
    (306 P.3d 318)
    No. 108,666
    L. Ruth Fawcett, Appellee, v. Oil Producers, Inc. of Kansas, Appellant.
    
    Opinion filed July 19, 2013.
    
      Robert W. Coykendall and Will B. Wohlford, of Morris, Laing, Evans, Brock & Kennedy, Chtd., of Wichita, and Julia Gilmore Gaughan, of the same firm, of Topeka, for appellant.
    
      Rex A. Sharp and Barbara C. Prankland, of Gunderson, Sharp & Wallce L.L.P., of Prairie Village, and David E. Sharp, of the same firm, of Houston, Texas, for appellee.
    
      David W. Nickel, of DePew Gillen Rathbun & Mclnteer, LC, of Wichita, for amicus curiae Kansas Independent Oil and Gas Association.
    Before Atcheson, P.J., Green and McAnany, JJ.
   Green, J.:

This interlocutory appeal under K.S.A. 60-2102(c) involves a class action brought by a royalty owner in Seward County, Kansas, on behalf of all royalty owners who were paid royalties from Oil Producers, Inc. of Kansas (OPIK), which owned the working interest or which operated Kansas wells from January 1, 1996, to the present. The plaintiff, L. Ruth Fawcett Trust, with Les Spaulding as the Trustee (Fawcett) claimed that OPIK had underpaid royalties, and sought recoveiy of the underpayments. Namely, plaintiff contended that the stipulated price adjustments contained in the gas purchase agreements between OPIK and certain gas purchasers were actually deductions of expenses that OPIK was not allowed to deduct from plaintiff s royalty share. Both parties moved for summary judgment. OPIK argued that it had complied with the express requirement of the leases to pay royalties based on actual proceeds of sales of gas that it had sold at the well. Moreover, OPIK maintained “that it would require a gross adulteration of the gas sales contracts to interpret the price adjustments to be improper ‘expense’ deductions.”

The trial court granted partial summary judgment in favor of the plaintiff. On appeal, OPIK contends that the trial court erred when it held that OPIK impermissibly calculated the plaintiff s royalty payments on the net proceeds OPIK received from certain gas purchasers instead of calculating plaintiff s royalty payments on the gross proceeds of the gas purchase contracts. We disagree. Accordingly, we affirm.

There are 25 oil and gas leases at issue in this case. Each of the oil and gas leases contain the same or similar language giving the lessor (royalty owner) either a one-eighth or three-sixteenths share of the gas produced and sold at the mouth of tire well. Two examples of the specific lease language are as follows:

“The lessee shall pay to the lessor for gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product as royalty ⅛ of foe market value of such gas at the mouth of foe well; if said gas is sold by foe lessee, then as royalty ⅛ of foe proceeds of the sale thereof at the mouth of foe well. The lessee shall pay lessor as royalty ⅛ of the proceeds from foe sale of gas as such at foe mouth of foe well where gas only is found

or

“The lessee shall monthly pay to lessor as royalty on gas marketed from each well where gas only is found, one-eighth (⅛) of foe proceeds if sold at foe well, or if marketed by lessee off foe leased premises, then one-eighth (⅛) of its market value at foe well

OPIK, the producer/operator of the gas wells, had gas purchase contracts with ONEOK Midstream Gas Supply, L.L.C. (ONEOK), Duke Energy Field Services, LP (Duke), Unimark L.L.C. (Uni-mark), and DCP Midstream, LP (DCP). ONEOK deducted á gathering and compression fee and a dehydration fee. It is clear, based on the record, that ONEOK deducted these various fees from the total value of the gas purchased.

Duke deducted a gathering fee, a conditioning fee, and a fuel reimbursement fee for possible lost or unmeasured gas. In addition, if the gas did not meet the quality as required under the contract, Duke could elect to accept the deliveiy of the gas and deduct any costs it incurred to bring the gas within the quality specifications.

Unimark deducted all third-party costs, fees, and charges incurred that were associated with selling the gas, including treating, gathering, transporting, and compressing fees.

Although the record does not contain the contract between DCP and OPIK, there is a billing statement which states that DCP deducted fees and adjustments from the total value of the gas purchased.

Fawcett, one of the royalty owners, filed a class action lawsuit against OPIK alleging that OPIK had underpaid royalty owners by taking several deductions before the gas products were in a marketable condition. A check stub submitted by Fawcett for a royalty payment indicated that the only fee subtracted from the gross value of the gas proceeds was a state tax. The check stub did not contain any information regarding the deductions taken by tire gas purchasers before they paid OPIK for the gas products. Apparently, OPIK calculated the royalty it owed to the royalty owners based on the gross proceeds of gas sales at the well to gas purchasers less the cost of the stipulated price adjustments contained in the gas purchase contracts between OPIK and the gas purchasers.

Both parties filed motions for partial summary judgment. The trial court granted Fawcett’s partial motion for summaiy judgment, finding that OPIK impermissibly reduced the royalty payments by failing to compute the royalty payments based on the gross proceeds of gas sales at the well to the gas purchasers. In addition, the trial court granted class certification.

OPIK filed an application for interlocutory appeal, which was granted.

Did the trial court err when it held that OPIK impermissibly calculated the royalty payments on the gross proceeds of gas sales at the well to gas purchasers less the cost of the stipulated adjustments contained in the gas purchase contracts?

OPIK argues that the trial court erred when it granted Fawcett’s partial motion for summary judgment. Specifically, OPIK contends that under the express language of the oil and gas leases, it was only required to calculate royalty payments based upon the actual proceeds it received from the gas purchasers. In addition, OPIK asserts that the implied duty to market rule does not reach as far as the trial court has allowed it to extend. Amicus curiae Kansas Independent Oil and Gas Association, in supporting OPIK’s position, argues “that the marketable condition rule can be met by selling natural gas in its raw form at the well to natural gas purchasers under arm’s-length transactions.” Nevertheless, Fawcett argues that OPIK cannot alter its obligations under the oil and gas leases or under the marketable condition rule with its confidential gas contracts with third parties. Moreover, Fawcett contends that OPIK had the duty to transform the gas into a marketable product and OPIK alone bore the expense of making the gas marketable.

We come, therefore, to the question of whether the royalty payments are to be computed on the gross proceeds of gas sales at the well or on gross proceeds of gas sales at the well less cost of the stipulated price adjustments contained in the gas purchase agreements between OPIK and the gas purchasers.

Standard of Review

When the pleadings, depositions, answers to interrogatories, and admissions on file, together with the affidavits, show that there is no genuine issue as to any material fact and that the moving party is entitled to judgment as a matter of law, summary judgment is appropriate. The trial court is required to resolve all facts and inferences which may reasonably be drawn from the evidence in favor of the party against whom the ruling is sought. When opposing a motion for summary judgment, an adverse party must come forward with evidence to establish a dispute as to a material fact. In order to preclude summary judgment, the facts subject to the dispute must be material to the conclusive issues in the case. On appeal, the same rules apply; summary judgment must be denied if reasonable minds could differ as to the conclusions drawn from the evidence. Osterhaus v. Toth, 291 Kan. 759, 768, 249 P.3d 888 (2011).

The facts of this case are undisputed. When there is no factual dispute, appellate review of an order regarding summary judgment is de novo. David v. Hett, 293 Kan. 679, 682, 270 P.3d 1102 (2011).

The Oil and Gas Leases

There are generally three types of oil and gas leases with regard to the royalty clause in Kansas: (1) the proceeds lease; (2) the market value lease; and (3) the Waechter lease (a combination of the proceeds lease and the market value lease). Lightcap v. Mobil Oil Corporation, 221 Kan. 448, 457-61, 562 P.2d 1 (1977).

Language contained in proceeds leases are not always the same, but the pertinent language regarding the payment of royalties is that the lessee shall pay the royally owner a share of the actual monies received from the sále of the gas. Smith v. Amoco Production Company, 272 Kan. 58, 76, 31 P.3d 255 (2001).

Market value leases require the computation of royally payments based on the price that would be paid by a willing buyer to a willing seller in a free market. Matzen v. Cities Service Oil Co., 233 Kan. 846, 851, 667 P.2d 337 (1983).

Under Waechter leases, because the sale of the gas occurs at the wellhead, the royalty payments are to be computed based upon the actual sale price received by the producer. Waechter v. Amoco Production Co., 217 Kan. 489, 509-12, 537 P.2d 228 (1975).

In this case, 22 out of the 25 oil and gas leases are obviously Waechter leases. The language of the royalty clause in Waechter is identical to the language of the royalty clauses in 22 of the oil and gas leases in this case: “one-eighth (⅛) [or ¾6] of the proceeds if sold at the well, or if marketed by lessee off the leased premises, then one-eighth (Vs) [or Vm] of its market value at the well. . . .”

The gas, under these oil and gas leases, was sold at the well under the gas purchase contracts between OPIK and the gas purchasers. Therefore, the geography of the sale of gas was at the well and the geography for the computation of the royalty was also at the well.

The remaining three oil and gas leases contain the following language:

“The lessee shall pay to the lessor for gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product as royalty Vs of the market value of such gas at the mouth of the well; if said gas is sold by the lessee, then as royalty ⅛ of the proceeds of the sale thereof at tire mouth of die well. The lessee shall pay lessor as royalty Vs of the proceeds from die sale of gas as such at the moudi of the well where gas only is found

This language is a combination of a market value lease and a proceeds lease. Because the language is not identical to a Waechter lease, these leases cannot be considered Waechter leases. Nevertheless, the portion of the leases pertaining to the market value of the gas is not applicable in this case because the gas was sold at the wellhead and was never used by the producer to manufacture gasoline or any other product. In this situation, the remaining three leases should be deemed proceeds leases. As a result, the geography of the sale of gas was at the well and the geography for calculation of the royalty was at the well.

The relevant provisions of the leases at issue provided that the royalty was to be paid at one-eighth or three-sixteenths of the proceeds for gas sold at the well. No provision was made in the leases for deductions or, for that matter, the stipulated price adjustments contained in the gas purchase agreements.

The Definition of Proceeds

OPIK asserts that it sold the royalty owners’ gas at the well, therefore, OPIK argues that it is required to pay only one-eighth or three-sixteenths of the actual proceeds. To reach this interpretation, OPIK cites to selected quotations from several Kansas cases to support its argument that “proceeds” refers to the money OPIK actually received from the gas purchasers. See, e.g., Cities Service Oil Co., 233 Kan. at 860 (“In Waechter, we held that under a royalty clause calling for one-eighth of the proceeds if sold at the well, the lessor was entitled to no more than his proportionate share of the amount actually received by the lessee for the sale of gas. Following Waechter, we held in Lightcap that where a lease calls for royalties based on the proceeds from the sale of gas, the proceeds means the money obtained from an actual sale, and the lessor of a proceeds lease is entitled only to his proportionate share of those proceeds.”); Lightcap, 221 Kan. 448, Syl. ¶ 5 (“Where a lease calls for royalties based on the ‘proceeds’ from the sale of gas, the term ‘proceeds’ means the money obtained from an actual sale and lawfully retained by the seller.”); Waechter, 217 Kan. at 512 (“Proceeds ordinarily refer to the money obtained by an actual sale.”).

OPIK argues, based on its interpretation of the earlier mentioned cases, insofar as the royalty payments are concerned, the royalty is to be computed not on the entire gross proceeds of gas sales at the well to gas purchasers, but on such gross proceeds less the deductions set out in the gas purchase contracts and disclosed on the billing statements. Accordingly, OPIK maintains that it complied with the leases’ royalty clause when it paid the royalty owners one-eighth or three-sixteenths of the actual money transferred into its possession from the gas purchasers.

OPIK further asserts that this definition is clearly established law in Kansas. Our Supreme Court, however, in Hockett v. The Trees Oil Co. 292 Kan. 213, 251 P.3d 65 (2011), explained that in Waechter, the producer had a long-standing contract with an interstate gas purchaser. The contract was subject to federal regulatory approval. The contract provided that the gas purchaser would pay the producer a price per thousand cubic feet (mcf) which was apparently less than the current market value of the gas at the wellhead. On appeal, the argument between the royalty owner and the producer was whether “proceeds” meant the price per mcf in the purchase contract between the producer and the gas purchaser, which was approved by federal regulators (sale price), or whether it meant the prevailing market rate per mcf of a willing seller and a willing buyer without relying on the purchase contract or the regulatoiy constraints (market value). The Hockett court explained that in Waechter, the court held that “ ‘where gas is sold at the wellhead there are “proceeds” of drat sale—the amount received by the seller from the purchaser.’ ” Hockett, 292 Kan. at 222.

The Hockett- court further explained that when the court in Wae-chter was defining “proceeds” as the amount received by the producer, the court was merely distinguishing the actual gross contract rate per mcf from a hypothetical wellhead market rate per mcf. The Hockett court pointed out that the Waechter decision did not purport to address the impact on royalty payments of any deductions from the gross sale price which the gas purchaser might malee to pay expenses attributable to the producer. Hockett, 292 Kan. at 222.

The Hockett court noted that Lightcap is very similar to Wae-chter in the language used regarding “proceeds.” In Lightcap, our Supreme Court stated that the term “proceeds” means the money obtained from an actual sale and lawfully retained by the seller. See Hockett, 292 Kan. at 223. The addition of the language “and lawfully retained” addressed the fact that the federal regulatory agency disapproved of the contract rate that was filed and adjusted the rate downward accordingly. Lightcap, 221 Kan. at 451. Because of the adjustment, the producer could keep only the portion of the federally approved sale price paid by the gas purchaser. As a result, the “proceeds” of the sale for payment of royalties included only the portion of the sale price that the producer was legally authorized to receive. Hockett, 292 Kan. at 223. Again, there is no indication in Lightcap that the court addressed the result of deductions from the gross sale price on royalty payments which the gas purchaser might make to pay expenses attributable to the producer.

In Cities Service Oil Co., the argument also centered on whether the royalty owners should have been paid an amount in excess of their proportionate share of the sale price based upon a hypothetical market value of the gas. The court continued to adhere to Lightcap and Waechter regarding the treatment of proceeds from the sale of gas at die wellhead. 233 Kan. at 860-61.

OPIK’s situation is not comparable to that in Waechter, Light-cap, and Cities Service Oil Co. Those cases each dealt with whether proceeds of the sale should constitute the hypothetical value of the gas or the federally approved value of the gas. None of those cases considered the result on royalty payments of deductions taken from the gross sale price by the gas purchaser before paying the producer. The determination of what “proceeds” were in those cases will not bear nearly the weight of reliance which OPIK places on them.

In Hockett, a statutorily required conservation fee was deducted by the gas purchaser before making payment to the producer. The producer then based the royalty payment on the amount it actually received from the gas purchaser. The producer argued that the parties’ intent in the royalty clause was to require the royalty owner to share in the cost of the conservation fee. After distinguishing Cities Service Oil Co., Lightcap, and Waechter, our Supreme Court held that

“ ‘proceeds’ in a royalty clause refers to the gross sale price in the contract between the [gas] purchaser and the lessee/producer/seller, so long as the contractual rate per mcf has been approved by tire applicable regulatory authority. If the lessee claims that it is entitled to compute and pay royalties based upon an amount less than the gross sale price, it must find the authority to do so somewhere other than in the lease’s royalty clause.” Hockett, 292 Kan. at 223.

Our research of Kansas law has revealed no case in which this particular issue has been decided: Do the leases in question allow OPIK to pay the royalty owners a royalty based on the gross proceeds of gas sales at the well to gas purchasers less the cost of the stipulated price adjustments contained in the gas purchase agreements between OPIK and the gas purchasers?

In Sternberger v. Marathon Oil Co., 257 Kan. 315, 330-31, 894 P.2d 788 (1995), a class action was instituted by a royalty owner on behalf of royalty and overriding owners in Kansas, Oklahoma, and Texas. The suit sought recovery of “ ‘marketing costs’ ” or “ ‘gathering line amortization expenses,’ ” which had been deducted from the plaintiff s payments by TXO-Production Corp. (the predecessor of Marathon) to recover expenses for transporting the gas from the lease to the point of sale. 257 Kan. at 317.

In Stemberger, there was no market for tire gas at the wellhead, and TXO was unable to interest a gas purchaser in constructing a line to the well.. As a result, TXO built its own gathering system to gather the gas from six wells and transport it to tire pipeline. TXO, the lessee producer, then paid a transportation fee to Kansas Gas Supply, the pipeline, which it charged back to the royalty owners, as well as a 12-cent per mcf amortization of the cost of the construction of the pipeline, which it called a “marketing cost,” and a “line amortization” charge, which appeared to result in a retirement of the cost of the gathering system over approximately 12 to 13 months. These costs included maintenance, trucking of the pipe, a per diem charge for the foreman, survey, and right-of-way costs for the gathering system.

The trial court held that the deductions by TXO, now Marathon, were improper, and judgment was entered in the amount of the total deductions, $119,994.52, plus prejudgment interest of $50,346.63, for the total judgment against Marathon of $170,341.20. In following earlier Kansas decisions, tire Sternberger court held that the geography of the royalty computation as required by the lease language was at the well But there being no market at the well, the Sternberger court held that the transportation costs were to be borne proportionally by the lessor and the lessee. 257 Kan. at 331-32.

Sternberger is instructive because it points out that “[t]he lessee has the duty to produce a marketable product, and the lessee alone bears the expense of making the product marketable.” (Emphasis added.) 257 Kan. at 330-31. In discussing Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994), the Sternberger court noted that the lessee has the burden of proving the reasonableness of its costs and “[ajbsent 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.” (Emphasis added.) 257 Kan. at 331.

Finally, as Fawcett points out in her brief, “Sternberger reaffirmed the line of demarcation between deductible and;nondeductible expenses at the mainline transmission line pipeline quality.’ ” Sternberger carefully distinguished between “gathering” and “transportation” charges, and more specifically,. transportation charges after the gas reaches interstate transmission line quality and pressure. At issue in Sternberger was the lessee’s “line amortization charge” for laying a pipeline from a well to the interstate transmission line. 257 Kan. at 318. But there was “no evidence that Marathon engaged in any . . . compression, processing, or dehydration.” Sternberger, 257 Kan. at 331. Because nothing was done that would physically “transform” the gas, “the deductions made by Marathon are properly characterized as ‘ “transportation” ’ rather than ‘ “gathering” ’ or other production costs.” 257 Kan. at 331. Consistent with Kansas law, transportation of transmission “pipeline quality” gas is deductible from royalty. 257 Kan. at 322. “Generally, Kansas law holds that transportation costs are borne proportionately by tire lessor and lessee.” Sternberger, 257 Kan. at 322 (citing Scott v. Steinberger, 113 Kan. 67, 213 Pac. 646 [1923]) (transporting gas); Voshell v. Indian Territory Illuminating Oil Co., 137 Kan. 160, 19 P.2d 456 (1933) (transportation of oil by pipeline); and Molter v. Lewis, 156 Kan. 544, 134 P.2d 404 (1943) (transportation of oil by truck). “Scott, Voshell, and Molter are dispositive of the issue in this case. These cases clearly show that. . . tire lessor must bear a proportionate share of the expenses in transporting the gas or oil to a distant market.” Sternberger, 257 Kan. at 324. Scott also makes clear that “transportation” to a “distant market” does not mean transportation within the field before a processing plant, but after the processing plant on the interstate transmission line to “Kansas City or Chicago.” Scott, 113 Kan. at 68-69.

Implied Duty to Market Rule

OPIK asserts that the implied duty to market the gas is an implied duty in fact and not an implied duty in law. Consequently, OPIK contends that the courts must look to the language of the lease and the intent of the parties. OPIK further asserts that if the implied duty to market is not expressly written into the lease, then the parties are not subject to the duty.

OPIK, however, fails to acknowledge this court’s decision in Farrar v. Mobil Oil Corp., 43 Kan. App. 2d 871, 234 P.3d 19, rev. denied 291 Kan. 910 (2010), where this court discussed the implied duty to market and whether that duty is implied in fact or implied in law. This court determined that, generally, the implied duty to market is one that is implied in law and the only way to defeat the implied duty to market is by express language in the lease showing a contrary intent. “Under Kansas law, an implied covenant can only be defeated by express language showing a contrary intent.” Farrar, 43 Kan. App. 2d at 886. See also Gilmore v. Superior Oil Co., 192 Kan. 388, 393, 388 P.2d 602 (1964) (“[I]n the absence of an express provision of the lease creating such duty, the lessee is under an implied obligation to exercise reasonable diligence in marketing the gas produced.”). Gilmore further stated that if such lessee is desirous of a more complete coverage of the marketing of oil, gas, liquid hydrocarbons, or even helium gas, which has been found to exist in the minerals underlying the vast Hugoton field, the lessee has the opportunity to protect itself by the manner in which it draws the lease. 192 Kan. at 391.

Here, no express provision was made for deductions in the leases in question.

As Fawcett notes in her brief, OPIK relies on Davis v. Key Gas Corp., in which the two leases contained “express no-deduction” attachments, making the leases effectively express no-deduction leases. Davis v. Key Gas Corp., 34 Kan. App. 2d 728, 124 P.3d 96 (2005) (The Key Gas lease provided: “It is agreed that Lessor shall bear no costs of gas treatment, dehydration, compression, transportation or water hauling charged to this lease by Lessee in its operations thereon.”). The implied duty to market rule has the same effect as an express no-deduction lease—no deductions are allowed from royalties unless language in the lease “clearly and expressly” allows them. Thus, the outcome in Key Gas (no deductions as a matter of law) is the same outcome as the trial court concluded here. The only exception being that the Key Gas lease also expressly forbade deducting “transportation” expenses which are not at issue here. Key Gas, 34 Kan. App. 2d at 730.

Next, we must consider whether OPIK can avoid its obligations under the implied duty to market the gas by negotiating and contracting with a gas purchaser for a gross sale price of the gas sold at the well and then allow the gas purchaser to deduct from that gross sale price any amount used to compress, dehydrate, treat, and gather the gas.

Like OPIK here, Key Gas argued that it did not breach the lease because it did not take the deductions, rather the midstream service provider, ONEOK, did. In Key Gas, the oil and gas leases contained a condition precedent that required tire lessee, Key Gas, to charge transportation costs and other expenses to the leases before Key Gas became liable for these expenses. Because those costs were deducted by the gas purchaser, ONEOK, from the amount paid to Key Gas for gas purchased under their contract according to its terms, they were not charged to the leases by Key Gas and the condition precedent that would trigger Key Gas’ liability for the costs was never fulfilled.

L. Wayne Davis and Davis Farm, L.L.C., the plaintiffs, brought an action against Key Gas for underpayment of royalties. The question was whether Key Gas was required to pay to Davis’ portion of the transportation and other- expenses deducted under the purchase agreement that Key Gas had with ONEOK. Davis argued that the express provisions of paragraph 9 of the lease, which stated that the lessor was to bear no costs for gas treatment, dehydration, compression, transportation, or water hauling, prohibited any deduction from Davis’ royalties and that Key Gas could not construct the gas purchase contract in such a fashion which imposed the deductions on the royalty owner and thus disclaimed its responsibility called for under paragraph 9 of the lease. Key Gas, however, argued that it was paying appropriate royalties to Davis, maintaining that the deductions made under the gas purchase contract were not charges made by Key Gas under its lease with Davis. Moreover, Key Gas contended that it made no deductions from the ONEOK payment that it received in figuring Davis’ royalty share and was, in fact, paying his royalty share of the actual proceeds received.

The trial court held in favor of Key Gas, holding that there was no suggestion of collusion between ONEOK and Key Gas as was the concern in Sternberger, 257 Kan. at 330.

The Key Gas majority held that Key Gas could not deduct such costs from its royalty payments under circumstances where Key Gas had prevented fulfillment of a condition precedent contained in the oil and gas leases. In reaching its holding, the Key Gas majority considered the parties’ intent under the leases and determined that Key Gas had in its control the ability to avoid those previously mentioned charges by entering into a gas purchase contract with ONEOK, which allowed ONEOK to charge Key Gas for those charges. The Key Gas majority determined that when Key Gas contracted with ONEOK, it relinquished control over transportation costs and other expenses, rendering performance of the condition precedent impossible. As a result, die majority in Key Gas held that Key Gas could not rely on nonperformance of a condition precedent to deny liability under circumstances where its own action was the cause of the nonperformance.

Consistent with the legal maxim that one cannot do indirectly what one cannot do directly, the majority in Key Gas rejected Key Gas’ argument that it could avoid the “express no-deduction” provision by treating the expenses as a reduction in revenue, i.e. as “actual proceeds,” instead of a service charge. 34 Kan. App. 2d 728, Syl. ¶ 9, 731. See also Wilson v. American Fidelity Ins. Co., 229 Kan. 416, Syl. ¶ 3, 625 P.2d 1117 (1981) (“A party should not be permitted to accomplish indirectly what it cannot accomplish directly.”).

OPIK cites to a concession made by plaintiff in Key Gas that Sternberger might have held the other way (which it would have for a true transportation expense). Fawcett, in this case, makes no such concession here. But because transportation is not at issue here, the Key Gas plaintiff s concession is irrelevant. And in Key Gas, it is unnecessary to address the difference because “transportation costs and other expenses” were barred. (Emphasis added.) 34 Kan. App. 2d at 732 (“It appears that Key Gas never disputed that the types of costs and expenses deducted by ONEOK were those listed in paragraph 9 of Exhibit A of the oil and gas leases.”).

Under the implied duty to market rule, OPIK cannot charge to the royalty owners any expenses to malee the gas marketable. Moreover, as stated earlier, under Hockett,

“ proceeds’ in a royalty clause refers to the gross sale price in the contract between the [gas] purchaser and the lessee/producer/seller, so long as the contractual rate per mef has been approved by tire applicable regulatory authority. If the lessee claims that it is entitled to compute and pay royalties based upon an amount less than the gross sale price, it must find the audiority to do so somewhere other than in the lease’s royalty clause.” 292 Kan. at 223.

Here, the language used in the leases valued the gas at the well. Moreover, the leases obligated OPIK to market the gas at the well. Under Kansas law, the leases make it clear that the royalty is to be computed on the gross proceeds of gas sales at the well. Because no special provision in the leases allowed OPIK to compute royalties based on the gross proceeds of gas sales at the well less tire cost of the stipulated price adjustments contained in the gas purchase agreements, we determine that OPIK’s arguments fail.

Affirmed.

McAnany, J.,

concurring: I concur with Judge Green’s analysis in this case. We are asked to decide whether tire proceeds to be divided among royalty holders from the sale of gas at the wellhead are the gross proceeds from the sale or the net proceeds after deducting charges incurred by the buyer for treating the gas after the point of sale. Setting aside public policy issues, the position taken by the appellant, Oil Producers, Inc. of Kansas, on this central issue is marked by a level of simplicity and clarity that avoids the morass of resolving the issue of marketability. OPIK argues: “The duty to market in Kansas has only ever required operators to produce a saleable gas product and market and sell it free of cost to the royalty owner.” According to OPIK, if a product can be sold, it ipso facto is marketable. Thus, the proceeds of the sale subject to distribution among the royalty interest holders were the net sale proceeds.

But a demand curve can be drawn for any item that may be subject to a commercial transaction. I do not ascribe to the notion that because there is some point on every such curve where somebody would be willing to pay for the item, each and eveiy item passes the test of marketability. Under that test, the notion of marketability becomes superfluous. That seems to defy a level of common sense that even judges are expected to bring to the discussion.

Besides, our Supreme Court spoke to the issue of marketability in Sternberger v. Marathon Oil Co., 257 Kan. 315, Syl. ¶ 3, 894 P.2d 788 (1995), when the court stated:

“Under a natural gas lease, once a marketable product is obtained, reasonable costs incurred to transport or enhance the value of tire 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 non-working interest holder is not obligated to bear any share of production expense, such as compressing, transporting, and processing, undertaken to transform gas into a marketable product.’’ (Emphasis added.)

While the expense at issue in Stemberger was the cost of a gas gathering pipeline system, we cannot ignore this language on marketability from the syllabus, which is there to set forth a point decided in the case. See K.S.A. 20-111.

Finally, I write separately to clarify my position inartfully expressed in Davis v. Key Gas Corp., 34 Kan. App. 2d 728, 743, 124 P.3d 96 (2005), rev. denied 281 Kan. 1377 (2006). While Key Gas dealt with transportation and other expenses charged back against the royalty interest holders, attention seemed to me to be focused at the time on the transportation issue. My dissent was directed solely to the majority’s handling of that issue and not the issue of other expenses charged back, though one would have a hard time detecting that from what I wrote. In the case now before us, transportation costs are not at issue, so I concur with Judge Green’s use of Key Gas in considering the other expenses deducted from the royalty payments.  