OPINION
JIM R. WRIGHT, Chief Justice.
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
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 C02 tertiary recovery operation in order to enhance the production from the Unit. The recovery operation involved injecting C02 purchased from Kinder Morgan C02 Company into the Unit wherein, generally stated, the C02 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 C02 — 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 C02 is extracted from the stream, as well as two-thirds of the natural gas liquids (NGLs). The extracted C02 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% C02. The remaining gas stream and separated NGLs are sent to the Snyder Gas Plant (SGP) where the remaining C02 is extracted, the NGLs are stabilized, and the stream is processed for sale. The C02 extracted at the SGP is also sent back to the Unit for reinjection.
In order to initiate this C02 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-ldnd 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 25c 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. Nations Bank,
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 C02 project— the transportation of the C02-laden stream fifteen miles to Cynara and then to the SGP, the extraction of C02 at both places, and the return of the C02-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 ap-pellees.
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 fact-finder 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
As
sets, 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 casing-head 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 (l/8th) of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth (l/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] l/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 80% 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. Cemosek,
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% C02 that would exist but for the injection of the C02 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 C02 content as a result of a C02 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 C02 as a result of a C02 tertiary recovery operation. The consideration of contracts for sale of gas with high C02 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 C02 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 C02 content; instead, it is a contract for the
processing of the gas stream after the bulk of the C02 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 Cy-nara. 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, appel-lees 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 C02 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 post-production 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] l/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 cas-inghead 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 C02 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 C02 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<e 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 ap-pellees’ 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 C02 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 C02 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 Cog-dell 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 ap-pellees take nothing.