Fawcett v. Oil Producers, Inc. of Kansas

352 P.3d 1032, 302 Kan. 350, 2015 Kan. LEXIS 376

• Court: Supreme Court of Kansas
• Decided: July 2, 2015
• Docket: 108666
• Status: Published

Opinion

The opinion of the court was delivered by

Biles, J.:

This is a class action for underpayment of royalties claimed under 25 oil and gas leases entered into between 1944 and 1991. The controversy arises because the lessee-operator sells its raw natural gas at the wellhead to third parties, who in turn process the gas before it enters the interstate pipeline system. The price tire operator is paid—and upon which royalties have been calculated—-is based on a formula that starts with the price those third parties receive for the processed gas (or a published index price) then deducts certain costs incurred or adjustments made. The class argues those subtracted costs and adjustments are the operator s sole responsibility because the gas is not in a marketable condition when it leaves the wellhead, so the royalties the class receives are less than they should be. It is represented to us that most natural gas produced in Kansas is sold under formula-based purchase agreements similar to those in this case.

The issue has been stated in various ways, but in its simplest form the court must decide whether the operator may take into account the deductions and adjustments identified in the third-party purchase agreements when calculating royalties. The district court granted summary judgment to the class for an as-yet undetermined amount of unpaid royalties. The Court of Appeals affirmed. Fawcett v. Oil Producers, Inc. of Kansas, 49 Kan. App. 2d 194, 195, 306 P.3d 318 (2013). We reverse on the issue subject to our review and remand for further proceedings.

The operator sold the gas at the well to various purchasers. Fawcett, 49 Kan. App. 2d at 199 (“[T]he geography of the sale of gas was at the well and the geography for the computation of the royalty was also at the well.”)- Under Kansas law, the leases imposed on the operator an implied duty to market the minerals produced. See Robbins v. Chevron U.S.A., Inc., 246 Kan. 125, 131, 785 P.2d 1010 (1990) (implied duty to market); Gilmore v. Superior Oil Co., 192 Kan. 388, 392, 388 P.2d 602 (1964); see also Smith v. Amoco Production Co., 272 Kan. 58, 81, 31 P.3d 255 (2001). To satisfy this duty, the operator had to market its production at reasonable terms within a reasonable time following production. See Smith, 275 Kan. at 81.

Whether the operator fulfilled this implied duty by entering into these purchase agreements depends on the circumstances as to the terms and time of sale, which are not in dispute in this case. Instead, the class invokes the “marketable condition rule,” which is a corollary of the duty to market. Broadly speaking, the rule requires operators to malee gas marketable at their own expense. See Sternberger v. Marathon Oil Co., 257 Kan. 315, 330, 894 P.2d 788 (1995) (“The lessee has the duty to produce a marketable product, and the lessee alone bears the expense in making the product marketable.”).

The class contends raw natural gas coming from the well is not marketable until it enters an interstate pipeline, so its royalties cannot be reduced by the deductions in these purchase agreements relating to transforming the gas into a condition suitable for that transmission system. We disagree. We hold these leases do not impose on the operator as a matter of law the responsibility to perform the post-production, post-sale gathering, compressing, dehydrating, treating, or processing that may be necessary to convert the gas sold at the wellhead into gas capable of transmission into interstate pipelines.

The class was not entitled to summary judgment, except as to conservation fees, which the operator concedes were wrongly deducted prior to the royalty calculation based on our recent decision in Hockett v. The Trees Oil Co., 292 Kan. 213, 251 P.3d 65 (2011) (conservation fee is expense attributable solely to well operator). That issue was resolved by the district court and is not in controversy on appeal.

Factual and Procedural Background

Production of natural gas is a complicated process. Title to the gas can change hands numerous times as it travels from the ground to an eventual end user. In this case, the chain starts with the plaintiff class, which consists of mineral rights owners, who lease their rights in exchange for a royalty interest in the oil and gas produced. The L. Ruth Fawcett Trust represents the class based on its royalty interests located in Seward County. We refer to the plaintiff class as “Fawcett.” Oil Producers, Inc. of Kansas (OPIK) is the lease operator, which means it owns the wells from which the oil and gas are produced. See Williams & Meyers, Manual of Oil and Gas Terms, pp. 709, 815 (15th ed. 2012) (defining operator and producer).

Natural gas coming from the ground in its raw condition is not suitable for transportation in interstate pipelines. For our purposes, it is sufficient to note that natural gas must meet certain quality specifications before it can enter an interstate gas pipeline and it must be processed to achieve those specifications. Some of this may occur at the wellhead, such as when an operator performs separating or dehydrating, as needed. But most processing required to transform raw natural gas into pipeline-quality gas occurs away from the wellhead, such as at processing plants, where other valuable components of the raw gas can be isolated and sold separately. See www.naturalgas.org for a summary of the industry process; see also Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., 281 F.R.D. 477, 479-80 (D. Kan. 2012), vacated by 725 F.3d 1213 (10th Cir. 2013).

OPIK does not charge royalty owners for any services it performs on tire leased premises. But OPIK does not own gathering or processing facilities. Instead, it sells the gas at the wellhead to midstream gatherers and processers (the third-party purchasers), who prepare the raw natural gas for eventual delivery into dre interstate pipeline system. Those third-party purchasers take title to the gas at the wellhead; transport it to processing plants; process it, separating tire natural gas and the natural gas liquids contained in the raw gas; and eventually sell the natural gas and natural gas liquids to someone else. The price OPIK gets for the raw gas is dependent in the first instance on what the third-party purchasers are paid for the processed gas or a contractually set index price.

The operator and amici argue these gas sales contracts are structured to allow OPIK and its royalty owners to jointly share in higher “downstream” market values as die gas gets closer to the consumer-—after the specified expense deductions to account for services provided by the third-party purchasers to process the gas and transport it from the wellhead to the downstream resale location. But from Fawcett’s perspective, its royalty payments are being re duced for expenses Fawcett claims are OPIK’s sole responsibility. In other words, because OPIK pays Fawcett a percentage of what OPIK receives, Fawcett proportionately shares in these expenses. A closer look at the leases and the contracts helps to understand how the parties get paid.

The 25 leases in issue vary in their exact language, including the fraction that represents tire amount owed to the royalty owner; but the parties stipulated the leases take two general forms as to tire royalty due for the gas sold on the leased premises:

(1) “lessee [OPIK] shall pay lessor [Fawcett] as royalty Vs of the proceeds from the sale of gas as such at the mouth of the well where gas only is found;” or

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

Importantly, the leases do not define what the term “proceeds” means and are silent as to deductions. The dispute between the parties is centered here and with the third-party purchase agreements.

Simplified, third-party purchasers pay OPIK for the raw gas received at the wellhead based on a percentage of specified index prices or the third-party purchasers’ actual revenue when that gas is sold to others, reduced by certain costs. By way of example, consider OPIK’s contract with third-party purchaser ONEOK Midstream Gas Supply, L.L.C.

In exchange for natural gas delivered by OPIK, ONEOK agreed to pay a percentage of its income from the sale of the natural gas and the natural gas liquids recovered from the raw gas—less deductions from the natural gas income for: a “base gathering and compression fee” of 55 cents per MMBtu (one million British thermal units); approximately 6 percent for plant, gathering, and compression fuel; 1.14 percent for fuel lost and unaccounted for; and, if applicable, fees paid to others to deliver the gas to ONEOK’s processing facility. OPIK and ONEOK further agreed the amount due under this formula constituted full consideration for the gas and all of its constituents received at the wellhead by ONEOK. Title to the gas passed to ONEOK at or near the wellhead.

The ONEOK agreement also contains quality requirements for the gas received from OPIK at the well. For example, OPIK must supply gas at a pressure “sufficient to effect delivery” and free of solid and liquid contaminants, hazardous waste, and free water. The gas must contain a minimum percentage of hydrocarbon constituents with a minimum heating value per cubic foot and less than specified amounts of water vapor, hydrogen sulfide, and sulfur. If the gas fails to meet contractual requirements, ONEOK reserves the right to either refuse delivery or accept the gas but deduct treatment costs.

There is no claim costs were ever assessed to the class to meet ONEOK or any other purchasers’ requirements as to the quality of the gas at the time and place OPIK delivered it.

One additional deduction needs highlighting to assist with an understanding of the contractual schemes involved, although its actual importance is minimized by OPIK’s concession before the case was argued to this court. Under the purchase agreements, separate contractual provisions made clear OPIK was responsible for conservation fees assessed under K.A.R. 82-3-307, so if third-party purchasers were required to pay the conservation fees on OPIK’s behalf, those purchasers would deduct that amount from what it paid OPIK for the raw gas. For a time in this case, OPIK argued the conservation fee was an appropriate deduction, i.e., a cost shareable with royalty owners, but that argument was lost when this court decided Hockett.

The district court proceedings

In the district court, the parties each moved for summary judgment. OPIK argued its royalty payments were proper because they were computed on 100 percent of its actual proceeds from its sale of the gas at the wellhead. Fawcett countered that OPIK was required to pay royalties on the “gross” price of the gas as it entered the interstate market, rather than the “net” contract prices set out in the third-party purchase agreements. Fawcett characterized the deductions and adjustments set out in those agreements as subtractions from the gross price.

In response to OPIK’s motion for summary judgment, Fawcett argued the “sale” for royalty purposes occurred when the third-party purchasers resold the processed natural gas and its liquid byproducts, not when OPIK sold the raw gas at the wellhead. Faw-cett claimed the raw gas was not marketable at the well since it was unsuitable for delivery into interstate pipelines. Fawcett argued the deductions in the purchase contracts simply represented expenses to make the gas marketable, which was OPIK’s obligation alone.

The district court granted Fawcett partial summary judgment for “those expenses claimed by [OPIK] such as the ‘gathering charges, compression charges, dehydration, treatment, processing, fuel charges, fuel lost or unaccounted for, and/or third party expenses incurred to make the gas marketable.’ ” It reasoned OPIK owed Fawcett a duty to make the gas marketable free of cost and that OPIK could not avoid responsibility for those costs by contracting with a third party to incur them. Impliedly, the district court determined the deductions in the purchase agreements represented costs required to make the gas marketable.

As a separate matter, the district court granted summary judgment to the class for royalty reductions attributable to the conservation fees based on Hockett, which was issued after the parties had filed for summary judgment. In Hockett, this court held that conservation fees were the operator’s sole responsibility. 292 Kan. at 224.

But the district court made no monetary damage calculation. Instead, it found its partial summaiy judgment order involved a controlling question of law regarding the operator’s legal duty under the leases as to which there was substantial ground for difference of opinion, so an immediate appeal would be beneficial. Upon OPIK’s timely application, the Court of Appeals granted interloc-utoiy review. See K.S.A. 60-2102(c) (interlocutoiy appeals).

The Court of Appeals decision

The Court of Appeals affirmed the order granting the class partial summaiy judgment. Fawcett, 49 Kan. App. 2d at 195. The panel framed the question as whether “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 [purchase contracts]?” 49 Kan. App. 2d at 202. The panel held royalty must be paid on the pre-deduction contract prices—-what it termed OPIK’s “gross proceeds.” 49 Kan. App. 2d at 195.

In arriving at that conclusion, the panel agreed that the gas was sold at the well and that the leases require royalty payment based on die proceeds from wellhead sales with no provisions for deductions or adjustments from gas sale contracts. 49 Kan. App. 2d at 199. Then, the panel concluded the term “proceeds” as used in the leases means the money OPIK would have received under the third-party purchase agreements without the deductions specified in those agreements. 49 Kan. App. 2d at 208. To reach that conclusion, the panel noted that operators are obligated to produce a marketable product, which the panel held did not occur until the gas reaches mainline transmission pipeline quality. 49 Kan. App. 2d at 203-04.

The panel then determined OPIK’s obligation prohibits deductions from royalties except as might be expressly authorized in the lease, noting no such language appears. 49 Kan. App. 2d at 205. Finally, having concluded OPIK could not deduct from royalties the expenses represented as deductions or price adjustments in the purchase agreements, the panel held OPIK could not contract with third-party purchasers to provide the services the operator was required to provide. 49 Kan. App. 2d at 207.

The panel relied heavily on Davis v. Key Gas Corp. 34 Kan. App. 2d 728, 731, 124 P.3d 96 (2005), in which another Court of Appeals panel held that an oil and gas lease expressly prohibiting operators from directly taxing any transportation or other expenses to royalty owners prohibited those operators from doing so indirectly through third-party purchase contracts. The Fawcett panel wrote in summation:

“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 OPIICs arguments fail.” 49 Kan. App. 2d at 208.

In a concurring opinion, Judge Patrick D. McAnany further challenged OPIK’s argument that its lease obligations were satisfied by its production and sale of gas at the wellhead, free of cost to the royalty owners. He characterized this as simplistically contending that if a product can be sold, it is by definition marketable. Judge McAnany criticized this logic as defying common sense because “a demand curve can be drawn for any item that may be subject to a commercial transaction,” and he rejected the idea that “marketability” is established at the “point on every such curve where somebody would be willing to pay for the item.” Fawcett, 49 Kan. App. 2d at 208.

OPIK petitioned this court for review, which was granted. Jurisdiction is proper. See K.S.A. 60-2101(b) (jurisdiction to review court of appeals decision upon petition for review); see also K.S.A. 20-3018(b).

Analysis

The issue before this court is whether OPIK is solely responsible under the common-law marketable condition rule for the costs and adjustments taken by the third-party purchasers. In concluding that the district court and Court of Appeals must be reversed on this point, we first consider OPIICs royalty obligation under the leases and whether the marketable condition rule allocates to OPIK the expense of post-production, post-sale processing to transform the gas as Fawcett claims.

Standard of Review

Our standard of review on summary judgment is well known:

“Summary judgment is appropriate 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. 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 estab lish 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, we apply the same rules and where we find reasonable minds could differ as to the conclusions drawn from tire evidence, summary judgment must be denied. [Citations omitted.]” Shamberg, Johnson & Bergman, Chtd. v. Oliver, 289 Kan. 891, 900, 220 P.3d 333 (2009).

Determining OPIK’s royalty obligation and the allocation of expenses under the marketable condition rule requires us to interpret the leases and the express and implied obligations arising from them. The interpretation and legal effect of an oil and gas lease are both questions of law subject to de novo review. See Thoroughbred Assoc. v. Kansas City Royalty Co., 297 Kan. 1193, 1207, 308 P.3d 1238 (2013) (interpreting oil and gas lease de novo). Both parties argue there are no material facts in dispute. As a result, we are focused on Fawcett’s contention that natural gas, as a matter of law, is not marketable for purposes of these oil and gas leases until it enters an interstate pipeline, so Fawcett’s royalties cannot be reduced by the deductions in these purchase agreements.

Discussion

The gas in this case was sold at the wellhead. Fawcett, 49 Kan. App. 2d at 199. The lease language required OPIK to pay Fawcett a fractional share of its proceeds “from the sale of gas as such at the mouth of the well where gas only is found” or “if sold at the well.” Generally,

“An oil and gas lease which provides that the lessee shall pay lessor monthly as royalty on gas marketed from each well one eighth of the proceeds if sold at the well, or, if marketed off the leased premises, then one-eighth of the market value at the well, is clear and unambiguous as to gas sold at the wellhead by the lessee in a good faith sale, and lessor is entitled to no more than his proportionate share of the amount actually received by the lessee for the sale of the gas.” Waechter v. Amoco Production Co., 217 Kan. 489, Syl. ¶ 2, 537 P.2d 228 (1975).

See also Matzen v. Cities Service Oil Co., 233 Kan. 846, 850-51, 667 P.2d 337 (1983) (quoting Waechter, 217 Kan. at 489, Syl. ¶ 2); Lightcap v. Mobil Oil Corp., 221 Kan. 448, 460, 562 P.2d 1 (1977).

The Fawcett panel identified 22 of the 25 leases in this case as Waechter leases, meaning that the royalty clause language is iden tical to the royalty language at issue in the Waechter case. Fawcett, 49 Kan. App. 2d at 198. As to the other three, the panel noted their royalty language is a combination of market value and proceeds leases. But it determined they should nevertheless be deemed Waechter leases because the language pertaining to market value is not applicable since the gas was sold at the wellhead. From this, the panel concluded: “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.” 49 Kan. App. 2d at 199. The parties have taken no exception to the panel’s conclusions in this regard.

In Hockett, we explained the term “proceeds” in a royalty clause similar to the ones at issue refers to the gross sale price in the contract between the first purchaser and the operator and noted that the cases stating the general rule recited in Waechter and its progeny do not “purport to address the impact on royalties of any deductions from the gross sale price which the purchaser might make to pay expenses attributable to the lessee/seller.” (Emphasis added.) 292 Kan. at 222. The “gross sale price” to which Hockett referred was the price paid for die gas before the purchaser withheld a state-assessed conservation fee, which was statutorily attributable only to the operator. See 292 Kan. at 224.

But unlike conservation fees, which function essentially as a state-assessed mill levy on gas sold by the operator, the third-party purchase contract pricing formulas in this case more clearly represent a negotiated sale price for the gas, i.e., the total sum paid in exchange for the gas delivered at the wellhead. As such, if the question were whether those negotiated formulas produce an adequate price, tiie answer would seem to require a fact-based analysis to determine whether the operator entered into good faith sales and whether the terms of those sales were reasonable under the circumstances. See Smith, 272 Kan. at 82-83; Waechter, 217 Kan. 489, Syl. ¶ 2.

But Fawcett contends something else. It claims OPIK is required to bear the entire expense of transforming raw natural gas into the quality required for transmission into the interstate pipeline system. Fawcett argues the “marketable condition rule,” which is an offshoot of the implied duty to market, imposes on operators the obligation to make gas marketable at tire operators’ own expense. 49 Kan. App. 2d at 197. Fawcett claims raw natural gas sold at the well is not marketable as a matter of law or fact until it is processed and enters an interstate pipeline, so its royalties cannot be reduced by the processing costs that are set out as deductions in the purchase agreements. We disagree with Fawcett’s equating “marketable condition” with interstate pipeline quality.

Under the controlling leases, OPIK owed the class an implied duty to market tire minerals produced. See Smith, 272 Kan. at 81; Robbins, 246 Kan. at 131 (implied duty to market); Gilmore, 192 Kan. at 392. We have said this covenant is implied by “ ‘the facts and circumstances of the case’ but . . . ‘not formally or explicitly stated in words.’ ” Smith, 272 Kan. at 70; see Howerton v. Kansas Natural Gas Co., 81 Kan. 553, 563, 106 P. 47 (1910) (oil and gas lease “contemplated that the well should be operated and gas marketed therefrom”).

To satisfy this duty, an operator must market its production at reasonable terms within a reasonable time following production. See Smith, 272 Kan. at 81. Ordinarily the interests of the lessor (royalty owners) and lessee (operator) will coincide on such matters because the operator will have everything to gain and nothing to lose by selling the product at the best price available. Robbins, 246 Kan. at 131-32. OPIK claims it fulfilled its duty to market by entering into these purchase agreements for sale of the gas at the wellhead and argues tire pricing formulas give both itself and its royalty owners the opportunity to share in higher prices received for the gas as it gets closer to the consumer.

With the duty to market comes the lessee-operator’s obligation to prepare the product for market, if it is unmerchantable in its natural form, at no cost to the lessor (royalty owner). Gilmore, 192 Kan. at 393; see Sternberger, 257 Kan. 315, 330, 894 P.2d 788 (1995). Three Kansas cases have addressed an operator’s duty to prepare gas for market: Gilmore, 192 Kan. 388; Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964); and Sternberger, 251 Kan. 315. We consider each to explain why the district court and Court of Appeals erred.

In Gilmore, the lease language required the operator to pay for gas sold, “as royalty ⅛ of the proceeds of the sale thereof at the mouth of the well.” 192 Kan. at 391. In that case, the operator had been wasting the gas produced by venting it into the atmosphere until it built a compressor station on the lease, which collected and compressed the gas. This allowed the operator to sell the gas, and the operator sought contribution from royalty owners for the compression costs. 192 Kan. at 389-90. In holding the operator could not pass on this expense to the royalty owner, the Gilmore court noted the only purpose for the compressing station was to put enough force behind the gas to enable it to enter the purchaser s pipeline, which was on the lease. The court then cited a treatise for the proposition that if raw gas is unmerchantable, the lessee must prepare it for market free of cost to the lessor. 192 Kan. at 393 (citing Merrill on Covenants Implied in Oil and Gas Leases, § 85, p. 214 [2d ed. 1940]). The Gilmore court reasoned that this compression simply “made the gas marketable and was in satisfaction of the duties of the lessee [operator] so to do.” 192 Kan. at 392.

In Schupbach, which involved virtually identical lease language as Gilmore, the operator similarly installed a compressor station on the leased premises that enabled it to compress gas to a delivery pressure specified by a third-party purchaser. Schupbach, 193 Kan. at 403. Finding Gilmore indistinguishable, the Schupbach court held the operator could not deduct that compression cost from its gross proceeds in computing royalties. 193 Kan. at 406.

Sternberger presented a different question, i.e., what expenses may be deducted from the sale price away from the well to determine market value of the gas at the well. In that case, the gas production was sold off-lease, but the lease language required the operator to “pay royalties of one-eighth ... of the market price at the well for gas sold or used.” (Emphasis added.) 257 Kan. at 321. The operator could not convince a third-party purchaser to build a pipeline to the well, so the operator had to construct its own gas gathering pipeline system to transport gas from the wells to the market. The operator then deducted a proportionate share of the pipeline costs from royalty payments as a recoupment. The court characterized the costs as post-production expenses. It held this deduction was proper—making the royalty owners responsible for a share of tire reasonable expenses to transport the gas to market. 215 Kan. at 331-32.

In so holding, the Stemberger court noted a long-standing rule in Kansas that when royalties are to be paid on the value of gas at the well, but no market exists there, the royalty owner must bear a proportional share of the reasonable expenses of transporting the gas to market. 257 Kan. at 322 (citing Molter v. Lewis, 156 Kan. 544, 134 P.2d 404 [1943]; Voshell v. Indian Territory Illuminating Oil Co., 137 Kan. 160, 19 P.2d 456 [1933]; Scott v. Steinberger, 113 Kan. 67, 213 P. 646 [1923]). Then, recognizing the operator’s general duty to prepare gas for market, the Stemberger court distinguished the transportation costs at issue from the compression costs required to make the gas marketable in Gilmore and Schup-bach, reasoning:

“[T]here is no evidence ... die gas produced ... was not marketable at the mouth of the well other than the lack of a purchaser at that location. There is no evidence [the operator] engaged in any activity designed to enhance the product, such as compression, processing, or dehydration. There is no evidence [the operator] attempted to deduct any expenses in making the gas marketable other dian those of constructing a pipeline to transport the gas to the purchaser or to a transmission pipeline.” 257 Kan. at 331.

The Stemberger court further explained:

“We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994) [En Banc], 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 nonworldng interest owners. . . . Absent a contract providing to the contrary, a nonworldng 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.” 257 Kan. at 331.

Notably absent from these cases is any discussion of a precise quality or condition at which gas becomes “marketable,” despite their conclusive declarations about whether the gas at issue was marketable at the well. What it means to be “marketable” remains an open question. But the answer is not simply, as Fawcett would have us hold, interstate pipeline quality standards or downstream index prices.

The common thread in Gilmore and Schupbach is that the compression expenses were necessary to deliver the gas production, on the leased premises, to the purchaser. See Schupbach, 193 Kan. at 404; Gilmore, 192 Kan. at 392. The transportation expenses in Stemberger were also required to deliver the gas to tire purchaser, yet they were not similarly treated because royalties in that case were based on the market value of the gas at the well, and the operators had done nothing to prepare the wellhead gas for sale other than move it from the place where its value was to be determined (the well) to the purchaser. See Sternberger, 257 Kan. at 331.

We believe these cases taken together demonstrate that when gas is sold at the well it has been marketed; and when the operator is required to pay royalty on its proceeds from such sales, the operator may not deduct any pre-sale expenses required to make the gas acceptable to tire third-party purchaser. See Coulter v. Anadarko Petroleum Corp., 296 Kan. 336, 362, 292 P.3d 289 (2013) (“The lessee . . . must bear the entire expense of producing the gas at the wellhead pursuant to the terms of the oil and gas lease. Additionally, the lessee must also bear the entire cost of putting the gas in condition to be sold pursuant to the court-made ‘marketable condition rule.’ ”); accord Wellman v. Energy Resources, Inc., 210 W. Va. 200, 211, 557 S.E.2d 254 (2001) (holding lease requiring royalty based on proceeds requires lessee to bear all costs to explore for, produce, market, and transport product to point of sale). But post-sale, post-production expenses to fractionate raw natural gas into its various valuable components or transform it into interstate pipeline quality gas are different than expenses of drilling and equipping the well or delivering the gas to the purchaser.

We recognize the Colorado Supreme Court held, based on the operator’s duty to market, that an operator can be solely responsible for post-production, post-sale processing expenses when the lease requires royalties to be calculated on the operator’s proceeds from the sale of gas at the well. See Rogers v. Westerman Farm Co., 29 P.3d 887, 891 n.1, 912-13 (Colo. 2001). In reaching that conclusion, the Rogers court determined the “at the well” language did not establish the geographical point of valuation for calculating royalty payments and the leases were therefore silent with respect to the allocation of post-production transportation and processing expenses. See 29 P.3d at 896-97. It held “marketable condition” ' established the point prior to which all transportation and processing costs are taxable to the operator, but after which such expenses may be shared with the lessors. See 29 P.3d at 906. When Rogers is viewed through the lens of the lease language at issue in this case, the sale of gas does not yield “proceeds” unless at the time of sale the gas is “in the physical condition such that it is acceptable to be bought and sold in a commercial marketplace, and in the location of a commercial marketplace, such that it is commercially saleable in the oil and gas marketplace.” 29 P.3d at 906.

To the extent Rogers concerns the royalty due on gas sold at the well under a proceeds lease, it is at odds with our Kansas caselaw interpreting such provisions, as well as our caselaw giving effect to the “at the well” language. See Hockett, 292 Kan. at 223 (“[T]he term proceeds’ in a royalty clause refers to the gross sale price in the contract between the first purchaser and the [operator].”); Sternberger, 257 Kan. at 324 (“[Kansas cases] clearly show that where royalties are based on market price ‘at the well,’ . . . the lessor must bear a proportionate share of the expenses in transporting the gas or oil to a distant market.”). We decline to follow Rogers based on our prior caselaw.

We hold that when a lease provides for royalties based on a share of proceeds from the sale of gas at the well, and the gas is sold at the well, the operator’s duty to bear the expense of making the gas marketable does not, as a matter of law, extend beyond that geographical point to post-sale expenses. In other words, the duty to make gas marketable is satisfied when the operator delivers the gas to tire purchaser in a condition acceptable to the purchaser in a good faith transaction. See Waechter, 217 Kan. 489, Syl. ¶ 2. OPIK satisfied its duty to market the gas when the gas was sold at the wellhead. When calculating Fawcett’s royalty, the post-production, post-sale processing expenses deducted by the third-party purchasers are shared.

We are sensitive to the potential for claims of mischief given an operator s unilateral control over production and marketing decisions. But we believe royalty owners’ interests are adequately protected by the operator’s implied covenant of good faith and fair dealing and the implied duty to market. The latter demands that operators market the gas on reasonable terms as determined by what an experienced operator of ordinary prudence, having due regard for the interests of both the lessor and lessee, would do under the same or similar circumstances. See Smith, 272 Kan. at 85; Robbins, 246 Kan. at 131. In this case, Fawcett does not challenge OPIK’s good faith, its prudence in entering into the purchase agreements at issue, or their material terms. Accordingly, we need not dwell further on what this might entail.

The judgment of the Court of Appeals is reversed as to the issue subject to our review. The judgment of the district court is reversed on the issue subject to our review, and the case is remanded to the district court.