaluation model that is inferior to the first-marketable theory.
¶ 28 The Anderson first-marketable-product analysis — which recognizes that the point of marketability is necessarily a question of fact — is clearly superior to both the extant Oklahoma jurisprudence (Johnson, Wood, and CLO) and to the Gorman model. I would today adopt the concept of a factual inquiry into the point of first-marketability, which treats all post-production costs the same. My concept would eliminate the calculation of royalty on the value of gas after compression, dehydration or gathering, when the gas may have been marketable before undergoing some or all of these processes. The Anderson approach would implement the marketability-based royalty calculation model announced, but not actually applied, in Wood and CLO.
, ¶ 29 The wellhead-based royalty valuation also is supplanted by the first-marketable product model. While the foundation of both calculations is a produetion/post-production dichotomy, the first-marketable product model conforms to the historical practice of determining royalty obligations at the point of marketability. When using this model (except for a possible transportation adjustment),76 an artificial work-back royalty calculation becomes unnecessary. This is so because royalty will be paid on the actual market value of the first-marketable product. By basing royalty on real instead of hypothetical market values, the theory minimizes the lessee’s ability to influence the quantum of royalty payment through manipulative accounting.
VI
SUMMARY
¶ 30 Recent studies and case law have provided the necessary tools to repair the infirm underpinnings of Oklahoma’s royalty jurisprudence by creating a new approach that is both historically and logically sounder. The first-marketable product method eliminates location-based royalty analysis without disrupting Oklahoma’s implied duty to market oil and gas. Resting royalties on actual market value corrects the deficiencies in the wellhead-based calculation.
¶ 31 I would accordingly respond to the certifying court by stating that in Oklahoma the lessee is responsible for all marketing costs until a first-marketable product is obtained. Royalty would be paid on the actual market value of the gas at that point. Other than possible transportation adjustments in *1219the event that the first market is not in the vicinity of the well, there should be no need for inquiring into the reasonableness of post-production costs and no proportional-increase requirement. This is so because under the theory I espouse, the lessor would receive no value from the lessee’s post-production, (post-marketable) enhancement of the product.77
. Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994).
. For a discussion of Professor Anderson's model of first marketability, see Part V, infra.
. See Uniform Laws Annotated, Uniform Certification of Questions of Law Act/rule (1995); Goldschmidt, Certification of Questions of Law; Federalism in Practice, American Judicature Society (1994).
. See, e.g., Shebester v. Triple Crown Insurers, 974 F.2d 135, 137 (10th Cir.1992).
. Schmidt v. United States, 1996 OK 29, 912 P.2d 871, 873; Brown v. Ford, 1995 OK 101, 905 P.2d 223, 226; Bonner v. Okla. Rock Corp., 1993 OK 131, 863 P.2d 1176, 1178 n. 3; Shebester v. Triple Crown Insurers, 1992 OK 20, 826 P.2d 603, 606 n. 4.
. 1970 OK 180, 475 P.2d 396.
. 1992 OK 100, 854 P.2d 880.
. 1994 OK 131, 903 P.2d 259.
. Johnson, supra note 6 at 398-99.
. Id. at 399.
. Id.
. Wood, supra note 7 at 880.
. Id.
. Id. at 883.
. Id. at 881; see Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 134-35 (Tex.1996); Heritage Resources v. Nationsbank, 939 S.W.2d 118, 121—22 (Tex.1996); Merritt v. Southwestern Elec. Power Co., 499 So.2d 210 (La.Ct.App.1986).
. Wood, supra note 7 at 881 (the court expressly rejected any distinction between production and post production costs); see Gilmore v. Superior Oil Co., 192 Kan. 388, 388 P.2d 602, 606 (1964); Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964); Hanna Oil and Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563 (1988). Kansas has recently accepted the first-marketable product approach toward cost deductibility for most expenses. See part V infra; Sternberger v. Marathon Oil Co., 257 Kan. 315, 894 P.2d 788 (1995).
. Wood, supra note 7 at 883.
. Id. at 881; Johnson, supra note 6 at 399.
. Wood, supra note 7 at 881.
. Id. at 883.
. Id. at 887 (Opala J., dissenting). For the Louisiana and Texas approach, see Judice, supra note 15; Heritage Resources, supra note 15; Merritt, supra note 15; Martin v. Glass, 571 F.Supp. 1406, 1416 (N.D.Tex.1983) affirmed without opinion, 736 F.2d 1524 (5th Cir.1984); Parker v. TXO Prod. Corp., 716 S.W.2d 644 (Tex.Civ.App.1986).
. Wood, supra note 7 at 887 (Opala J., dissenting).
. Wood, supra note 7 at 884 (Opala J., dissenting).
. Id. at 885.
. Id.
. Id. at 883 (Opala J., dissenting). For the Kansas and Arkansas method, see Gilmore, supra note 16; Schupbach, supra note 16; Hanna Oil, supra note 16; Sternberger, supra note 16.
. Wood, supra note 7 at 883 (Opala J., dissenting).
. The court's rationale rests on principles of contract interpretation as well as on Wood and the implied duty to market. CLO, supra note 8 at 261.
. Id. at 262 (the court cites Wood for this notion).
.CLO, supra note 8 at 262.
. Id.
. Id. (the court cites the Manual of Oil and Gas Terms for this definition).
. Id. at 262-63.
. CLO, supra note 8 at 262-63; Wood, supra note 7 at 882. See generally Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically?, Part 2 (Should Courts Contemplate the Forest or Dissect Each Tree?) - Nat. Resources J. -, discussion in text at notes 225-235 (draft manuscript on file at the University of New Mexico School of Law). An earlier version of this manuscript is cited in Laura H. Burney, The Interaction of the Division Order and the Lease Royalty Clause, 28 St. Mary’s L.J. 353, 395 n. 193.
. Anderson, supra note 34, Part 2, discussion in text at note 235.
. Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269, 1273-74.
. Johnson, supra note 6 at 399 (the court requires the parties to share only costs incurred "beyond the lease property").
. Wood, supra note 7 at 881.
. CLO, supra note 8 at 262.
. Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically?, Part 1 (Why All The Fuss? What Does History Reveal? ) -Nat. Resources J.-, discussion in text at notes 111-115 (draft manuscript on file at the University of New Mexico School of Law).
. During the mining law's origin in ISth-centu1 ry England, the miner had to dress and wash the ore before sending a royalty to the King. Anderson, supra note 40, Part 1, discussion in text at notes 132-133 (referring to Nellie Kirk-ham, Derbyshire Lead Mining Through The Centuries 32-42 (1968)). While the "washed ore" was not the final product, it was marketable. This was evidenced by the custom of selling washed ore to a smelter/buyer. The common practice in 19th-centuiy England was not to turn over to the King ore in its raw form but to deliver in-kind royalty of metal in a "manufactured state.” Id., Part 1, discussion in text at note 136 (referring to 1 John A. Rockwell, A Compilation of Spanish and Mexican Law, in Relation to Mines, and Titles to Real Estate, in Force in California, Texas and New Mexico; and in the Territories Acquired Under the Louisiana amd Florida Treaties, When Annexed to the United States 558-59 (1851)). Both the custom and law of England was not to calculate royalty at the time of severance but to require payment upon attainment of a marketable good. Id., Part 1, discussion in text after note 136.
Other cultures provide a similar property-free determination of royalty share. Ancient Greek royalty owners were paid in pure silver rather than in the ore discovered by the miners. Anderson, supra note 40, Part 1, discussion at notes 118-120 (noting T.A. Rickard, Man and Metals, a History of Mining In Relation To The Development Of Civilization (1932)). In Rome a royally owner received cut marble instead of the unfinished, unmarketable stone recovered from the earth. Id., Part 1, discussion in text at notes 121-122 (quoting Clyde Pharr, The Theodosian Code And Novels And The Sirmondian Constitutions, Book X, Title 19 (1952)). A net-proceeds approach to royalty calculation was standard practice in early Spanish law. Id., Part 1, discussion in text at notes 123-126. The tradition of Western jurisprudence weighs against the use of a property-based royalty calculation.
. Support for marketability rather than property as the basis for royalty valuation can be found in Clark v. Slick Oil Co., 88 Okl. 55, 211 P. 496 (1922). For a thorough analysis of older royalty cases in other jurisdictions, see Anderson, supra note 40, Part 1, discussion in text at notes 137-248. For a review of modern royalty cases, see Anderson, supra note 34, Part 2, discussion in text at notes 1-89, 140-296.
. Anderson, supra note 40, Part 1, discussion in text at notes 135-242. CLO and Johnson both demonstrate the importance of language and intent to royalty clause interpretation. CLO, supra note 8 at 260-61; Johnson, supra note 6 at 399.
. Anderson, supra note 34, Part 2, discussion in text at notes 145-146.
. Anderson, supra note 34, Part 2, discussion in text at notes 305-306. Disallowing deductions allows the lessor to receive all the benefits of the lessee’s refining and marketing activities without any extra compensation for the lessee.
. Some courts determine market value by examining sales at other nearby wells ("comparable sales”) if there are any. Exxon Corp. v. Middleton, 613 S.W.2d 240, 245-46 (Tex.1981). Under this approach, if comparable wellhead sales exist, then the gas in question would be marketable in fact.
. Marla J. Williams et at, Determining the lessor’s Royalty Share of Post-Production Costs: Is the Implied Covenant to Market the Appropriate Analytical Framework?, 41 Rocky Mtn. Min. L. Inst. § 12.02[2] (1995).
. Anderson, supra note 34, Part 2, discussion in text at note 295.
. See Black’s Law Dictionary 876 (5th ed.1981); Anderson, supra note 34, Part 2, discussion in text at notes 115-119. For a discussion of the problems encountered under a “work-back” approach, see generally Owen L. Anderson, Calculating Royalty: “Costs” Subsequent to Production — "Figures Don’t Lie, But....”, 33 Washburn L.J. 591 (1994).
. See, e.g., Professor Anderson’s discussion of Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225 (5th Cir.1984), cert. den. 471 U.S. 1005, 105 S.Ct. 1868, 85 L.Ed.2d 161 (1985), aff'd in part, rev'd in part on other grounds, after remand, 905 F.2d 840 (5th Cir.1990), supra note 49 at 612-613 and supra note 34, Part 2, discussion in text at note 78.
. Anderson, supra note 49 at 603.
. Anderson, supra note 40, Part 1, discussion in text after note 59.
. See 3 Eugene Kuntz, Law of Oil and Gas § 40.5 at 351 (1989); Owen L. Anderson, Wood v. TXO Production Corp., Discussion Notes, 125 Oil and Gas Reporter, Report No. 1 (12-95), at 155-161; Anderson, supra notes 34, 40 and 49.
. Kuntz, supra note 53, § 40.5 at 351 (1989) (emphasis supplied). See also West v. Alpar Resources, Inc., 298 N.W.2d 484, 489 (N.D.1980), in which the court observes that most oil and gas scholars agree the lessor should pay a share of post-production costs, but disagree as to the point at which "production” is complete.
. Anderson, supra note 34, Part 2, discussion in text at notes 110-112 (emphasis supplied, footnotes omitted).
. Wood, supra note 7 at 83 (Opala J., dissenting).
. See discussion in supra note 41.
. Anderson, supra note 34, Part 2, discussion in text at notes 12-13. See also Tara Petroleum, supra note 36 at 1272.
. See generally Maurice Merrill, Covenants Implied in Oil and Gas Leases § 85 (2d ed.1940). *1217Given the large number of small interest-owning lessors, any suggestion that negotiation commonly occurs is absurd.
. Anderson, supra note 34, Part 2, discussion in text after note 4 and in text at Section 3, conclusion, prior to note 305.
. Id., Part 2, discussion in text after note 4.
. Id., Part 2, discussion in text at notes 113— 123, 254-274.
. Professor Anderson does note that long-established case law has allowed the lessee to charge the lessor for a proportionate share of reasonable and actual transportation costs where the marketing point is not in the vicinity of the well. Anderson, supra note 34, Part 2, discussion in text at notes 145-146.
. Garman, supra note 1.
. Sternberger, supra note 16.
. Id. at 661 (emphasis added).
. Id.
. Sternberger, supra note 16.
. Id. at 800 (emphasis supplied). Stemberger is particularly significant because, in Wood, Oklahoma expressly accepted Kansas royalty jurisprudence. Wood, supra note 7 at 881.
. Id.
. Anderson, supra note 34, Part 2, discussion in text at note 262.
. Id.., Part 2, discussion in text at note 306.
. Anderson, supra note 40, Part 1, discussion in text at notes 5-8. Allowing the lessor to profit from the lessee's downstream enhancements would complicate the royalty calculation. While some lessees sell the gas without making many improvements, other lessees are vertically integrated, making several enhancements before selling the final product. If lessees must share downstream earnings, lessors in the latter situation would reap large profits while those in the former relationship would only receive royalty on the sale to the next middleman in the marketing process. Anderson, supra note 34, Part 2, discussion in text at notes 314 — 319.
. Anderson, supra note 34, Part 2, discussion in text at note 311.
. Stemberger, supra note 16.
.See supra note 63.
. It is interesting to note that nothing in the court’s opinion appears to prohibit a lessee from paying royalty on a known first-market value. As I understand today’s pronouncement, it merely limits the lessee's right to use a work-back valuation method.