
    1998 OK 7
    Ted MITTELSTAEDT, an individual, Ruth Mittelstaedt, an individual, Plaintiffs-Appellees, v. SANTA FE MINERALS, INC., a corporation, Defendant-Appellant.
    No. 84977.
    Supreme Court of Oklahoma.
    Jan. 20, 1998.
    Dissenting Opinion by Justice Opala Modified March 5, 1998.
    
      Gregory A. McKenzie, William K. Elias, Michael J. Massad, and Frank H. McGregor of McKenzie, Moffett, Elias & Books, Oklahoma City, for Plaintíffs-Appellees.
    Gary W. Davis, Mark D. Christiansen, and Paul D. Trimble of Crowe & Dunlevy, Oklahoma City, and William H. Boyles, Santa Fe Minerals, Inc., Dallas, TX, for Defendant-Appellant.
    Robin Stead, Donald F. Heath, Jr., Heath, P.C., for Amicus Curiae National Association of Royalty Owners, Norman, Oklahoma.
    Brenton B. Moore, Oklahoma Mid-Continent Oil & Gas Association, James C.T. Hardwick of Hall, E still, Hardwick, Gable, Golden & Nelson, P.C., Tulsa, Joseph W. Morris, Teresa B. Adwan, M. Benjamin Sin-gletary of Gable & Gotwals, Inc., for Amicus Curiae for Oklahoma Mid-Continent Oil and Gas Association, Tulsa, Oklahoma.
    
      
      . Typical gas royalty clause types are "market value," "proceeds” ("gross” and "net"), and "in kind” clauses. Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269, 1272 n. 3.
    
    
      
      . In Home-Stake the producer claimed an ad valorem tax exemption for a six-mile pipeline from a well to a trunk line claiming such was necessary for the production of gas from the well because production had not occurred until the gas was marketed. The court rejected this claim, and observed that absent a specific lease provision "marketing of oil or gas is not required in order to satisfy the habendum clause of a lease requiring production within one year, or as long thereafter as either is produced.” Id. 463 P.2d at 985. A similar, although not identical, argument was raised in Union Oil Co. v. Board of Equalization, 1996 OK 40, 913 P.2d 1330, where the taxpayer claimed that equipment at the wellhead was exempt from ad valorem taxation as necessary for production if the equipment was necessary to fulfill the implied covenant to make the product marketable. Id. 913 P.2d at 1334 n. 2. Resolution of the claim was unnecessary, and the Court did not address whether the claim was correct. Id.
      
    
   SUMMERS, Vice Chief Justice.

¶ 1 Gas well lessors filed suit in Federal Court, claiming they were not getting the full “3/16 of the gross proceeds received for the gas sold” as called for in-the lease. Lessee in response explained it was deducting the lessor’s share of post-production expenses in marketing the gas, and then remitting 3/16 of the proceeds as royalty. The trial court entered judgment in favor of the lessors for their portion of the proceeds deducted and withheld by the lessee, plus interest. The ■ ease is now in the Tenth Circuit Court of Appeals. Since the case will turn on Oklahoma law the Circuit Court has certified the question to us, framed as follows:

In light of the facts as detailed below, 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?

¶ 2 We conclude that this clause, when considered by itself, prohibits a lessee from deducting a proportionate share of transportation, compression, dehydration, and blending costs when such costs are associated with creating a marketable product. However, we conclude that the lessor must bear a proportionate share of such costs if the lessee can show (1) that the costs enhanced the value of an already marketable product, (2) that such costs are reasonable, and (3) that actual royalty revenues increased in proportion with the costs assessed against the nonworking interest. Thus, in some cases a royalty interest may be burdened with post-production costs, and in other cases it may not.

¶ 3 The two wells are in Canadian County. Some compression operations and associated expenses were performed at the wellhead. Lessee Santa Fe Minerals, Inc. did not charge the royalty interests with these costs. But then the gas was moved downstream to a location off the leased premises, where Santa Fe paid unaffiliated third parties for transportation fees, blending fees, dehydration fees, and compression fees. Santa Fe charged a proportion of these costs against the royalty interests. The gas was then moved further downstream where it was placed into the purchaser’s pipeline. The Mittlestaedts went to court to recover that portion of the latter costs charged against their royalty as lessors. The trial court, in one of its rulings, recognized as an undisputed fact that the expenses in controversy incurred by Santa Fe “were incurred for the purpose of improving the quality of the gas produced from the wells involved, thereby resulting in a higher price being received from the purchaser and to permit sale at better, higher-priced markets.”

¶4 Our assignment requires us, at the outset, to analyze these Oklahoma eases: Wood v. TXO Production Corp., 1992 OK 100, 854 P.2d 880, TXO Production Corp. v. State ex rel. Commissioners of the Land Office, 1994 OK 131, 903 P.2d 259, (because Wood and this second case both involve TXO we will refer to it as CLO), and Johnson v. Jernigan, 475 P.2d 396 (Okla.1970).

¶ 5 In Wood we rejected the idea that compression costs to “enhance” (or make marketable) a product should be shared by the royalty interest. Wood, 854 P.2d at 881. However, we also said in Wood that “in Oklahoma the lessee’s duty to market involves obtaining a marketable product.” In our case the royalty owners rely upon the first above quote. The lessee relies upon the latter, arguing that its duty is fulfilled by delivering a marketable product at the leased premises, and that costs incurred after the this duty is fulfilled may be allocated proportionately to the royalty interest. It is noteworthy that in Wood the compression took place on the leased premises.

¶ 6 In CLO the lessee wanted to charge .compression and dehydration costs to the lessors. Our Court said no, these operations were required to make the gas marketable, as required by the Lessees’s implied covenant to market. The enhancement operations in CLO, as in Wood, took place at the wellhead, on the leased premises.

¶ 7 In Johnson v. Jernigan, the lessee wanted to charge the lessor its proportionate share of transportation costs to the nearest market. We allowed that to happen because there was no market available for the gas at the lease. The lessee’s duty to market did not include bearing the full burden of delivery to an off-site purchaser.

¶ 8 In all these opinions the Court had to fix the rights and duties of the parties according to the language of the leases and the implied covenants that go with them. The clause immediately preceding the “gross proceeds” clause in our case is an in kind clause requiring the lessee “To deliver to the credit of lessor free of cost, in the pipe line to which it may connect its wells, the 3/16 part of all oil. In CLO we stated that the lease phrase “without cost into pipelines” modifying an “in kind” clause also referred to lessee’s 1/8 payment of the market value of the gas sold to the lessor. Id. 903 P.2d at 261. We then concluded that the 1/8 market value paid to the lessor did not bear any of the lessee’s costs from processes necessary to get the product into the pipelines. Id. Unlike the present case, in CLO delivery to the purchaser’s pipeline occurred at the leased premises.

¶ 9 In CLO we examined the language of the lease. Id. 903 P.2d at 260-261. We use the plain meaning of the terms when doing so. Trawick v. Castleberry, 275 P.2d 292, 294 (Okla.1953). Using the plain meaning of the phrase “gross proceeds” suggests that the payment to the lessor is without deductions. See Pioneer Telephone Co-op. Inc. v. Oklahoma Tax Commission, 1992 OK 77, 832 P.2d 848, where we defined “gross receipts” for the purpose of sales taxes and used its plain meaning. This view of gross receipts has also been used when interpreting a royalty clause: “The term ‘gross proceeds’ usually implies no deductions of any kind.” Altman and Lindberg, Oil and Gas: Non-Operating Oil and Gas Interests’ Liability for Post-Production Costs and Expenses, 25 Okla.Law Rev. 363, 375 (1972), [citing, Brown, Royalty Clauses in Oil and Gas Leases, 16 Oil & Gas Inst. 161 (SW. Legal Found.1965) ]. Consistent with this approach, we have explained that when the lease requires payment of the “market value” of the gas this value “means the gas purchase contract price.” Helmerich & Payne, Inc. v. State ex rel. Commissioners of the Land Office, 1997 OK 30, ¶ 12, 935 P.2d 1179, 1181. But when certain circumstances are present this definition of “gross receipts,” as being a value with no deductions, has been tied to the value of the product at a certain location, that is, the leased premises, or wellhead.

¶ 10 In Johnson v. Jernigan, 475 P.2d 396 (Okla.1970) we explained that gross proceeds “has 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. 475 P.2d at 399. Thus, “gross proceeds” does indicate an amount without deduction from, or charge against, the royalty interest, but only when the point of sale occurs at the leased premises.

¶ 11 The third clause discussed by the parties provides that the lessee will “pay lessor for gas produced from any oil well and used off the premises, or for the manufacture of casing-head gasoline or dry commercial gas, 3/16 of the gross proceeds, at the mouth of the well, received by lessee for the gas-” A producer has a duty to market gas from a producing well. Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269, 1273. The parties argue whether this clause means that the lessee’s duty to market is measured by the performance of the lessee at the wellhead. This contention requires discussion of a lessee’s implied covenant to market.

¶ 12 In CLO we first analyzed the lessee’s duties as specified by the lease. After we concluded that the lessor did not pay certain post-production costs because of the language of the lease, we then explained that the result in that case was consistent with our opinion in Wood, discussing a lessee’s implied covenant to market gas. Id. 903 P.2d at 261. We said that the lessee must make the gas available to market at the leased premises (wellhead). Making the gas available to market at the leased premises means that the lessee must produce the gas in a marketable form at the leased premises. Thus, when discussing a lessee’s duty to provide a marketable product at the leased premises we said that “the implied duty to market means a duty to get the product to the place of sale in marketable form. Here [in both Wood and CLO] the compressors ... are on the leased premises.” (quoting Wood, emphasis deleted) Id. 903 P.2d at 262.

¶ 13 The Mittelstaedts argue that when the sale is at a distant market the implied duty of the lessee under the lease is to pay for all of those costs associated with delivering the gas at the point of sale, i.e., to get the product to the place of sale in marketable form at the expense of the lessee. This view is incorrect as to distant markets. We explained in CLO that our ruling in Johnson v. Jernigan, 475 P.2d 396 (Okla.1970) was still good, and that a lessor may be required to pay its proportionate share of transportation costs when the sale occurs off the léase premises. See CLO at 262, 263 n. 2. In Johnson there was no market fbr the product at the leased premises. Johnson allows allocating transportation costs to lessors when the point of sale is away from the lease only when no market for the product is available at the lease. When there is a market available at the wellhead transportation costs to a point of sale at a distant market should not be allocated against the lessors’ interest except in those circumstances that we will later explain.

¶ 14 In Wood we explained that nonworking interest owners (royalty owners) have no input into the cost-bearing decisions. 854 P.2d at 883. These owners have no input on the marketing decisions. If costs were imposed on royalty owners they “would be sharing the burdens of working interest ownership without the attendant rights.” Id. We then said that if a lessee wants royalty owners to share in the post-production costs then that must be stated in the lease. Id.

¶ 15 The Supreme Court of Colorado, reviewed our decision in Wood and came to similar conclusions.

Allocating these costs to the lessee is also traceable to the basic difference between cost bearing interests and royalty and overriding royalty interest owners. Normally, paying parties have the right to discuss proposed procedures and expenditures and ultimately have the right to disagree with the course of conduct selected by the operator. Under the terms of a standard operating agreement nonoperat-ing working interest owners have the right to go “non-consent” on an operation and be subject to an agreed upon penalty. See A.A.P.L. Form 610-1989 Model Form Operating Agreement Art. Vl.b.ii. This right cheeks an operator’s unbridled ability to incur costs without full consideration of their economic effect. No such right exists for nonworking interest owners.

Garman v. Conoco, Inc., 886 P.2d 652, 660 (Colo.1994).

Colorado concluded that no costs were alloca-ble to the nonworking interests when the costs were to create a marketable product. Id. But the court then concluded that when additional costs were incurred to increase the value of the gas already marketable those costs could be allocated to the noninterest owners under certain conditions:

To the extent that certain processing costs enhance the value of an already marketable product the burden should be placed upon the lessee to show such costs are reasonable, and that actual royalty revenues increase in proportion with the costs assessed against the nonworking interest.

Id. 886 P.2d at 661.

¶ 16 The Supreme Court of Kansas then agreed with this as an accurate statement of the law in Kansas as to transportation costs. Sternberger v. Marathon Oil Company, 257 Kan. 315, 894 P.2d 788 (1995). It said that:

We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo.1994). That ease 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. In the case before us, the gas is marketable at the well. The problem is there is no market at the well, and in that instance we hold the lessor must bear a proportionate share of the reasonable cost of transporting the marketable gas to its point of sale.

Sternberger, 894 P.2d at 800.

Kansas’ reasoning is consistent with our holding in Johnson v. Jernigan, supra. The Kansas Court then reviewed our decisions in Wood and CLO, and explained that Wood was consistent with Kansas law and that CLO involved a lease provision and facts that distinguished it from Stemberger. Sternberger, 894 P.2d at 801-804. The agreement on this issue between Kansas and Colorado as to the lessee’s burden is also noteworthy because of what we said in Wood.

¶ 17 In Wood we explained that Oklahoma’s rule for nonallocation of costs in creating a marketable product was similar, although not identical, to that in Kansas. Wood, 854 P.2d at 881. We stated in Wood that we followed the approach used by the courts in Kansas and Arkansas. Wood, 886 P.2d at 882. This was discussed by the Colorado Supreme Court in Garman. Garman, 886 P.2d at 658.

¶ 18 Thus, we agree with both Stemberger and Garman. When the gas is shown by the lessee to be in a marketable form at the well the royalty owner may be charged a proportionate expense of transporting that gas to the point of purchase. Johnson v. Jernigan, supra. The lessee bears the burden of showing that such cost is reasonable, and that actual royalty revenues increased in proportion with the costs assessed against the nonworking interest. Garman v. Conoco, Inc., supra. Thus, in this controversy whether the royalty interest must bear transportation costs away from the lease will depend upon whether the lessee can meet its burden.

¶ 19 In both Wood and CLO we were concerned with operations on the leased premises to make the product marketable. However, this does not mean that costs incurred after severance at the wellhead are necessarily shared by the lessors. We expressly rejected this approach in Wood. See Wood, 854 P.2d at 882. Post-production costs must be examined on an individual basis to determine if they are within the class of costs shared by a royalty interest.

¶ 20 The lessee has a duty to provide a marketable product available to market at the wellhead or leased premises. Generally, custom and usage in the industry are used in determining the scope of duties created by the lease. Heiman v. Atlantic Richfield Co., 1995 OK 19, n. 4, 891 P.2d 1252, 1257 n. 4; Matzen v. Hugoton Production Co., 182 Kan. 456, 321 P.2d 576, 582 (1958). Neither the facts given us nor the legal arguments on the certified question identify custom and usage with respect to the individual costs at issue when the leases were executed.

¶ 21 It is common knowledge that raw or unprocessed gas usually undergoes certain field processes necessary to create a marketable product. These field activities may include, but are not limited to, separation, dehydration, compression, and treatment to remove impurities. See Exxon Corporation v. United States, 33 Fed.Cl. 250, 271 (1995) where the producer discussed the “normal field production activities” to determine the representative market or field price for calculating the gross income from the property for the purpose of a percentage depletion deduction for federal income taxes.

¶ 22 In CLO we stated that “the costs for compression, dehydration and gathering are not chargeable to Commissioners [lessors] because such processes are necessary to make the product marketable under the implied covenant to market.” CLO, 903 P.2d at 263. We said:

According to TXO’s brief in chief, dehydration “involves removal of moisture from gas before it enter’s the purchaser’s pipeline.” Such a process is necessary in order to make the product marketable and involve costs incident to delivering the product into pipelines. As such, costs of dehydration are not chargeable against Commissioners under Wood.

CLO, 903 P.2d at 262.

In Exxon the federal court reached the conclusion that dehydration was a nonproducing rather than producing function for the purpose of the depreciation allowance calculation. However, the Exxon court was well aware that its conclusion was not necessarily the same for calculating royalties.

¶ 23 This Court too, has observed that a term used for the purpose of calculating a tax may have a different meaning in calculating a royalty. See Oklahoma Tax Commission v. Sun Oil Company, 489 P.2d 1078, 1081 (Okla.1971) where this Court relied upon In re Home-Stake Production Co., 463 P.2d 983 (Okla.1969) in explaining that the value of gas for the purpose of the gross production tax was not necessarily calculated in the same manner as its value for the purpose of paying royalties. Additionally, one term may not have a uniform definition throughout the industry, and custom and usage may vary. See Mason v. Ladd Petroleum Corp., 1981 OK 73, 630 P.2d 1283, 1285, where we noted a diversity in accepted accounting practices, leading to opposite results. The parties have not shown that the actual costs at issue are, or are not, treated by the industry as production costs or post-production costs for our purpose.

¶24 In CLO when discussing gathering we stated that gathering occurs prior to the product being placed into the purchaser’s pipeline, and “As such, gathering is not a deductible expense.” CLO, 903 P.2d at 262-263. It is argued from this quote that every cost, of whatever nature, incurred prior to delivery to purchaser is a cost that cannot be allocated to a royalty interest governed by a gross proceeds clause. We are invited to overrule Johnson v. Jemigan, supra, as inconsistent with CLO.

¶ 25 We stated in CLO that in Oklahoma gathering is a cost of production, i.e., to make a marketable product, and is not a cost allocated to a royalty interest, but our discussion included a reaffirmation of Johnson v. Jernigan, supra. CLO, 903 P.2d at 263. Our conclusion that dehydration was a non-allocated cost rested upon similar grounds. Id. 903 P.2d at 262.

¶26 Generally, costs have been construed as either production costs which are never allocated, or post-production costs, which may or may not be allocated, based upon the nature of the cost as it relates to the duties of the lessee created by the express language of the lease, the implied covenants, and custom and usage in the industry. We conclude that' dehydration costs necessary to make a product marketable, or dehydration within the custom and usage of the lessee’s duty to create a marketable product, without provision for cost to lessors in the lease, are expenses not paid from the royalty interest. However, excess dehydration to an already marketable product is to be allocated proportionately to the royalty interest when such costs are reasonable, and when actual royalty revenues are increased in proportion to the costs assessed against the royalty interest. It is the lessee’s .burden to show that the excess dehydration costs charged against the royalty interest occurred to a marketable product, i.e., that the cost is a post-production cost. It is also the burden of the lessee to show both the reasonableness of the costs and that the royalty revenues increased in proportion with the costs assessed against the royalty interest.

¶ 27 The certified question asks us to determine whether blending costs are a post-production expense. The exact nature of the “blending” is not identified. The analysis for blending costs is the same as for dehydration costs. Blending costs necessary to make a marketable product are not costs allocated to the royalty interest. Blending costs to an already marketable product are to be allocated proportionately to the royalty interest when such costs are reasonable, and when actual royalty revenues increase in proportion to the costs assessed against the royalty interest. The lessee has the burden of showing the reasonableness of the cost, the proportional increase in revenues to the royalty interest, and that the cost was incurred to alter a marketable product. The lessee must show that the cost was a post-production cost.

¶28 In Wood one issue was whether a lessor’s interest must bear a proportionate share of compression expenses when the compression was necessary to provide a marketable product because of low pressure. We expressly declined to make compression costs a form of transportation cost that may be charged against the royalty interest. Wood, 854 P.2d at 881-882. This holding is consistent with Kansas, where compression costs both on and off the lease necessary to place the gas into the purchaser’s pipeline are not costs allocated to the royalty interest. See Sternberger, 894 P.2d at 798, explaining, Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964). However, in Wood we noted that there was no sale at a distant market, and no necessity to transport the product.

¶ 29 Clearly, compression on the leased premises to push marketable gas into the purchaser’s pipeline is a cost not allocated to the royalty interest. Wood, supra. We decline to turn compression costs into costs paid by the royalty interest merely by moving the location of the' compression off the lease. However, we recognize that when marketable gas is transported off the lease to a point where its constituents are changed, additional compression may then become necessary to push the changed product into a purchaser’s pipeline. We conclude that off-lease compression costs may be allocated to the royalty interests if such costs are reasonable, when actual royalty revenues increase in proportion to the costs assessed against the nonworking interest, and when the compression is associated with enhancing an already marketable product off the lease. The lessee bears the burden of showing the reasonableness of the cost and the increase in royalty revenues resulting from the compression costs.

¶ 30 In sum, a royalty interest may bear post-production costs of transporting, blending, compression, and dehydration, when the costs are reasonable, when actual royalty revenues increase in proportion to the costs assessed against the royalty interest, when the costs are associated with transforming an already marketable product into an enhanced product, and when the lessee meets its burden of showing these facts.

¶ 31 CERTIFIED QUESTION ANSWERED.

¶ 32 KAUGER, C.J, SUMMERS, V.C.J., and HODGES, LAVENDER and HARGRAVE, JJ., concur.

¶ 33 SIMMS and ALMA WILSON, JJ., concur in part and dissent in part.

¶ 34 OP ALA and WATT, JJ., dissent in part.

OPALA, Justice,

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 Garman 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) custom 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, 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. 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. 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. 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]; Wood v. TXO Prod. Corp. [Wood]; and TXO v. State ex rel. Comm’rs of the Land Office [CLO].

Johnson v. Jernigan

¶ 7 In Johnson, gas lessors alleged that the lessees wrongfully deducted transportation costs from their l/8th royalty interest in the “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. 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. 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.

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. The lessee then subtracted from the royalty payments the lessors’ proportionate share of the compression costs. The lessors sought to recover these costs. The court held that, absent an agreement between the parties to share compression costs, the lessee must bear the entire expense of gas compression.

¶ 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, the court preferred the Kansas and Arkansas approach that prohibits such deductions. 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.

¶ 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. 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. In order to deduct compression costs from the royalty interest, the lessee must include in the lease a cost-apportionment clause.

¶ 11 In Wood I was in dissent, preferring the Louisiana and Texas view that distinguishes production from post-production costs. Under the latter approach, the lessee is responsible for all costs of production while post-production costs are shared proportionately by both parties. Production should be considered completed and royalty determined at the wellhead, the point at which the gas or oil is severed from the ground. 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. 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.

¶ 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. 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.

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, the court expressly adopted the Wood test: cost de-ductibility turns on whether the process is necessary to prepare the product for market. 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. Turning to dehydration costs, the court held that the removal of moisture from gas is another process necessary to make the product marketable. 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” — 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. 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. Absent any factual 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. 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.

¶ 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, was expressly accepted in Wood. 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. 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). As Professor Anderson notes in his detailed study of royalty law, history does not support a property-law interpretation of royalty clauses.

¶ 18 Extant body of United States jurisprudence demonstrates an absence of property-law type interpretation of royalty clauses, notwithstanding modern cases to the contrary. Courts have traditionally applied contract principles to interpret royalty obligations, concentrating on the language of the lease and the intent of the parties. 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. 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. 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 wellhead to help determine wellhead market value, it becomes necessary to subtract all post-wellhead costs from the final selling price. The flaw in this “work-back” process is that it ignores the realities of the market. 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. 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.

¶20 The party in the best position to calculate costs and assign them to each stage of the marketing process is the lessee. 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. Skillful and self-serving accounting can skew the royalty calculation, minimizing the lessor’s share.

y

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. 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.”

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.”

¶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. 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 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.” It is important to remember that oil and gas lease contracts are printed by the lessee on standard forms and are rarely negotiated. Rather than pick apart the precise phraseology of each clause, we should examine the plain meaning of the entire contract. Royalty clauses may contain slightly different terminology, but most create similar obligations. 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.

¶ 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.

¶ 25 Today’s opinion relies heavily on two recent variations of the first-marketable product theory—Garman v. Conoco, Inc. and Sternberger v. Marathon Oil Co. 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.”

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. The Supreme Court of Kansas adopted a somewhat similar approach to transportation costs in Stemberger:

“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.”

¶ 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. Professor Anderson notes that this work-back calculation is unnecessary under the true or pure first-marketable product approach. 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. The lessee has no obligation to pay royalty on any value that post-production activities add to the product. The lessee’s duty of good faith and fair dealing will apply to ensure that the first-market is “real, existing and substantial.” 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. 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), 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 the 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. 
      
      . A royalty is an agreed return paid for the oil, gas, and minerals, or either of them, reduced to possession and taken from the leased premises. A royalty is a share of the product or proceeds therefrom, reserved to the owner for permitting another to use the property. Elliott v. Berry, 206 Okla. 594, 245 P.2d 726, 729 (1952).
     
      
      . It is undisputed that the third parties receiving the fees are unrelated or unaffiliated to Santa Fe. We do not address the effect of lessee-affiliated gas marketers attempting to capture the costs of marketing. See A. Wright & C. Sharpe, Direct Gas Sales: Royalty Problems for the Producer, 46 Okla.L.Rev. 235 (1993).
     
      
      . The conclusion in Exxon, 33 Fed.Cl. at 275-276, relied upon the opinion in Hugoton Production Company v. United States, 161 Ct.Cl. 274, 315 F.2d 868 (Ct.Cl.1963). In Hugoton the producer claimed that its central dehydration plant was a producing (as opposed to nonproducing) function. Id. 315 F.2d at 892. The I.R.S. determined that the dehydration plant was a nonpro-ducing function. Id. The Kansas producer calculated gross income from the properly for tax purposes and royalties using the same method. Id. 315 F.2d at 870 n. 12.
     
      
      . 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). Given 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.
     