Fawcett v. Oil Producers, Inc. of Kansas

IN THE SUPREME COURT OF THE STATE OF KANSAS

No. 108,666

L. RUTH FAWCETT,
Appellee,

v.

OIL PRODUCERS, INC. OF KANSAS,
Appellant.

SYLLABUS BY THE COURT

The lessee-operator of the oil and gas leases at issue in this case has an implied
duty to market the minerals produced. To satisfy this duty, the operator must market its
production at reasonable terms within a reasonable time following production. It must
also prepare the raw production, if unmerchantable in its natural form, free of cost to the
royalty owners. The production is merchantable once the operator has put it into a
condition acceptable to a purchaser in a good faith transaction. Royalty owners in this
case were not entitled to judgment as a matter of law on their theory that post-production,
post-sale expenses necessary to transform raw natural gas into the quality required for
interstate pipeline transmission were attributable solely to the operator as part of the
operator's responsibility to make the gas marketable.

Review of the judgment of the Court of Appeals in 49 Kan. App. 2d 194, 306 P.3d 318 (2013).
Appeal from Seward District Court; KIM R. SCHROEDER, judge. Opinion filed July 2, 2015. Judgment of
the Court of Appeals affirming the district court is reversed as to the issue subject to review. Judgment of
the district court is reversed as to the issue subject to review and remanded with directions.

Robert W. Coykendall, of Morris, Laing, Evans, Brock & Kennedy, Chtd., of Wichita, argued the
cause, and Will B. Wohlford and Julia Gilmore Gaughan of the same firm, of Topeka, were with him on
the briefs for appellant.
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 Rex A. Sharp, of Gunderson Sharp LLP., of Prairie Village, argued the cause, and Barbara C.
Frankland and David E. Sharp, of the same firm, of Houston, Texas, were with him on the briefs for
appellee.

David W. Nickel, of DePew Gillen Rathbun & McInteer, LC, of Wichita, was on the brief for
amicus curiae Kansas Independent Oil and Gas Association.

David E. Pierce, of Topeka, was on the brief for amicus curiae Eastern Kansas Oil & Gas
Association.

Curtis M. Irby, of Glaves, Irby and Rhoads, of Wichita, was on the brief for amicus curiae DCP
Midstream, LP.

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 the 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.

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 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 make
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
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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
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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 the 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 the interstate pipeline system.
Those third-party purchasers take title to the gas at the wellhead; transport it to
processing plants; process it, separating the 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 the
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 reduced 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.
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 The 25 leases in issue vary in their exact language, including the fraction that
represents the amount owed to the royalty owner; but the parties stipulated the leases take
two general forms as to the royalty due for the gas sold on the leased premises:

(1) "lessee [OPIK] shall pay lessor [Fawcett] as royalty 1/8 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 (1/8) of the proceeds if sold at the well, or if
marketed by lessee off the leased premises, then one-eighth (1/8) 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
6
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.

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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.
Fawcett 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.

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 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 summary 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 interlocutory review. See K.S.A. 60-2102(c)
(interlocutory appeals).

The Court of Appeals decision

The Court of Appeals affirmed the order granting the class partial summary
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 the 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
9
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 the cost of the stipulated price adjustments
contained in the gas purchase agreements, we determine that OPIK's 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

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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 OPIK's 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 establish a dispute as to a material fact. In order to preclude

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 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 the 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).
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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 identical 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 the 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

13
exchange for the gas delivered at the wellhead. As such, if the question were whether
those negotiated formulas produce an adequate price, the 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 the 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 the
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
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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 the 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, 257 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 1/8 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.

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 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 the
reasonable expenses to transport the gas to market. 215 Kan. at 331-32.

In so holding, the Sternberger 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 Sternberger court
distinguished the transportation costs at issue from the compression costs required to
make the gas marketable in Gilmore and Schupbach, reasoning:
16
 "[T]here is no evidence . . . the 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 than those of constructing a pipeline to
transport the gas to the purchaser or to a transmission pipeline." 257 Kan. at 331.

The Sternberger 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 nonworking interest owners. . . . 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." 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 Sternberger were also required to deliver the gas to the purchaser, yet they were not

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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 the 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
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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 the 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.

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 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.

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