Court Opinion

ID: 3083146
Source: CourtListenerOpinion
Date Created: 2015-10-16 02:16:58.165963+00
Date Added: 2024-06-11T09:51:04.287423
License: Public Domain

Opinion filed October 31, 2012

                                            In The

   Eleventh Court of Appeals
                                          __________

                                    No. 11-10-00282-CV
                                        __________

                      OCCIDENTAL PERMIAN LTD., Appellant

                                               V.

                  MARCIA FULLER FRENCH ET AL., Appellees

                          On Appeal from the 132nd District Court

                                     Scurry County, Texas

                                 Trial Court Cause No. 22397

                                         OPINION
       This is a suit to recover certain royalty payments under two leases. Marcia Fuller French
and other royalty owners sued Occidental Permian Ltd., the operator of the Cogdell Canyon Reef
Unit, and alleged that Occidental had underpaid royalties due under the leases. Following a
nonjury trial, and after the trial court refused to allow the royalty owners’ request to reopen to
present evidence of market value, the trial court rendered judgment for the royalty owners. We
reverse and render.
         Appellees1 are royalty owners under two separate oil and gas leases covering lands in
Scurry and Kent Counties. Both leases are subject to a unitization agreement; appellant’s
predecessor, as lessee of both leases, was a party to the unitization agreement. Appellant is the
current lessee under the leases and is the operator of the Unit pursuant to the terms of the
unitization agreement. Appellant is the only party against whom recovery has been sought in
this lawsuit.
         Following the decline of production in the Unit, in 2001, appellant initiated a CO2 tertiary
recovery operation in order to enhance the production from the Unit. The recovery operation
involved injecting CO2 purchased from Kinder Morgan CO2 Company into the Unit wherein,
generally stated, the CO2 mixes with the oil in the reservoir and thereby causes more oil to be
produced. A result of this type of recovery operation is that the well produces, along with the
oil, casinghead gas that, in addition to impurities normally associated with production in the
absence of this type of operation, is heavily laden with CO2—in this instance about 85% of the
casinghead gas stream.
         After the casinghead gas stream from the Unit is measured, Kinder Morgan takes
possession of the stream and transports it fifteen miles to its Cynara facility. At Cynara, the
stream is processed and a majority of the CO2 is extracted from the stream, as well as two-thirds
of the natural gas liquids (NGLs).                 The extracted CO2 is then sent back to the Unit for
reinjection. As a result of the activities at Cynara, the remaining stream is composed of not more
than 10% CO2. The remaining gas stream and separated NGLs are sent to the Snyder Gas Plant
(SGP) where the remaining CO2 is extracted, the NGLs are stabilized, and the stream is
processed for sale. The CO2 extracted at the SGP is also sent back to the Unit for reinjection.
         In order to initiate this CO2 tertiary recovery operation, appellant entered into a Treating
and Processing Agreement with Kinder Morgan, which covered all of the gas produced from the
Unit. In the contract, appellant agreed to pay Kinder Morgan two types of fees each month:
(1) a monetary fee and (2) an “in-kind” fee. The monthly monetary fee has decreased over time

         1
            Appellees are Marcia Fuller French; Gillian Fuller; French Capital Partners, Ltd.; Lesa Oudt; Connie Delle Cogdell,
individually and as trustee of the David M. Courtney Trust, and as trustee of the John Cogdell Courtney Trust; John Courtney,
trustee of the Carol C. Courtney Disclaimer Trust; Penny Cogdell Carpenter, individually and as co-independent executor of the
Estate of William Munsey (“Billy”) Cogdell and as co-trustee of the Cogdell Marital Trust; Billy Rank Cogdell, individually and
as co-independent executor of the Estate of William Munsey (“Billy”) Cogdell and as co-trustee of the Cogdell Marital Trust;
Dick Munsey Cogdell, individually and as co-independent executor of the Estate of William Munsey (“Billy”) Cogdell and as co-
trustee of the Cogdell Marital Trust; Jim David Cogdell; and Happy State Bank and Trust Company, as trustee for the Martha
Ann Cogdell Hospital Trust.

                                                              2
as Kinder Morgan has recovered its cost of capital for certain investments; the fee is not charged
against royalty owners. The in-kind fee amounted to 30% of the NGLs and 100% of the residue
gas extracted from the casinghead gas stream produced from the Unit. Because no royalty is
paid on this in-kind fee, the in-kind fee is, in effect, deducted in calculating royalty payments.
       The contract also required Kinder Morgan to enter into a Gas Processing Agreement with
Torch Energy Marketing, Inc., the operator of the SGP. The contract required the SGP to
complete the activities described above.       For these services, Kinder Morgan would pay a
processing fee of 25¢ per mcf of the gas entering the SGP. Beginning in 2006, this fee escalated
annually. Kinder Morgan received 100% of the residue gas and 100% of the NGLs—70% of the
NGLs were to be allocated to appellant pursuant to the terms of appellant’s contract with Kinder
Morgan described above.
       The royalties paid by appellant are based on the NGL proceeds appellant received from
Kinder Morgan under their agreement. Thus, because the in-kind fee is assigned to Kinder
Morgan as compensation under appellant’s contract with Kinder Morgan, appellant paid royalties
on 70% of the NGLs produced from the Unit and did not pay any royalties on the residue gas.
Royalty is commonly defined as the landowner’s share of production, free of expenses of
production. Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121–22 (Tex. 1996). Although
it is not subjected to the costs of production, royalty is usually subjected to postproduction costs,
including taxes, treatment costs to render the hydrocarbons marketable, and transportation costs.
Id. at 122. However, the parties may modify the general rule by agreement. Id.
       At trial, appellees argued, and the trial court agreed, that the entire CO 2 project—the
transportation of the CO2-laden stream fifteen miles to Cynara and then to the SGP, the
extraction of CO2 at both places, and the return of the CO2-permeated stream to the Unit for
reinjection—was all a production activity. That a bulk of the NGLs ultimately produced was
also separated from the casinghead gas stream at Cynara was “merely incidental to this overall
production process.” The deduction of the in-kind fees paid by appellant to Kinder Morgan
(100% of the residue gas and 30% of the NGLs) improperly imposed part of the expenses of
production upon appellees.      The trial court concluded that, because appellant did not pay
royalties on 100% of the NGLs and residue gas ultimately produced from the Unit, appellant
underpaid its royalty obligations.

                                                  3
       In Issues Two, Three, and Five, appellant challenges the legal and factual sufficiency of
the evidence offered to show that appellant underpaid royalties owed to appellees.
       In an appeal from a bench trial, the trial court’s findings of fact have the same force and
effect as jury findings. Anderson v. City of Seven Points, 806 S.W.2d 791, 794 (Tex. 1991). We
review a trial court’s findings of fact under the same legal and factual sufficiency of the evidence
standards that we use when we determine whether sufficient evidence exists to support an answer
to a jury question. Kennon v. McGraw, 281 S.W.3d 648, 650 (Tex. App.—Eastland 2009, no
pet.). When we review evidence for legal sufficiency after a bench trial, we consider all of the
evidence in the light most favorable to the trial court’s judgment. We credit any favorable
evidence if a reasonable factfinder could and disregard any contrary evidence unless a reasonable
factfinder could not. City of Keller v. Wilson, 168 S.W.3d 802, 821–22 (Tex. 2005). In a factual
sufficiency review, we consider all the evidence and will uphold the trial court’s finding unless
the evidence is too weak to support it or the finding is so against the overwhelming weight of the
evidence as to be manifestly unjust. Serv. Corp. Int’l v. Aragon, 268 S.W.3d 112, 118 (Tex.
App.—Eastland 2008, pet. denied).
       We review a trial court’s conclusions of law de novo. BMC Software Belgium, N.V. v.
Marchand, 83 S.W.3d 789, 794 (Tex. 2002). We independently evaluate conclusions of law to
determine whether the trial court correctly drew the legal conclusions from the facts. Walker v.
Anderson, 232 S.W.3d 899, 908 (Tex. App.—Dallas 2007, no pet.). We will uphold the trial
court’s conclusions of law if any legal theory supported by the evidence can sustain the
judgment. OAIC Commercial Assets, L.L.C. v. Stonegate Vill., L.P., 234 S.W.3d 726, 736 (Tex.
App.—Dallas 2007, pet. denied). We will reverse the judgment of the trial court only if the
conclusions are erroneous as a matter of law. Id.
       In this case, there are two different leases controlling the payment of royalties—the Fuller
Lease and the Cogdell Lease. The gas royalty provision of the Fuller Lease provides the
following:
              4. The royalties to be paid lessor are: . . . (b) on gas, including casinghead
       gas or other gaseous substance produced from said land and sold or used off the
       premises or in the manufacture of gasoline or other product therefrom, the market
       value at the well of one-eighth (1/8th) of the gas so sold or used, provided that on
       gas sold at the wells the royalty shall be one-eighth (1/8th) of the amount realized
       from such sale.

                                                 4
The gas royalty provision of the Cogdell Lease provides the following:
               3. The lessee shall pay to the lessor for gasoline or other products
       manufactured and sold by the lessee from the gas produced from any oil well, as
       royalty, [one-fourth] 1/4 of the net proceeds from the sale thereof, after deducting
       cost of manufacturing the same. If gas is sold by the lessees, the lessor shall
       receive as royalty [one-fourth] 1/4th of the market value at the field of such gas.

Additionally, the unitization agreement prohibits imposing any part of the cost of production
operations on the royalty owners:
               22. No part of the costs and expenses incurred in the development and
       operation of the unit area, including secondary recovery and pressure maintenance
       costs, shall be charged to any royalty owner unless such royalty owner is already
       obligated to pay such costs or expenses by the terms of other agreements. Such
       costs and expenses shall be borne by the working interest owners as provided in
       the Unit Operating Agreement.

       The key dispute we must resolve is whether the evidence sufficiently shows that
appellant underpaid royalties by deducting the in-kind fees from its royalty calculation.
       It is commonly understood that a royalty is a share of production that is free from the
expenses of production. Heritage, 939 S.W.2d at 121–22. This concept is exemplified in the
quoted portion of the unitization agreement above. Whereas the amount of the royalty may not
be reduced by production costs, postproduction costs are typically deducted prior to calculating
royalty.   Id. at 122.    Postproduction costs include taxes, treatment costs to render the
hydrocarbons marketable, and transportation costs. Id.
       Appellees contend that this case is unlike virtually all other reported cases in that
appellees do not challenge the value of the royalty payments but, rather, claim the volume of
production on which appellant pays royalties is deficient. As described above, because of the in-
kind fee of 30% of the volume of NGLs and 100% of the residue gas produced from the Unit
(part of the consideration paid to Kinder Morgan by appellant under their contract), appellant
only pays royalties to appellees on 70% of the NGLs produced, saved, and sold from the gas
produced from the Unit and on none of the residue gas remaining after separation of the NGLs.
Appellees argue that the in-kind fee is not chargeable to appellees because it is a payment made
for production operations. Their assertion that, because royalties were not paid based on 100%
of the volume of NGLs and 100% of the residue gas, appellant breached its royalty obligations.

                                                 5
       However, in order to determine whether appellant breached its royalty obligations, we
must first look to the clauses in the leases under which those obligations arise. Tana Oil & Gas
Corp. v. Cernosek, 188 S.W.3d 354, 360 (Tex. App.—Austin 2006, pet. denied); see Heritage,
939 S.W.2d at 121.
       Under the Fuller Lease, royalties are to be determined based on the “market value at the
well.” As we stated in Carter v. Exxon Corp., 842 S.W.2d 393, 397 (Tex. App.—Eastland 1992,
writ denied), “‘At the well’ designates the point in the gas production process where market
value is to be calculated.” Market value is simply the price a willing seller obtains from a
willing buyer. Heritage, 939 S.W.2d at 122. At trial, the burden is on the plaintiff to prove
market value at the well. Id. This may be done in one of two ways: (1) through the comparable
sales method or (2) when comparable sales are not readily available, through the net-back
method. Id.
       In its findings, the trial court found that “[t]he market value of NGLs per gallon for
royalty purposes is the value per gallon paid to [appellant] by Kinder Morgan.” “The market
value of the [Unit] residue gas is its value ‘at the well.’” The trial court then reasoned that “[t]he
best evidence of the market value of the native [Unit] gas stream”—a hypothetical stream at the
well containing less than 2% CO2 that would exist but for the injection of the CO2 during the
tertiary recovery operation, not the casinghead gas stream that actually is measured at the well—
“is the value received by Kinder Morgan under the [Kinder Morgan/Torch] Contract, under
which Kinder Morgan receives 100% delivery of both NGLs and residue gas at the tailgate of the
SGP, for which it pays the SGP a 25¢ processing fee (escalated annually and now approximately
32¢).” In its determination of how to compensate appellees for the alleged underpayment of
royalties, the court found that “the best measure of the value of these NGLs and residue gas is
the terms of the [Kinder Morgan/Torch Contract], less the agreed processing fee, calculated at
the values used by [appellant] for NGL royalty payments and Kinder Morgan for the value of the
residue gas at the SGP.”
       We have reviewed the record to determine whether the market value at the well found by
the trial court is supported by evidence under the comparable sales method.               Under the
comparable sales method, the sale price is compared to other sales that are “comparable in time,
quality, quantity, and availability of marketing outlets.” Id. At trial, appellees’ expert Charles
Kuss was called to testify about “the market value of the native [Unit] gas[] and what a

                                                  6
reasonably prudent operator could expect to receive in an arm’s length, negotiated contract for
gas that’s not subject for dedication and free for sale.” He testified generally as to the usual or
typical brackets in sharing percentages to producers under a percentage-of-proceeds contract in
west Texas and offered his opinion on the market value of the casinghead gas. However, Kuss
stated that his opinion was not based on any specific gas contract in the Permian Basin as a
comparable sale but, rather, was based on his “historical knowledge in dealings in the business in
the industry.” Kuss also acknowledged that he had no experience in selling gas that had a higher
CO2 content as a result of a CO2 tertiary recovery operation than it initially had in the ground.
       After reviewing the record, we hold that the trial court’s findings on the market value are
not supported by any evidence under the comparable sales method. As stated above, “[a]
comparable sale is one that is comparable in time, quality, quantity, and availability of marketing
outlets.” Id. Here, the record contains no evidence of any specific sales, much less any specific
sales of gas heavily laden with CO2 as a result of a CO2 tertiary recovery operation. The
consideration of contracts for sale of gas with high CO2 content like that present in the
casinghead stream from the Unit is “a material step in the quality analysis required by the
comparable sales” method. Occidental Permian Ltd. v. Helen Jones Found., 333 S.W.3d 392,
406–07 (Tex. App.—Amarillo 2011, pet. denied).             The percentage-of-proceeds estimates
provided by Kuss were not supported by any identified contracts and, thus, are meaningless. See
id. at 405. Kuss stated that his opinion was based on his previous experience; however, he stated
that he did not have any experience in selling gas with a similar CO2 content as that at issue here.
As such, combined with the lack of any identified contracts to support his opinion, we conclude
that his opinion amounts to no evidence under the comparable sales method. See id. at 406–07.
       In their brief, appellees contend that the actual sales value of the gas at issue as set forth
in the Kinder Morgan/Torch Contract is a perfect comparable sale and that, therefore, the trial
court properly found it to be “[t]he best evidence of the market value of the native [Unit] gas
stream.” Even if only one contract could be sufficient evidence under the comparable sales
method, the contract between Kinder Morgan and Torch is not sufficient because it is not a
contract for sale of gas at the well. This contract amounts to no evidence under the comparable
sales method because it is not a contract for sale of gas with high CO2 content; instead, it is a
contract for the processing of the gas stream after the bulk of the CO2 has been stripped at
Cynara.

                                                 7
       Having concluded that no evidence exists to support the trial court’s determination of
market value at the well, we next must examine whether that value is supported by evidence
under the net-back method.        We do so without deciding whether appellees proved that
information about comparable sales was not readily available. See Heritage, 939 S.W.2d at 123.
The net-back method “involves subtracting reasonable post-production marketing costs from the
market value at the point of sale.” Id. at 122.
       As noted above, the trial court found that “the best measure of the value of [the] NGLs
and residue gas is the terms of the [Kinder Morgan/Torch] Contract [100% NGLs/100% residue
gas split], less the agreed processing fee, calculated at the values used by [appellant] for NGL
royalty payments and Kinder Morgan for the value of the residue gas at the SGP.” Appellees
contend that this formula properly supports the determination of market value at the well under
the net-back method. The processing fee, they claim, accounts for the postproduction activities
of the costs of transportation from the well to the SGP and the processing at the SGP, and
therefore was deducted from the net sales values at which the NGLs and residue gas were sold in
order to arrive properly at the market value at the well under the net-back method.
       Appellant argues that appellees’ net-back analysis is incorrect because it fails to subtract
the costs of any activities at Cynara. We agree. In order for us to hold otherwise would require
that we agree with appellees’ contention that all of the activities that take place at Cynara are
properly classified as production, the cost of which is not chargeable to royalty owners. We do
not. As stated above, appellees bore the burden of proving market value at the well. Id.
Appellees’ damage models included values of NGLs and residue gas at the tailgate of the SGP,
with the costs of transportation from the well to the SGP and processing at the SGP netted out by
deducting the SGP processing fee. They claim that the net-back of the prices at the SGP tailgate
by deducting this fee brings the value of the native Unit gas back to the gas value at the well.
However, this assumes that the only allowable postproduction costs that may be deducted are the
costs for the activities at the SGP and none at Cynara. Because appellees contend that all of the
activities that take place at Cynara are production activities, they did not offer any evidence
allocating the costs for the various activities that take place at Cynara. Therefore, if any of the
activities that take place at Cynara are postproduction activities, there is no evidence in the
record to support the market value at the well under the net-back method because there are some

                                                  8
postproduction costs that have not been deducted, and we could not ascertain those costs from
the record. See id. at 123.
       In addition to the separation of the majority of the CO2 from the casinghead gas stream,
the following also occur at Cynara: compression, dehydration, separation of hydrogen sulfide,
separation of two-thirds of the total created NGLs, and transportation of the remaining stream
and NGLs to the SGP. Appellant does not dispute that production activities, which are not
properly chargeable to royalty owners, occur at Cynara; however, appellant argues that the
record contains no evidence that the monetary fee paid to Kinder Morgan, which is not charged
against royalties, does not cover the cost of all of the production activities. Thus, appellant
argues, there is no evidence that it underpaid royalties.
       In Cartwright v. Cologne Production Co., 182 S.W.3d 438 (Tex. App.—Corpus Christi
2006, pet. denied), the court addressed whether the operators there improperly deducted the costs
of treating and compressing the produced gas from royalties. One of the activities that the
operators charged against royalty was the removal of hydrogen sulfide. Id. at 442–43. The trial
court granted the operators’ summary judgment motion that no genuine issue of material fact
existed regarding the operator entitlement to deduct postproduction marketing expenses. The
Corpus Christi court held that the trial court did not err when it granted the summary judgment
motion because the operators were entitled to deduct compression and treatment costs, which
included the removal of hydrogen sulfide, in computing gas royalties owed to lessors. Id. at 446.
In reaching this decision, the court discussed the general rule in Texas that production costs are
not chargeable to royalty interest owners. Id. at 444–45. Additionally, it provided, “Whatever
costs are incurred after production of the gas or minerals are normally proportionately borne by
both the operator and the royalty interest owners. These postproduction costs include taxes,
treatment costs to render the gas marketable, compression costs to make it deliverable into a
purchaser’s pipeline, and transportation costs.” Id. (citation omitted).
       We agree with the Corpus Christi court that the removal of hydrogen sulfide from the
casinghead gas stream is a postproduction activity done to render the stream marketable.
Because the costs of separating the hydrogen sulfide were not deducted in the trial court’s
determination of market value at the well under the net-back method, we hold, without even
addressing the other activities at Cynara, that the evidence does not support the trial court’s
determination of market value.

                                                  9
       The trial court found that both the monetary and in-kind fees paid by appellant to Kinder
Morgan cover all of the services provided by Kinder Morgan and that neither is “allocable to any
of the many services provided by Kinder Morgan, or between production and post-production
expenses.” However, appellees had the burden of proving the market value at the well under the
net-back method. Heritage, 939 S.W.2d at 122. To do so, they were required to subtract
reasonable postproduction costs from the market value at the point of sale. Id. Appellees’ expert
Wayman Gore testified that, if he “had the information on which to make a reasonable
allocation” of the costs of the various services, he could do so. Appellees failed to offer
evidence to show that the costs of all postproduction activities had been deducted; therefore, the
trial court’s determination of the market value at the well was in error. Because neither method
of proving market value at the well is properly supported by evidence, the evidence is not
sufficient to show that appellant underpaid royalties under the Fuller Lease.
       We next turn to the Cogdell Lease.         Under the Cogdell Lease, royalties are to be
determined based on “the net proceeds from the sale . . . , after deducting cost of manufacturing.”
“If gas is sold by the lessees, the lessor shall receive as royalty [one-fourth] 1/4th of the market
value at the field of such gas.” “‘Proceeds’ or ‘amount realized’ clauses require measurement of
the royalty based on the amount the lessee in fact receives under its sales contract for the gas.”
Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008).
       We have already held that, at least, the removal of hydrogen sulfide from the casinghead
gas stream is a postproduction activity done to render the stream marketable. Because we have
held that it is necessary to render the stream marketable, we also hold that it is a cost of
manufacturing that must be deducted in order to determine the net proceeds from the sale, and
thus the royalty, under the Cogdell Lease. Because the trial court’s royalty calculation does not
include the deduction of the cost of the removal of hydrogen sulfide, we hold that the evidence is
insufficient to prove that appellant underpaid royalties under the Cogdell Lease.
       Appellant’s Issues Two, Three, and Five, concerning whether the evidence sufficiently
showed that appellant underpaid royalties under the Fuller and Cogdell Leases, are sustained. In
appellant’s first issue, it argues that the CO2 separation activity is a postproduction activity, the
cost of which is properly shared with royalty owners, because the separation activity is necessary
to obtain marketable products from the casinghead gas. Because we have held that the evidence
is insufficient to prove that appellant underpaid royalties, we do not need to decide and do not

                                                 10
decide appellant’s first issue concerning whether any or all of the costs of separating CO2 from
the casinghead gas stream is a postproduction expense. TEX. R. APP. P. 47.1.
       In his fourth and sixth issues, appellant contests the trial court’s conclusion that appellant
breached an implied duty to market. In the fourth issue, appellant challenges part of the trial
court’s conclusion of law that provides that appellant “has an implied duty to market gas
production from the [Unit] as a reasonably prudent operator” and that appellant breached this
duty. Specifically, appellant challenges whether Texas law recognizes an implied duty to market
in a market-value lease. Appellant contends that Texas law does not. We agree. In Bowden, the
Texas Supreme Court recognized its conclusion in two of its previous cases that a duty to market
cannot be implied in a market-value case. 247 S.W.3d at 701. In one of the previous cases, the
court explained its reasoning as follows, “Because [a market-value] lease provides an objective
basis for calculating royalties that is independent of the price the lessee actually obtains, the
lessor does not need the protection of an implied covenant.” Yzaguirre v. KCS Res., Inc., 53
S.W.3d 368, 374 (Tex. 2001).       To the extent that the trial court concluded that appellant
breached an implied duty to market under the Fuller Lease, appellant’s fourth issue is sustained.
       Appellant’s sixth issue challenges the legal and factual sufficiency of the evidence that
appellant violated the duty to market implied in the Cogdell Lease. The Texas Supreme Court
has recognized that a duty to market may be implied in some “proceeds” leases. Bowden, 247
S.W.3d at 701. “‘[T]he standard of care in testing the performance of implied covenants by
lessees is that of a reasonably prudent operator under the same or similar facts and
circumstances.’” Id. at 699 n.4 (quoting Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 567–
68 (Tex. 1981)).
       The trial court held that the 25¢ per mcf processing fee covered all postproduction
expenses. Therefore, the trial court concluded that, by deducting the in-kind fee paid to Kinder
Morgan from its royalty payments and thus forcing the royalty owners to bear a portion of the
expenses of production, appellant breached the implied duty to market because it obtained for
itself a financial benefit that was not shared with the royalty owners. In other words, the trial
court’s conclusion, and appellees’ argument, is based on the supposition that appellant was not
entitled to the benefit of passing on any of the costs of the activities at Cynara because this
breached the royalty clauses of the respective leases. We have already held that the evidence at
trial was insufficient to show that appellant breached its obligations under the royalty clauses.

                                                11
However, we still must examine the evidence in order to determine whether there is sufficient
evidence to support the trial court’s conclusion that appellant breached the implied duty to
market under the Cogdell Lease.
       At trial, appellees asked Kuss the following: “In your opinion would a reasonably prudent
operator having in mind the interest of the lessor and the lessee accept this 70/0 split under a
POP contract or a gas processing agreement for the native gas available at [Unit] Central Tank
Battery 1?” Kuss responded, “No.” In this question, when appellees’ counsel referred to “native
gas,” he was referring to the casinghead gas with the injected CO2 stripped out of the quantity
and quality. Appellant objected to the use of this term on the ground that there was no native gas
available at the well that met those qualities because, at that point, the produced gas still included
the CO2 and other impurities. Appellees also asked, “Mr. Kuss, with respect to your opinions
under POP contracts, what POP contract in your opinion would a reasonably prudent operator
having in mind the interest of the lessor and lessee obtain for the native [Unit] gas at [the well]?”
Kuss answered, “I would say an 85 percent of proceeds to the producer would be reasonable --
what a reasonably prudent operator could receive for gas for sale at that point, or the 100/100 gas
processing agreement. Either one of those would be reasonable. I would give weight to the gas
processing agreement, because it covers the exact gas we’re talking about.” This is inapposite
here because the testimony does not address the casinghead gas that is actually produced at the
well. “An expert’s opinion might be unreliable, for example, if it is based on assumed facts that
vary from the actual facts, or it might be conclusory because it is based on tests or data that do
not support the conclusions reached.” Whirlpool Corp. v. Camacho, 298 S.W.3d 631, 637 (Tex.
2009) (citation omitted). Because the testimony is based on a hypothetical “native gas” that is
free from impurities rather than the actual casinghead gas stream that is produced at the well, we
conclude that Kuss’s opinion on this issue amounts to no evidence. Thus, based on our review of
the record and our previous holdings, we hold that the evidence is insufficient to show that
appellant breached the implied duty to market under the Cogdell Lease. Appellant’s sixth issue
is sustained.
       In addition to the award of damages for breach of the royalty provisions and the implied
duty to market, the court also awarded appellees attorney’s fees and entered a declaratory
judgment ordering appellant to pay royalties on future production in compliance with the
respective leases and in the same fashion as embodied in the trial court’s judgment for past

                                                 12
production. In its seventh and eighth issues, appellant challenges the award of attorney’s fees
and the grant of declaratory relief. Because both awards were based on alleged contractual
breaches, which we have now held to be unsupported by evidence, we also hold that the award of
attorney’s fees and declaratory relief were improper. See TEX. CIV. PRAC. & REM. CODE ANN.
§§ 37.004(b), 38.001 (West 2008). Appellant’s seventh and eighth issues are sustained.
         The judgment of the trial court is reversed, and we render judgment that appellees take
nothing.

                                                                                  JIM R. WRIGHT
                                                                                  CHIEF JUSTICE

October 31, 2012
Panel2 consists of: Wright, C.J.,
McCall, J., and Hill.3

         2
           Eric Kalenak, Justice, resigned effective September 3, 2012. The justice position is vacant pending appointment of a
successor by the governor or until the next general election.
         3
             John G. Hill, Former Chief Justice, Court of Appeals, 2nd District of Texas at Fort Worth, sitting by assignment.

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