

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
 

 
                                                                  O
P I N I O N
            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.
            Appellees[1]
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
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 CO2
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.
            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.
 
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.
            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
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.
            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 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.
            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 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.  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 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
Panel[2]
consists of: Wright, C.J.,
McCall, J., and
Hill.[3]
 




[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]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. 


