Samson Lone Star, Ltd. Partnership v. Hooks

389 S.W.3d 409, 177 Oil & Gas Rep. 542, 2012 Tex. App. LEXIS 4353, 2012 WL 1951113

• Court: Court of Appeals of Texas
• Decided: May 31, 2012
• Docket: No. 01-09-00328-CV
• Status: Published

Opinions

OPINION ON REHEARING

EVELYN V. KEYES, Justice.

Following the issuance of our March 1, 2012 opinion and judgment on rehearing, appellant, Samson Lone Star, Limited Partnership n/k/a Samson Lone Star L.L.C. (“Samson”), moved for further rehearing on issues relating to the supersede as bond and surety. Appellees, Charles G. Hooks, et al. (“the Hooks”), moved for further rehearing asking this Court to clarify its ruling regarding post judgment interest. Subsequently, on April 16, 2012, the Hooks moved for en banc reconsideration of our March 1, 2012 opinion. We grant both motions for rehearing, withdraw our opinion and judgment of March 1, 2012, and issue this opinion and judgment in their stead. We dismiss the Hooks’ April 16, 2012 motion for en banc reconsideration as moot.²

This is an appeal from a final judgment against Samson for more than $21 million in favor of the Hooks. Samson has a number of oil and gas leases from landowners in Hardin and Jefferson Counties, including the Hooks. The judgment arises from an oil and gas case in which the Hooks brought suit against Samson with respect to three oil and gas leases, two in Hardin County, Texas (the “95-acre Lease” and the “10-acre Lease,” collectively the “Hardin County Leases”) and one in Jefferson County, Texas (the “Jefferson County Lease”). The Hooks sued Samson for breach of contract, fraud, fraudulent concealment, statutory fraud, negligent misrepresentation, violation of the Texas Natural Resources Code by failure to properly pay royalties, statutory negligence, common law negligence per se, injunctive relief, and declaratory judgment.

The trial court granted Samson’s motion for partial summary judgment on whether it had breached certain offset obligations under the Leases. It also granted the Hooks’ motions for summary judgment on claims for additional royalties related to their claims of “unpooling” with respect to the Hardin County Leases and breach of the “most favored nations” clause in both Hardin County Leases and the Jefferson County Lease.

The questions of whether Samson committed fraud against the Hooks with respect to a well drilled within the buffer zone of the Hooks’ Jefferson County Lease and whether it underpaid royalties by not paying royalties for “formation production” in all three Leases were tried to a jury. The trial court rendered judgment on the verdict, holding Samson liable to the Hooks for fraud and underpaid royalties, and it entered a final judgment that left intact the summary judgment in Samson’s favor on offset obligations and the summary judgments in favor of the Hooks on their unpooling claim and their most favored nations clause claims. Samson has appealed the final judgment, and the Hooks have cross-appealed.

In eight issues, Samson complains that (1) there is legally and factually insufficient evidence of common law fraud; (2) there is legally and factually insufficient evidence of statutory fraud; (3) the statute of limitations bars the Hooks’ fraud claims; (4) there is legally and factually insufficient evidence to support the jury’s finding on fraud damages; (5) the trial court erred in interpreting the phrase “formation production” in the Hooks’ Leases as requiring Samson to pay twice for molecules of gas produced as condensate; (6) the trial court erred in entering judgment in favor of the Hooks for additional royalties based on the unpooling issue with respect to the Hardin County Leases and on the most favored nations clauses in all three Leases; (7) the trial court erred in elevating lease provisions into a permanent injunction, and there is no evidence to support the injunction or attorney’s fees; and (8) the trial court erred by granting post-judgment interest at the rate of 18%, compounded annually.³

In a single issue, the Hooks complain on cross-appeal that the trial court erred in rendering summary judgment in favor of Samson on the issue of whether Samson breached certain offset obligations in the Hooks’ leases. We affirm the trial court’s summary judgment order in favor of Samson on its offset obligations.

With respect to Samson’s appeal, we affirm the portion of the trial court’s judgment awarding the Hooks reimbursement for ad valorem taxes as stipulated by the parties, and we reverse the remainder of the final judgment of the trial court and render judgment that the Hooks take nothing on those claims.

I. SAMSON’S APPEAL

A. BACKGROUND

1. The Hooks’ Jefferson County Lease and the BSM No. 1 Unit

In 1999, the Hooks entered into the Jefferson County Lease with Samson. This lease covered 640 acres owned by the Hooks in the Dyches survey in Jefferson County, Texas and was bordered by Pine Island Bayou, which also serves as the county line between Jefferson and Hardin Counties.

Article VI of the Jefferson County Lease was a section called “Offset Obligations.” In this section, Samson covenanted to operate the leased premises as a reasonably prudent operator would and to protect the leased premises from drainage. Article VI also contained specific obligations for Samson in case of potential drainage. This Article provided that if a gas well were completed within 1,320 feet from the leased premises, then, within 90 days from the date of the sale of first production from that well, Samson must take one of three actions: (1) drill an offset well; (2) pay the Hooks “compensatory royalties” — in addition to any royalties currently due — in a sum equal to the royalties that would be payable under the Lease on the production from the adjacent or nearby producing well as if it had been producing on the leased premises; or (3) release the offset acreage.⁴ The Jefferson County Lease did not provide for pooling.

In April 2000, Samson began drilling a gas well, the Black Stone Minerals No. 1 (the “BSM No. 1 well”), on a tract it owned in Hardin County adjacent to the Hooks’ 640-acre Jefferson County Lease. This adjacent tract was located in Hardin County. The surface drillsite was outside the 1,320-foot buffer zone around the Hooks’ Jefferson County Lease that triggered Samson’s offset obligations under Article VI(A) of the Lease. However, the well was a directional well that slanted away from the surface drillsite. Originally, the BSM No. 1 well was planned with a bottom hole location 1,080 feet from the Hooks’ lease line on the east, a location within the 1,320-foot buffer zone of the Hooks’ Jefferson County Lease. This proposed well location was reflected on a plat titled “Proposed Well Location [BSM No.]l Walker Pettitt League, A-43, Hardin County, Texas,” which was prepared and signed by a third-party surveyor on March 22, 2000. The surveyor certified that “this is a true and correct plat based on a ground survey made under my supervision on March 22, 2000.” This plat was filed with the Railroad Commission of Texas (“Railroad Commission”).

The March 22, 2000 plat showed a 704-acre gas pooling unit (the “BSM No. 1 unit”) designated by Samson that ran along Pine Island Bayou, the Hardin County/Jefferson County line, on the east. This line was also the western boundary of the tract containing the Hooks’ Jefferson County Lease. The Hooks and their co-owners of the tract on which their Jefferson County Lease was located were not named as lessors in the table shown on the plat of the designated unit. An arrow shown on the plat pointed to the location of the proposed bottom hole about at the beginning of a line that ran to the eastern line of the unit at Pine Island Bayou, the county line. Notations on the plat stated: The Proposed Surface Location is:

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The Proposed Bottom Hole Location is: 330' FSL x 330' FEL Survey 870'± Scaled FSL x 1080'± Scaled' FEL Unit.

It is undisputed that “FSL” meant “From the Southern Line” of the Walker Pettitt Survey, “FNL” meant “From the Northern Line” of the Survey, and “FEL” meant “From the Eastern Line” of the Survey, which was the Hardin County/Jefferson County line at Pine Island Bayou. Thus, in this notation, the surface location of the BSM No. 1 well was 1,600 feet from the eastei’n line of the survey at Pine Island Bayou, and the proposed bottom hole location was about 1,080 feet from the eastern line, which marked the western line of the Hooks’ Jefferson County Lease. The proposed bottom hole was therefore within the 1,320-foot buffer zone for the Jefferson County Lease.

Although the March 22, 2000 plat of the designated BSM No. 1 unit estimated the location of the proposed bottom hole location of the BSM No. 1 well, the exact bottom hole location of the well, following drilling, could only be ascertained from a directional survey. This survey was completed in July 2000 and was also filed with the Railroad Commission. Both parties agree that the survey showed the BSM No. 1 well to be bottomed 1,184 feet from the Hooks’ Jefferson County Lease, within the 1,320-foot buffer zone of the Lease. Thus, Samson had an obligation under the terms of the “Offset Obligations” in the Hooks’ Jefferson County Lease to (1) drill an offset well, (2) pay the Hooks “compensatory royalties,” or (3) release the “offset acreage” within 90 days from the date production was first “sold, removed, or otherwise marketed” from the well.

The BSM No. 1 well was completed in August 2000, and the first gas sales occurred in late October 2000. Because the bottom hole of the well was within the 1,320-foot buffer zone of the Hooks’ Jefferson County Lease, the first gas sales triggered Samson’s offset obligations under the terms of the Lease. The Hooks complain, and the jury found, however, that Samson did not follow the provisions in Article YI(A) of the Jefferson County Lease, which provided that, within 90 days of the first sale of gas from a well within its buffer zone, Samson must drill an offset well, pay the Hooks compensatory royalties, or release the offset acreage. Instead, the jury found that Samson attempted to avoid those obligations by seeking to pool the Hooks’ interest in the production from the BSM No. 1 well with those of other mineral owners, despite the lack of pooling authority in the Jefferson County Lease, while concealing the bottom hole location of the BSM No. 1 well.

In December 2000, Samson filed a P-12 “Pooling Authority” form with the Railroad Commission that reflected a reconfigured BSM No. 1 pooling unit. By letter, Samson informed the Commission that a portion of the 704 acres in the original BSM No. 1 unit was to be put into a separate 308.41-acre pooling unit for the proposed Black Stone Minerals No. A-l well (the “BSM A-l well”). Attached to the letter was a “Certificate of Pooling Authority,” which represented the Brous-sard tract, on which the Hooks’ Jefferson County Lease lay, as one of the tracts whose mineral-rights owners either had given Samson pooling authority under an instrument currently in effect or had pooled their interests into the reconfigured BSM No. 1 unit. Also attached was a plat of the redesignated704-acre pooling unit dated November 16, 2000 and certified by Samson’s land man, Glenn Lanoue.

The arrows pointing to the surface and bottom hole locations on the November 16 plat of the redesignated BSM No. 1 unit were the same as those pointing to the proposed surface and bottom hole locations on the original March 22, 2000 plat of the unit. However, the acreage of the unit had been changed to show a different 704-acre configuration for the BSM No. 1 unit from that originally filed with the Railroad Commission. The redesignated BSM No. 1 unit, unlike the previously designated BSM No. 1 unit, extended beyond the eastern line of Hardin County at Pine Island Bayou into Jefferson County. The certificate, signed by Lanoue, stated that “this is a true and correct plat based on the best of my knowledge November 16, 2000.”

On February 15, 2001, Samson sent the Hooks a letter offering to pool 50 acres covered by the Hooks’ Jefferson County Lease into there designated BSM No. 1 gas pooling unit for the BSM No. 1 well. Attached to the letter was a copy of the plat of the reconfigured unit Samson had filed with the Railroad Commission in December 2000.

On February 20, 2001, before accepting Samson’s offer to pool — which would require amendment of Article VI of the Hooks’ Jefferson County Lease to permit pooling — Charles Hooks, the landowner and an attorney who had participated in a number of oil and gas deals, called Lanoue and sought more information. Charles Hooks inquired about the BSM No. 1 well’s location and about how his property fit in the unit. Lanoue told him that the well was about 1,500 feet away from Pine Island Bayou, the boundary between Hardin and Jefferson Counties and the western line of the Hooks’ Jefferson County Lease.

Hooks requested a plat showing where his acreage would lie within the proposed reconfigured BSM No. 1 unit. That same day, Lanoue sent Hooks the scaled plat of the redesignated BSM No. 1 pooling unit that Samson had filed with the Railroad Commission in December 2000. This plat was certified by Lanoue as “a true and correct plat based on the best of my knowledge December 28, 2000.” A number of changes had been made to the March 22, 2000 plat showing the original BSM No. 1 gas pooling unit to reflect the redesignated unit. The plat of the reconfigured unit had different boundaries extending further west and'also further east into Jefferson County, encompassing part of the Broussard tract on the east that had not been included in the original unit designation. The plat had been highlighted to show the location of the Hooks’ 50 acres east of Pine Island Bayou.

Like the March 2000 plat of the original BSM No. 1 unit, the plat of the redesignat-ed BSM No. 1 unit contained the arrow pointing to the location of the bottom hole, but it gave slightly changed coordinates from those of the proposed bottom hole of the BSM No. 1 well on the March 2000 plat. At trial, Lanoue testified that he changed these coordinates with a ruler. Also, instead of a line running from the proposed bottom hole location and showing ± 1,080 feet to the eastern line of the unit at Pine Island Bayou, the plat showed a different line to the bayou with an undesig-nated starting point. The plat also showed an eastern border of the reconfigured BSM No. 1 unit beyond the bayou and encompassing a portion of the Hooks’ Jefferson County Lease. Above the line was the designation “±1400'.” An arrow stating “BHL” and giving the well coordinates pointed to a point on the line about one quarter of the way from the western starting point of the line to the eastern end of the line at the bayou. Thus, if the designation “±1400'” were interpreted as the distance from the bottom hole to the bayou, the bottom hole of the BSM No. 1 well would be outside the 1,320 foot buffer zone for the Jefferson County Lease. However, if the “±1400'” designation were interpreted as the distance from the undesig-nated starting point of the line to the bayou and the arrow one-quarter of the way along it were interpreted as the bottom hole location, the bottom hole of the well would be within the buffer zone of the Hooks’ Lease, triggering Samson’s offset obligations under Article VI(A) of the Jefferson County Lease.

290' FSL x 740' FEL Survey 500' Scaled FNL x 1400'± Scaled' FEL Unit.

This language in the plat thus expressly stated that the bottom hole of the BSM No. 1 well was located about 1,400 feet from the eastern line of the redesignated BSM No. 1 unit, which encompassed the Hooks’ 50 acres from their Jefferson County Lease between Pine Island Bayou and the eastern edge of the redesignated unit. According to this notation, the bottom hole of the BSM No. 1 well was within 1,320 feet of the “leased premises,” and, therefore, inside the buffer zone for the Hooks’ Jefferson County Lease

Lanoue testified at trial that he added the notation that showed the bottom hole of the BSM No. 1 well to be ±1,400 feet from the eastern line of the unit in August 2000 to reflect the newly shaped unit. He also testified that he got the notation “740 feet from the east line and 290 feet from the south line” “from myself.” He did not go to the directional survey which had been previously completed to determine the exact location of the bottom hole. However, he intended the numbers to be “[a]s accurate as a land guy is using a ruler on a scaled piece of paper that might not even be to scale.”

Hooks testified at trial, however, that Lanoue orally told him that the BSM No. 1 well was 1,500 feet from Pine Island Bayou. He then looked at the plat and concluded that the bottom hole location was approximately 1,400 feet west of Pine Island Bayou and thus outside the line that would have triggered the 1,320 foot offset provisions in the Jefferson County Lease. He made no other inquiries regarding the plat or the bottom hole of the well, and he did not check the records filed with the Railroad Commission to determine the exact location of the bottom hole.

After making the pooling offer to the Hooks, Lanoue executed the designation of the BSM No. 1 pooling unit in February 2001 and recorded it in the county’s real property records on March 7, 2001, showing the Hooks as participating in the pool for the BSM No. 1 unit. However, the Hooks did not actually consent to pool the 50 acres from their Jefferson County Lease into the BSM No. 1 unit until May 25, 2001, and they conditioned their assent on a formal amendment to the lease which they were to prepare and submit to Samson. The Hooks did not prepare the formal amendment, however, and the parties never executed such an amendment. Instead, the Hooks agreed to a division order setting out their percentage distribution of the unit’s proceeds, which stated that Samson would pay the Hooks royalties based on a stated percentage of their acreage in the unit to the entire acreage of the BSM No. 1 unit unless notified otherwise in writing.

After the Hooks agreed to be included in the BSM No. 1 unit, Samson sent royalty checks to them for their unit interest continuing through the time of trial, and the Hooks cashed the royalty checks. However, the royalty checks did not include additional compensatory royalties calculated under the terms of Article VI of the Hooks’ Lease for a well drilled within the 1,320-foot buffer zone of the Hooks’ Jefferson County Lease.

After the Hooks agreed to pool 50 acres of their Jefferson County Lease into the BSM No. 1 unit, Samson drilled a second well, the Joyce DuJay No. 1 well (“DuJay No. 1 well”), within the 1,320-foot buffer zone of the Hooks’ Jefferson County Lease. That well was completed in January 2002 and made part of another pooling unit, the DuJay No. 1 unit, in which the Hooks also participated and from which they received royalties. This well was offset by the BSM No. 1 unit. Hooks testified that he was not defrauded with respect to the DuJay No. 1 unit.

2. The Hooks’ Hardin County Leases, the BSM A-l Well and Pooling Unit, and the Hooks’ “Unpooling” Claim

In addition to their Jefferson County Lease, the Hooks also owned two leases in Hardin County near the BSM No. 1 well, the 95-acre and 10-acre Hardin County Leases. Unlike the Hooks’ Jefferson County Lease, these Leases did provide for pooling in terms that were essentially the same with respect to the manner and methods of pooling.

The Hardin County Leases both contained language calling for an instrument “identifying and describing the pooled acreage” and stating that a “pooled unit shall become effective on the date such instrument or instruments are so filed for record.” Article V(E) of the pooling provision in each Lease also stated that production from any part of a pooled unit that included the leased premises was considered production from the leased premises “regardless of whether ... such production was secured before or after the date of this lease or the date of the instrument designating the pooled unit.” The 95-acre Lease provided in Article V(E) as follows:

E. Lessee [Samson], at its option, is hereby given the right and power in its discretion to pool or combine, as to any one or more formations, the land covered by this Lease or any portion of said land, insofar only as gas or gas condensate rights are concerned ... with other land, lease or leases in the immediate vicinity thereof, except to the extent and in the manner hereinafter stipulated. With respect to any such unit so formed, Lessee shall execute in writing an instrument or instruments identifying and describing the pooled acreage, and file same for recording in the office of the County Clerk in Hardin County, Texas; and the pooled unit shall become effective on the date such instrument or instruments are so filed for record. Notwithstanding anything hereof to the contrary, pooled units created hereunder and comprising all or part of the herein leased premises shall not exceed the maximum acreage figures permitted for all production units of oil or gas wells completed at certain depths under Article V hereof unless the Railroad Commission of Texas or any governmental authority having and asserting jurisdiction over the subject matter thereof prescribes for the drilling or operation of a well at a regular location, or permits for the obtaining of the maximum allowable from any well to be drilled, drilling, or already drilled, larger pooled units than any of those herein permitted, then any such pooled unit may be established or enlarged to conform to the size either required of a well or permitted for the obtaining of the maximum allowable. For any well drilled on and completed at depths beneath the surface of a tract covered by this lease there shall be no pooling with other lands, unless such tract is insufficient, due to either its lack of size or prior unitization hereunder, to comprise the maximum acreage figures permitted hereunder in which case all of said tract (95 acres more or less) or the then un-unitized portion of same shall be so pooled; and Lessee may include in such pooled unit such other acreage as may be available to comprise the maximum acreage figures permitted under the terms of this lease. For a well drilled on or completed at depths beneath the surface of lands other than the herein leased premises, not less than all (100%) of the lands (95 acres more or less) or the then un-unitized portion of same shall be so pooled; and Lessee may include in such pooled unit such other acreage as may be available to comprise the maximum acreage figures permitted under the terms of this lease.

Operations for drilling on or production of gas from any part of the pooled unit which includes all or a portion of the Leased Premises, regardless of whether such operations for drilling were commenced or such production was secured before or after the date of this lease or the date of the instrument designating the pooled unit, shall be considered as operations for drilling on or production of gas from the Leased Premises, whether or not the well or wells be located on the Leased Premises, and the entire acreage constituting such unit or units shall be treated for all purposes, except the payment of royalties on production from the pooled unit, as if the same were included in this Lease. The above right and power to pool may be exercised at any time and from time to time and before or after a well has been drilled, or while a well is being drilled. Lessee may vacate any unit formed by it hereunder by instrument in writing filed for record in said county at any time when there is no unitized substance being produced from such unit. The pooling for gas hereunder by Lessee shall also pool and unitize all liquid gas, and the royalty interest payable to Lessor thereon shall be computed the same as on gas. For the purpose of computing the royalties to which owners of royalties shall be entitled on production from each production unit, there shall be allocated to the applicable separate tract acreage included in such production unit a pro rata portion of the production produced from such production unit. Such allocation shall be on an acreage basis; that is to say, there shall be allocated to the applicable separate tract acreage within the unit that pro rata portion of the production produced from the production unit which the number of surface acres covered by such separate tract and included in the production unit bears to the total number of surface acres included in the production unit, commencing with the date of first production from the production unit.

(Emphasis added.)

In February 2001, Samson finished directionally drilling and completed the BSM A-l well north of the BSM No. 1 well on Samson’s own lease in Hardin County (the “Black Stone Minerals/FirnBank lease”). The mineral interests underlying this lease were owned 87.5% by Black Stone Minerals and 12.5% by FirnBank as cotenants.

Samson did not have the contractual authority to pool under its leases with either Black Stone Minerals or FirnBank. Samson therefore negotiated with the leaseholders for such a right and concluded that both of the lessors were in agreement. Accordingly, on March 12, 2001, Samson filed a Unit Designation for a 704-acre unit called the Black Stone Minerals “A” No. 1 Gas Unit (the “BSM A-l unit”). The BSM A-l unit designation unitized the Black Stone Minerals/FirnBank lease, as well as the Hooks’ 10-acre and 95-acre Hardin County Leases and other tracts, including leases beneath Pine Island Bayou owned by the State. The designation reflected that it was effective as of the date of first production, and it included a list of the leases pooled, including the Hooks’ Hardin County Leases. The designation for the BSM A-l unit included gas production at all depths between 6,000 and 13,800 feet, although the BSM A-l well produced gas only from the shallow EY5 formation.

FirnBank consented to be pooled into the BSM A-l Unit in May 2001. Samson also obtained written consent from the Hooks to pool their Hardin County Leases into the BSM A-l unit. In addition, it obtained the agreement of the Texas General Land Office and the School Land Board (collectively, the “State of Texas”), who owned adjacent land, to pool that land into the unit. However, Black Stone Minerals, the 87.5% owner of the mineral interests underlying the drill site, declined to consent to the pooling unit.

Samson drilled and completed the BSM A-l well, and the well began, producing in June 2001 from the depth range of the formation at the horizon from 12,304 to 12,332 feet. In December 2001, Samson finished another gas well, the DuJay No. 1 well. The DuJay No. 1 well produced from some of the same land designated to the BSM A-l unit, but it reached from 13,150 to 13,176 feet — a lower horizon than the BSM A-l well. The DuJay No. 1 well began producing in January 2002.

In February 2002, after failing to receive Black Stone Minerals’ consent to the BSM A-l pooling unit, Samson amended the BSM A-l unit designation. It executed and recorded a designation for a new unit, the Joyce DuJay No. 1 Gas unit (“DuJay No. 1 unit”) that recited an effective date as of first production of the Du-Jay No. 1 well, i.e., January 2002. The DuJay No. 1 unit designated a new, smaller, 571-acre unit with a different name, different leases, different depths and different boundaries from the BSM A-1 unit. The DuJay No. 1 unit included some of the deeper strata of the originally designated BSM A-l unit, but it excluded the EY5 horizon from which the BSM A-l well was producing at 12,304 to 12,332 feet. Instead, the designated DuJay No. 1 unit pooled its leases as to gas well production from 12,800 feet and deeper, including some already-pooled depths carved out of the BSM A-l unit (12,400-13,800 feet) and deeper strata (below 13,800 feet). Because of its depth limitations, the DuJay No. 1 unit included the DuJay No. 1 well, but not the shallower-completed BSM A-l well. The designated acreage excluded most of the Black Stone Minerals/FirnBank lease, but it included the Hooks' Hardin County Leases and the State’s leases.

Samson did not get consent from the Hooks to vacate or amend the BSM A-l unit or to “unpool” their interests from the BSM A-l unit or well. However, it informed the Hooks that the BSM A-l unit had been amended and the unit name had been changed. It stated, “Please note that the Unit Designation for the Black Stone Minerals ‘A’ No. 1 is being amended and will now be called the Joyce DuJay No. 1 unit. No additional action is needed on your part.” After the BSM A-l unit was amended, reconstituted, and renamed the DuJay No. 1 unit, Samson paid, and the Hooks accepted, royalty payments from pooled production from the DuJay No. 1 well from the date of first production until after commencement of trial in the instant case. The BSM A-l well was produced as a lease well on Samson’s Black Stone Minerals/FirnBank leases and was not included in any unit. Samson did not pay the Hooks royalties on the BSM A-l well, and the Hooks took no action to enforce any rights with respect to the original BSM A-1 unit.

Subsequently, Samson drilled another DuJay well (the “DuJay A-l well”) and created a separate pooling unit for that well. The DuJay A-l unit differed from the DuJay No. 1 unit by depth limitation and acreage. The DuJay A-l well began producing on September 25, 2002. However, Samson did not file the DuJay A-l unit designation until July 2003. The Hooks’ Hardin County Leases were likewise pooled into the designated DuJay A-l unit, and the Hooks accepted royalties on the production from that unit as well from the date of first production until after trial had begun in the instant action.

3. The Hooks’ Hardin County Leases and the “Most Favored Nation” Clause

The Hooks’ Hardin County Leases also contained a “most favored nation” clause. This clause provided that, under certain circumstances, the royalties payable to the Hooks must be elevated to match the highest royalty payable to Samson’s other lessors.

4. The Hooks’ Leases and the “Formation Production Clause”

Article III(K) of each of the Hooks’ Leases contained a “formation production clause.” Article III provided that the Hooks were to receive as royalties 25% of “the market value at the wells” on the “gas, including casinghead gas or other gaseous substances produced from said land,” or 25% of “the price received therefor by Lessee.” Likewise, they were to receive as royalties 25% of “all liquid hydrocarbons that may be produced from said land.” Article III(K) provided, “For the purposes of calculating all royalties payable under Article III herein, it is expressly provided that all such calculations shall be based on formation production as reported on Texas Railroad Commission forms P-1 and P-2.”

B. PROCEDURAL HISTORY

1. Trial Court Proceedings

In August 2004, several mineral-rights owners who had leased to Samson filed a suit against Samson styled Joyce DuJay Lee v. Samson Lone Star. The plaintiffs, who did not include the Hooks, complained about pooling issues unrelated to the BSM No. 1 well. In December 2004, other landowners, also not including the Hooks, filed a second action, styled Thomas Klorer et al. v. Samson, complaining about the same issues. In August 2005, these two actions were consolidated.

On his birthday in November 2006, Charles Hooks, as an oil and gas attorney, attended a seminar for oil and gas attorneys. There, he met an attorney who told him he was handling the Klorer and Lee eases against Samson.

On November 16, 2006, the Hooks were added to the consolidated suit in a Fifth Amended Petition. This petition alleged against Samson various breaches of contract and common law and statutory negligence related to the Hooks’ Jefferson County Lease and their two Hardin County Leases. Among other things, the Hooks claimed that Samson had breached the Jefferson County Lease by not paying compensatory royalties based on the bottom hole of the BSM No. 1 well being within 1,320 feet from their Lease. The Hooks also claimed that Samson had improperly “unpooled” the BSM A-l unit, and they sued to obtain all royalties they would have received from that unit as if all the lessors, including Black Stone Minerals, had agreed to pool, to be added to the royalties they received from the DuJay No. 1 and DuJay A-l units(the “unpooling claim”). The Hooks also asked for a declaratory judgment regarding the construction of the “most favored nations” clauses in their Leases, which they argued was triggered by a royalty paid to the State of Texas under a pooling agreement with Samson that was higher than the royalty paid to the Hooks under their pooling agreements. Finally, the Hooks sought the payment of royalties to them on “formation production” under the terms of all three Leases. The Hooks did not, however, plead any fraud claims at that time.

The Hooks added fraud, fraudulent inducement, and statutory fraud claims with respect to the Jefferson County Lease in a Sixth Amended Petition, filed on May 7, 2007. The Hooks alleged in the alternative (1) that their Jefferson County Lease had never been a part of the BSM No. 1 unit because no agreement to amend that Lease to allow pooling was entered, and, therefore, they were entitled to damages under the Lease for the loss of their rights to require Samson either to drill an offset well, pay them compensatory royalties, or release their acreage, and (2) that Samson had made false representations to them as to the configuration of the BSM No. 1 unit and the location of the BSM No. 1 well to induce them to agree to amend the Jefferson County Lease to allow a portion of it to be pooled in the BSM No. 1 well and unit(the “offset obligations claim”). They contended that Samson had falsely represented “that the [BSM No. 1] (gas) well was more than 1,320' from the nearest lease line of the Hooks Jefferson County Lease” so that its offset obligations were not triggered under the Lease. The Hooks claimed that the representations were intended to save Samson from having to pay them the substantially greater compensatory royalties that would have been payable under the terms of the Lease for infringement of the 1,320-foot buffer zone.

In September 2007, the trial court severed the consolidated action against Samson into three different actions, one of which was the Hooks’ action against Samson for fraud and breach of contract.⁵

Subsequently, the Hooks moved for partial summary judgment on several of their claims based on the terms of their Leases. The Hooks moved for summary judgment on the unpooling claim, claiming that Samson did not have authority to vacate the BSM A-l unit into which their Hardin County Leases were pooled and that, therefore, Samson had breached its lease contract by failing to pay them royalties on the BSM A-l well. The Hooks also moved for summary judgment on their most favored nation claim, formation production claim, and offset claims. They argued that Samson failed to pay them “royalties based on a greater ‘Most Favored Nations’ rate and compensatory royalties on certain offset encroaching wells.”

Samson moved for partial summary judgment on the offset obligations provision, on the formation production claims, and on the most favored nation claim. Samson also moved for summary judgment on the Hooks’ unpooling claim on the basis of limitations.

The trial court granted the Hooks’ motion for summary judgment and denied Samson’s motion on the unpooling claim. It assessed damages of $766,626.85 against Samson on the Hooks’ unpooling claim.

The trial court also granted the Hooks’ summary judgment motion on their claim for breach of the most favored nations clause in their Hardin County Leases and awarded them $848,854.01 in damages.

The trial court granted Samson’s motion for summary judgment for breach of the offset obligations provision in the Jefferson County Lease on limitations, and it denied the Hooks’ corresponding motion. The trial court also disposed of some other contract claims by other partial summary judgment motions.

In 2008, the case went to trial solely on the Hooks’ fraud claims with respect to the Jefferson County Lease and their formation production claims. The fraud claims included the Hooks’ claims that Samson’s landman, Lanoue, had made misrepresentations to them to get them to allow Samson to add their 50 acres subject to the Jefferson County Lease to the BSM No. 1 pooling unit for the BSM No. 1 well, which was within the 1,320-foot buffer zone for the Lease. The Hooks contended Samson made these misrepresentations to avoid abiding by the terms of Article VI(A) of the Jefferson County Lease, which they contended would have required Samson to drill an offset well, release their acreage, or pay them compensatory royalties, and, therefore, they were entitled to damages. The Hooks also claimed that they were entitled to additional royalties under the formation production clauses in both their Jefferson County and their Hardin County Leases.

The jury answered “yes” to the questions of whether Samson committed fraud and statutory fraud with respect to the BSM No. 1 well. It assessed damages against Samson for fraud in the amount of $20,081,638.07. The jury found that, in the exercise of reasonable diligence, the Hooks should have discovered Samson’s fraud by Charles “Hook’s Birthday April 2007.” It did not respond, however, to the questions asking for a finding, by clear and convincing evidence, that the harm to the Hooks resulted from fraud or that Samson had actual awareness of the falsity of the representations or promise that the jury had found to be fraud.⁶ Therefore, it did not award exemplary damages. The jury also did not respond to the question requesting it to “find beyond a reasonable doubt that Samson secured execution by the Hooks of a document by deception” and that the property had a value of $1,500 or more.⁷

Finally, the jury found that Samson’s failure to pay royalties based on formation production resulted in underpayment of royalties on all three of the Hooks’ Leases.

The trial court entered final judgment on the jury’s verdict, awarding the Hooks $20,081,638.07 for damages proximately caused by Samson’s fraud with respect to the BSM No. 1 well. The final judgment also reaffirmed and incorporated the trial court’s previous summary judgment rulings in favor of the Hooks. In addition to the fraud award, the judgment awarded the Hooks$766,626.85 in damages for the “unpooling” claim related to the BSM A-l well, $848,854.01 in damages for breach of the Leases’ most favored nations clause, and $52,257.22 in damages related to ad valorem taxes.⁸ Finally, the final judgment included an award of attorney’s fees, expert witness fees, costs for copies of depositions, and pre- and post-judgment interest in favor of the Hooks.

2. Claims on Appeal

Samson has appealed the judgment on the trial verdict and the partial summary judgments entered against it, and the Hooks have cross-appealed the partial summary judgments entered against them, all of which were incorporated in the final judgment.

Samson contends on appeal that the trial court erred in entering judgment on the jury’s finding that it committed fraud with respect to the Hooks’ Jefferson County Lease and that it -withheld royalties on formation production with respect to all three of the Hooks’ claims. It also contends that the trial court erred in granting the Hooks’ motion for summary judgment on their unpooling claim with respect to the BSM A-l well, in granting summary judgment on the Hooks’ claim for royalties under the most favored nations clause in their Jefferson and Hardin County Leases, and in denying its own motion for summary judgment on those claims. Finally, Samson contends that the trial court erred by granting a permanent injunction in its final judgment requiring Samson to fulfill certain contract provisions on pain of contempt of court, that it erred in awarding attorney’s fees to the Hooks, and that it erred in awarding the Hooks 18% post-judgment interest compounded annually.

The Hooks contend on cross-appeal that the trial court erred in ruling in Samson’s favor on their claims that Samson breached the offset obligations clause in the Hardin County Leases.

C. DISCUSSION

1. The Trial Court’s Judgment on the Hooks’ Fraud Claims with Respect to the Jefferson County Lease

In its third issue, Samson contends (1) that there is legally and factually insufficient evidence to support the jury’s finding that the Hooks could not have discovered their fraud claims until April 2007 and (2) that the statute of limitations bars the Hooks’ claim for fraud, fraudulent inducement, and statutory fraud with respect to the Jefferson County Lease.

To prove fraud, a plaintiff must show that the defendant made (1) a material misrepresentation (2) that was either known to be false when made or was asserted without knowledge of its truth (3) which was intended to be relied upon (4) which was indeed relied upon and (5) which caused injury. Dow Chem,. Co. v. Francis, 46 S.W.3d 237, 242 (Tex.2001). To prove fraudulent inducement, these same elements of fraud must be established as they relate to a contract. Coastal Bank SSB v. Chase Bank of Tex., N.A., 135 S.W.3d 840, 843 (Tex.App.-Houston [1st Dist.] 2004, no pet.). The statute of limitations for fraud is four years. Tex. Civ. Prac. & Rem.Code Ann. § 16.004 (Vernon 2002).

“Statutes of limitations are intended to compel plaintiffs to assert their claims ‘within a reasonable period of time while the evidence is fresh in the minds of the parties and witnesses.’” Wagner & Brown, Ltd. v. Horwood, 58 S.W.3d 732, 734 (Tex.2001) (quoting Computer Assocs. Int’l, Inc. v. Altai Inc., 918 S.W.2d 453, 455 (Tex.1996)). “As a general rule, a cause of action accrues and the statute of limitations begins to run when facts come into existence that authorize a party to seek a judicial remedy.” Provident Life & Accident Ins. Co. v. Knott, 128 S.W.3d 211, 221 (Tex.2003). In most circumstances, “a cause of action accrues when a wrongful act causes a legal injury, regardless of when the plaintiff learns of that injury or if all resulting damages have yet to occur.” Id.

The statute of limitations for fraud is four years. Tex. Civ. Prao. & Rem.Code Ann. § 16.004(a)(4) (Vernon 2002); Exxon Corp. v. Emerald Oil & Gas Co., 348 S.W.3d 194, 216 (Tex.2011). “The statute of limitations for fraud begins to run from the time the party knew of the misrepresentation.” Emerald Oil, 348 S.W.3d at 216; see also Little v. Smith, 943 S.W.2d 414, 420 (Tex.1997) (“Generally, in a case of fraud the statute of limitations does not commence to run until the fraud is discovered or until it might have been discovered by the exercise of reasonable diligence.”).

The Hooks claimed, and the jury found, that in making their determination to agree to the pooling of 50 acres of their Jefferson County Lease in the BSM No. 1 unit, they relied solely on Lanoue’s oral statement that the BSM No. 1 well was about 1,500 feet from their Lease line and on Charles Hooks’ interpretation of the plat of the BSM No. 1 unit provided to him in response to his conversation with La-noue on February 15, 2001. The Hooks also contended, and the jury found, that they did not discover that the bottom hole of the BSM No. 1 well was within their 1,320-foot buffer zone, entitling them to additional compensation royalties, until well within the limitations period as extended by application of the discovery rule.⁹ Specifically, the Hooks claimed that they relied on Charles Hooks’ interpretation of the designation “±1400'” on the line on the plat of the redesignated unit drawn from an undesignated point to Pine Island Bayou as meaning that the bottom hole of the BSM No. 1 well was about 1,400 feet, or more than 1,320 feet, from their Lease, and, therefore, outside the buffer zone. They did not inquire into seemingly contradictory information in that document showing an arrow pointing to the bottom hole of the BSM No. 1 well about one-quarter of the way along the 1,400-foot line from an undesignated point to Pine Island Bayou, the western line of their Jefferson County Lease. Nor did they inquire into the notation that the bottom hole was about 1,400 feet “FEL unit,” i.e., from the eastern line of the reconfigured BSM No. 1 unit, which included 50 acres of their Jefferson County Lease. Both of these notations would have indicated to them that the bottom hole of the BSM No. 1 well was clearly within the Lease’s 1,320-foot buffer zone. Similarly, the Hooks did not seek available records from either Samson or the Railroad Commission that would have shown them the actual location of the BSM No. 1 well’s bottom hole.

Had the Hooks exercised reasonable diligence, they should have known of the exact location of the bottom hole when the directional survey was filed with the Railroad Commission in July 2000. See Emerald Oil, 348 S.W.3d at 216; Little, 943 . Charles Hooks was an oil and gas attorney and had participated in more than 100 oil and gas leases at the time of trial, and he knew that Lanoue had certified the plat furnished to Hooks as being made on his own knowledge in December 2000, but he never sought to investigate the results of the directional survey filed with the Railroad Commission in July 2000, which showed the exact location of the bottom hole. Nor did the Hooks conduct due diligence in seeking the plat of the originally designated BSM No. 1 unit certified by the surveyor in March 2000, showing the proposed bottom hole of the BSM No. 1 well, which was likewise filed with the Railroad Commission in July 2000. Both of these publicly available documents would have shown that the well was proposed to be and was bottomed within the 1,320-foot buffer zone of the Jefferson County Lease, triggering Samson’s obligations to them under Article VI(A) of that Lease. Any inquiry into the records available from the lessee, Samson, or from the Railroad Commission would have shown the Hooks the actual location of the BSM No. 1 well’s bottom hole in February 2001, when pooling was first proposed to them.

The Hooks’ fraud claims were not filed until May 2007, more than six years after pooling was proposed to them by Samson. We conclude that the Hooks knew or should have known information that led to the discovery of the alleged fraud no later than February 2001, as the necessary information was a matter of public record at that time. See BP Am. Prod. Co. v. Marshall, 342 S.W.3d 59, 66 (Tex.2011) (holding that information disclosing lessee’s failure to continue good faith efforts to develop oil and gas lease was available from public records and “from several other sources, including the lessee”); HECI Exploration Co. v. Neel, 982 S.W.2d 881, 886 (Tex.1998) (holding that, because several sources of information about common reservoirs and operations are available to royalty owners, including Railroad Commission records, discovery rule deferring accrual of cause of action does not apply to claims of royalty owners for damage to common oil and gas reservoir).

The statute of limitations for fraud begins to run when the claimant knew or could have discovered the fraud by the exercise of reasonable diligence. See Little, 943 S.W.2d at 420. Thus, the statute of limitations began to run in February 2001, but the Hooks did not file suit until May 2007, which is well outside the limitations period. See Emerald Oil, 348 S.W.3d at 216. We hold that the Hooks’ fraud claims are barred by limitations as a matter of law.

On rehearing, the Hooks argue that the issue of when they could have discovered the fraud was a question for the jury, citing Lesley v. Veterans Land Board, 352 S.W.3d 479, 485-86 (Tex.2011). That case addressed an alleged mistake in a reservation of a mineral interest. Id. The supreme court held that there were fact issues as to whether this mistake was so plain as to charge the grantor with knowledge of the mistake. Id. at 486. The court concluded, “In these circumstances, it cannot be said that, as a matter of law, Lesley knew or should have known of the mistake in her deed when she executed it. Whether her claim for reformation is barred by limitations involves disputed facts.” Id. This scenario is distinguishable from the present case.

When a cause of action accrues is normally a question of law. Emerald Oil, 348 S.W.3d at 202. Our analysis of when the Hooks knew or should have known of facts that in the exercise of reasonable diligence would have led to the discovery of the alleged wrongful act demonstrates that they should have known of the alleged fraud, as a matter of law, in February 2001, more than six years before they filed suit. There is no disputed fact issue here regarding whether this information was plain enough to charge the Hooks with this knowledge — it is undisputed that this information was readily available in Samson’s records and in the records filed with the Railroad Commission. Moreover, there was sufficient information available on the plat of the redesignated BSM No. 1 unit- — namely the information that the bottom hole of the well was “±1400” feet from the eastern line of the unit that encompassed their 50 acres — that should have put them on inquiry notice. Thus, the reasoning in Lesley does not apply in this case.

We sustain Samson’s third issue.

2. Summary Judgments Entered Against Samson on the Hardin County Leases

(a) Samson’s “Unpooling” of the BSM A-l Unit

In its sixth issue, Samson challenges the trial court’s summary judgment awarding the Hooks damages on their claim for royalties from the BSM A-l unit due to Samson’s improper unpooling of that unit.

Samson contends that because Black Stone Minerals, the 87.5% owner of the mineral rights on the drill site tract did not consent to pooling, (although Firn-Bank, the owner of a 12.5% interest in the mineral rights did), the “essential purpose for forming that unit had failed” and the BSM A-l unit as originally designated was not formed. Thus, the amendment of the unit to exclude the non-consenting drill site mineral owner, Black Stone Minerals, was justified. Samson further argues that, after the BSM A-l unit was amended and renamed the DuJay No. 1 unit, the Hooks accepted royalty payments from production on both DuJay units, which gave the Hooks a higher percentage of the production than they would have received under the BSM A-l unit. Samson argues that, by accepting the royalty payments from the DuJay No. 1 well and the DuJay A-l well, the Hooks accepted the amendment to the BSM A-l unit and they understood and acknowledged that the BSM A-l unit was not formed.

Alternatively, Samson argues that, if the amendment to the BSM A-l unit was improper, the BSM A-l unit still exists and the Hooks should have been paid in accordance with their interests in that unit, not in accordance with their interest in the two DuJay units, which were improperly formed. Moreover, it argues that the extent of the unit must be limited to Firn-Bank’s 12.5% interest in the drill site tract because only FirnBank consented to pool its undivided interest in the gas produced from the BSM A-l well.

The Hooks argue that the BSM A-l unit was validly formed when FirnBank, the owner of a 12.5% undivided interest in the mineral rights to the drill site, consented to the unit and that this pooled unit could not be vacated or amended so long as gas continued to be produced from the BSM A-l well. The Hooks agreed to the pooling of their Hardin County Leases in the BSM A-l unit. Therefore, they argue, they are entitled to royalties from the BSM A-l well in addition to the royalties they accepted from their participation in the DuJay No. 1 and DuJay A-l pooling units.

An oil and gas lease is a contract and is therefore interpreted as such. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex.2005). When construing a contract, the primary goal of the courts is to give effect to the parties’ written expression of their intent. PG & E Gas Transmission v. City of Edinburg, 59 S.W.3d 225, 227 (Tex.App.-Corpus Christi 2001, no pet.). The eourts will enforce the intentions of the parties to an unambiguous oil and gas lease as expressed in the lease. Tittizer, 171 S.W.3d at 860. In determining the agreement, the court examines all parts of the contract and the circumstances surrounding its formulation. Columbia Gas Transmission Corp. v. New Ulm Gas, Ltd., 940 S.W.2d 587, 591 (Tex.1996); PG & E Gas Transmission, 59 S.W.3d at 227-28.

With respect to royalty interest owners, “pooling results in ‘a cross-conveyance of interests in land by agreement among the participating parties, each of whom obtains an undivided joint ownership in the royalty earned from the land in the “block” created by the agreement’” and each of whom receives royalty on the basis of the percentage of that party’s acreage to the whole block. Browning Oil Co. v. Luecke, 38 S.W.3d 625, 633 (Tex.App.-Austin 2000, pet. denied) (quoting MCZ, Inc. v. Triolo, 708 S.W.2d 49, 52-53 (Tex.App.-Houston [1st Dist.] 1986, writ ref'd n.r.e.)). In other words, pooling effects a cross-conveyance among the owners of the minerals under the various tracts in the pool so that all cotenants own undivided interests under the unitized tract in the proportion that their contribution bears to the unitized tract. Montgomery v. Rittersbacher, 424 S.W.2d 210, 213 (Tex.1968). Thus, when an oil and gas lease is executed by all of the owners of different mineral interests in two or more tracts, the royalties payable under the lease will be pooled, and all royalty interest owners in the land subject to the lease will share in production, no matter where the well is drilled on the leasehold. London v. Merriman, 756 S.W.2d 736, 739 (Tex.App.-Corpus Christi 1988, writ denied).

An oil and gas lessee has no power to pool, however, without the lessor’s express authorization, usually contained in the lease’s pooling clause. Tittizer, 171 S.W.3d at 860; Se. Pipe Line Co. v. Tichacek, 997 S.W.2d 166, 170 (Tex.1999); Luecke, 38 S.W.3d at 634 (holding that lessee’s authority to pool is derived solely from terms of lease, and lessee has no power to pool absent express authority). “For pooling to be valid, it must be done in accordance with the terms of the methods and purposes specified in the lease.” Tittizer, 171 S.W.3d at 860; Tichacek, 997 S.W.2d at 170. Good-faith pooling can be exercised multiple times. See Expando Prod. Co. v. Marshall, 407 S.W.2d 254, 259-60 (Tex.Civ.App.-Fort Worth 1966, writ ref'd n.r.e.). However, “[t]he lessors’ land may be pooled only to the extent stipulated in the lease.” Tittizer, 171 S.W.3d at 860 (quoting Jones v. Killingsworth, 403 S.W.2d 325, 327-28 (Tex.1965)).

Joinder by all interest owners is not necessary for a pooled unit to be valid. See Ladd Petroleum Corp. v. Eagle Oil & Gas Co., 695 S.W.2d 99, 106 (Tex.App.-Fort Worth 1985, writ ref'd n.r.e.); see also Whelan v. Placid Oil Co., 274 S.W.2d 125, 128 (Tex.Civ.App.-Texarkana 1954, writ ref'd n.r.e.) (holding that tenant in common has right to execute lease on his undivided interest in common property, notwithstanding nonjoinder of cotenant); Donnan v. Atl. Richfield, 732 S.W.2d 715, 717 (Tex.App.-Corpus Christi 1987, no writ) (stating that cotenant has right to incorporate pooling agreement into oil or gas lease without consent or joinder of cotenants, thereby binding his undivided interest). Rather, a tenant in common has the legal right to incorporate a pooling agreement into an original oil and gas lease without the consent or joinder of the other cotenants, creating a valid contract binding the undivided interest of the co-tenant making the agreement. Whelan, 274 S.W.2d at 128. In such a case, the timely completion of a producing well under the terms of the pooling agreement and within the unit area set out in the unitization agreement will serve to continue the lease in full force and effect so long as gas is being produced in commercial quantities. Id. A cotenant who enters into such a lease binding its royalty interest in the completed and producing well and who accepts its pro rata share in the royalties from the well calculated under the terms of the unitization agreement is estopped to deny the validity of the unitization agreement as to its interest therein. Id. at 129.

A lessee cannot unilaterally terminate a unit that has a producing pooled well. See Ladd Petroleum Corp., 695 S.W.2d at 106-07. Rather, for a lessee to terminate a unit, either the lessors must agree to the unpooling or the lease must expressly authorize such termination. Id. at 107; see Williamson v. Mobil Producing Tex. & N.M., Inc., 737 S.W.2d 917, 921 (Tex.App.-Beaumont 1987, writ denied) (“So, clearly, the lessee, if it is ‘after the discovery of the same,’ can change the pooling unit only subsequent to the cessation of production.... ”).

When a mineral interest owner — a lessor — accepts royalty checks from a pooled unit, he has accepted that unit. See Montgomery, 424 S.W.2d at 214-15. Under the doctrine of equitable estoppel, mineral interest owners can not repudiate a unit designation after accepting royalties attributable to that unit. Cambridge Prod. Inc. v. Geodyne Nominee Corp., 292 S.W.3d 725, 732 (Tex.App.-Amarillo 2009, pet. denied).

Here, The Hardin County Leases granted Samson the authority to pool those leases with other land or leases. Under that authority, Samson obtained the Hooks’ ágreement to pool their interests with the undivided interests of the two drill site lessors, Black Stone Minerals and FirnBank, in the BSM A-l unit. One of the two drillsite lessors — FirnBank—con-sented to the BSM A-l unit. In addition, Samson pooled other lands and its own working interests into that unit. However, Black Stone Minerals refused to pool. Samson had no authority to pool Black Stone Minerals’ interests without its express consent. See Tittizer, 171 S.W.3d at 860; Tichacek, 997 S.W.2d at 170; Luecke, 38 S.W.3d at 634. But it did not lack authority to form a gas production unit that included the mineral interests of Black Stone Minerals’s cotenant, Firn-Bank. See Ladd Petroleum Corp., 695 S.W.2d at 106; Whelan, 274 S.W.2d at 128.

We agree with the Hooks that the originally designated BSM A-l unit was validly formed, creating a valid contract binding FirnBank, the cotenant making the agreement, and the Hooks. See Whelan, 274 S.W.2d at 128. Thus, the Hardin County Leases and FirnBank’s undivided 12.5% interest in the acreage of the designated unit, as well as the leases of the other consenting landowners, constituted a valid pooling unit. However, FirnBank pooled only its own undivided 12.5% interest in the production from the BSM A-l unit. See id. at 129. The BSM A-l unit that was created for the BSM A-l well did not include the interest of Black Stone Minerals, who had not consented to pool its undivided mineral interest in the drill site lease, as a lessor. See Tittizer, 171 S.W.3d at 860; Tichacek, 997 S.W.2d at 170; Luecke, 38 S.W.3d at 634. Neither Firm Bank nor the Hooks had the authority to bind Black Stone Minerals to them own agreement to pool. See Montgomery, 424 S.W.2d at 213; Whelan, 274 S.W.2d at 128.

While there was production from the original BSM A-l unit, Samson had no authority to dissolve that unit. See Williamson, 737 S.W.2d at 921. Nevertheless, when Black Stone Minerals refused to pool, Samson treated the BSM A-l well as continuing as an independent lease well on the Black Stone Minerals/FirnBank Lease that was not pooled in any unit. Samson did not pay the Hooks royalties on the production from the BSM A-l well, nor did the Hooks complain that they were not receiving royalties. Instead, it amended and redesignated the pooling unit to exclude the BSM A-l well and the EY5 formation from which it was producing, which Samson renamed the DuJay No. 1 unit.

Samson pooled the Hooks’ interests and those of the other interest holders in the originally designated BSM A-l unit into both the DuJay No. 1 unit and the DuJay A-l unit, pursuant to its right under the Hardin County Leases to exercise pooling authority multiple times, “at any time and from time to time.... ” Samson notified the Hooks, stating, “Please note that the Unit Designation for the Black Stone Minerals ‘A’ No. 1 is being amended and will now be called the Joyce DuJay No. 1 Unit. No additional action is needed on your part.”

The amended unit and redesignated pooling unit included reduced acreage from the Black Stone Minerals/FirnBank lease as well as the Hooks’ Hardin County Leases and others from the original BSM A-l unit, including the State’s leases. Although the new DuJay No. 1 unit did not include the horizon from which the BSM A-l well was producing, it did include deeper strata that had been included in the original BSM A-l unit, including the depths from which the DuJay No. 1 well was producing. Subsequently, Samson designated a second new gas production unit that overlapped with the original BSM A-l unit, which it named the DuJay A-l unit. The DuJay A-l unit included different strata not included in the DuJay No. 1 unit.

The completion of a producing well, the BSM A-l, within the unit area set out in the unitization agreement served to continue the leases granted to Samson by Firn-Bank, the Hooks, and the other landowners in full force and effect so long as any “unitized substance” continued to be produced from the BSM A-l well, subject to unpooling through agreement of the lessors or through cessation of the production of unitized substance as provided in the habendum clause of the Hardin County Leases. See Ladd Petroleum Corp., 695 S.W.2d at 107; Whelan, 274 S.W.2d at 128. Therefore, Samson’s redesignation of the BSM A-l unit constituted a breach of the Hardin County Leases by Samson, as did its failure to pay the Hooks royalties on the production from the BSM A-l well unless the lessors agreed to the unpooling.

The Hooks took no action to assert any rights under the originally designated BSM A-l unit in response to Samson’s amendment and redesignation of the BSM A-l unit as the DuJay No. 1 unit and its subsequent designation of the DuJay A-l unit until they filed suit for breach of contract against Samson in November 2006, more than four years from the date of first production and more than four years from the date the BSM A-l unit was amended and redesignated and the Hooks were notified. Instead, the Hooks expressly agreed to accept the redesignation and terms of the new units, binding themselves to accept royalties pursuant to their pro rata share of the royalties from the DuJay No. 1 and DuJay A-l units as calculated under the terms of the DuJay No. 1 and DuJay A-l unitization agreements, and they did accept royalties from the production of both DuJay units until the time of trial in this case.

We conclude that, by accepting royalty checks from the amended and redesignat-ed pooling units, the DuJay No. 1 and DuJay A-l units, which they had been notified replaced the BSM A-l unit, and by not asserting any rights to royalties from the original BSM A-l unit or making any timely claim against Samson in regard to the amendment and redesignation of the BSM A-l unit, the Hooks accepted and ratified the amendment and redesignation of the units. See Fortune Prod. Co. v. Conoco, Inc., 52 S.W.3d 671, 678 (Tex.2000) (stating that ratification is adoption or confirmation by person with knowledge of all material facts of prior act which he had right to repudiate); Montgomery, 424 S.W.2d at 214-15.

We hold, therefore, that the Hooks are estopped to assert an interest in royalties from production from the BSM A-l well by their ratification of the amended and redesignated BSM A-l unit.

We sustain Samson’s sixth issue.

(b) The Hooks’ Summary Judgment on the “Most Favored Nations” Clause in the Jefferson and Hardin County Leases

In its seventh issue, Samson claims that the trial court erred in rendering summary judgment in the Hooks’ favor on the “most favored nations” lease clause contained in all three of the Hooks’ Leases. This clause provided that, under certain circumstances, the royalties payable to the Hooks must be elevated to match the highest royalty payable to Samson’s other lessors. Specifically, the clause provides:

XXIX. MOST FAVORED NATIONS CLAUSE

If Lessee shall enter into an oil and gas lease(s) part of which is located within three (3) miles of any exterior boundary of the subject lands covered by the Subject Lease, hereinafter referred to as “Third Party Lease,” Lessee shall notify Lessor of such fact. If the reserved royalty or the amount per acre payable for delay rentals, shut-in rentals or minimum royalty, at any time payable under such Third Party Lease, is higher than the like royalty and amounts payable as provided in the Subject Lease, the royalty or amount payable per acre in the Subject Lease, which is less than that provided in the Third Party Lease shall be immediately increased so that it will equal the royalty or other amounts payable under the Third Party Lease. The subject Lease and the Third Party Lease must be calculated in substantially the same manner, such that the comparison of the Subject Lease and the Third Party Lease is based on the same effective net royalty or other payments, and that same shall include or deduct the same types of charges, taxes and other burdens from such interests.

The trial court granted summary judgment in the Hooks’ favor, holding that this clause was triggered by royalty paid to the State of Texas under a pooling agreement with Samson that was higher than the royalty due to the Hooks.

It is undisputed that the State of Texas’s lease under Pine Island Bayou (“State of Texas Lease”) is a “Third Party Lease” within the meaning of that term in the most favored nations clause in the Leases in that it covers land located within three miles of the lands covered by the Hooks’ Leases. The State, like FirnBank and the Hooks, originally consented to pooling to form the BSM A-l unit. It declined, however, to consent to the subsequent DuJay No. 1 unit. In order to obtain the State’s consent to pool its lease under Pine Island Bayou into the DuJay No. 1 unit, Samson entered into a pooling agreement wherein Samson became obligated to pay the State a 28.28896% royalty on production from the DuJay No. 1 well, as opposed to the 25% it had been paying the State and was paying to the Hooks. The issue, therefore, is whether the pooling agreement executed by Samson and the State constitutes a “Third Party Lease,” i.e., an oil and gas lease located within three miles of any exterior boundary of any of the Hooks’ Leases with a higher royalty than that provided for in the Hooks’ Leases, so that Samson’s obligation to pay the Hooks increased royalties under the most favored nations clause in those leases was triggered.

A most favored nations clause is “a vendor protection clause [that] enables the vendor to receive the benefit of increases in the market price of his product over the term of a long range contract with a purchaser.” Lone Star Gas Co. v. Howard Corp., 556 S.W.2d 372, 374 (Tex.Civ.App.-Texarkana 1977, writ ref'd n.r.e.). Such a clause is enforced according to its terms. See id. at 375-76.

The most favored nations clause in the Leases referred specifically to Samson’s obligation to pay the Hooks royalty per acre equal to that payable under any Third Party “oil and gas lease(s) part of which is located within three (3) miles of any exteri- or boundary of the subject lands covered by [the Hooks’] Lease that Samson entered.” Here, however, Samson did not enter an “oil and gas lease” with the State that required it to pay higher royalties per acre than it was paying the Hooks under their Leases. It entered a settlement agreement, called a “Pooling Agreement,” that raised only the royalty payable to the State on production from the DuJay No. 1 unit.

The difference between the royalties payable to the State on production from the DuJay No. 1 unit and the royalties paid to the Hooks did not represent a difference in the market price of gas at the time the pooling agreement was entered; nor did it represent a general increase in the royalty rate on the State’s leases. It was an amount agreed upon by Samson and the State to induce the State to accept the amended unit in place of the BSM A-l unit and to compensate the State for its loss of royalties from the BSM A-l well due to Samson’s amendment and redesig-nation of the BSM A-l unit as the DuJay No. 1, excluding the BSM A-l well formation.

We conclude that, under its plain terms, the most favored nations clause in the Hooks’ Leases does not apply to trigger royalties payable to the Hooks equal to those payable under the settlement agreement reached between Samson and the State. Therefore, we hold that the trial court erred in granting the Hooks’ motion for summary judgment for damages under the most favored nations clause in the Hardin County Leases.

We sustain Samson’s seventh issue.

3. The Hooks’ Claims Under the Formation Production Clause in the Jefferson and Hardin County Leases

In its fifth issue, Samson complains about the jury’s finding, in response to Question Number 8, that Samson’s failure to pay royalty based on formation production resulted in underpayment of royalty under the Hooks’ Jefferson and Hardin County Leases and the trial court’s judgment awarding the Hooks damages based on the formation production clause in the Leases. Samson contends the issue was erroneously submitted to the jury because the construction of the contractual provision involved was a question of law for the trial court; therefore, the jury’s response to Question Number 8 is immaterial. Samson argues that, as a matter of law, the lease provision in question, properly construed, does not require Samson to pay for formation production, as this would require it to pay twice for molecules of gas produced at the surface of the well as liquid condensate. It also contends that there is legally and factually insufficient evidence that the Hooks’ Leases required Samson to pay twice for those molecules of gas. It states that, by giving effect to the jury’s answer to Question Number 8, the trial court increased all the other categories of damages assessed against it.

Condensate consists of “hydrocarbons that exist in the form of gas when contained in the natural gas reservoir underground, which condense into liquid form when released from the reservoir’s higher pressure and temperature.” Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 704 n. 7 (Tex.2008). When gas is produced, it goes through a mechanical separator through which condensate drops out as a liquid at the wellhead. The Railroad Commission has implemented a system by which producers report the amount of gas in the reservoir before it is produced. This system requires producers to use a formula to calculate the volume of reservoir gas produced at the surface as a liquid. “Formation production” is thus the calculation of the total amount of natural gas taken from the reservoir in whatever form it arrives at the surface, whether in the form of gas or in the form of liquid condensate. Formation production calculations allow the Railroad Commission to track the amount of gas coming out of the ground to avoid overproduction.

Article III of each of the Hooks’ Leases contained several paragraphs specifying how royalties were to be paid. It reads in pertinent part:

III ROYALTIES:

Lessors reserve for themselves ... the following royalties ...

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B. (1) On gas, including casing head gas or other gaseous substances produced from said land, Twenty-Five percent (25%) of the market value at the wells of such gas, or Twenty-Five percent (25%) of the price received therefor by Lessee, whichever is greater ...

D. An equal Twenty-Five percent (25%) part of all other liquid hydrocarbons that may be produced from said land ...

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K. For the purposes of calculating all royalties payable under Article III herein, it is expressly provided that all such calculations shall be based on formation production as reported on Texas Railroad Commission forms P-1 and P-2.

The Hooks base their formation production argument on Article III(K). They contend that although this provision expressly refers to the entirety of Article III, which covers payments for both liquids and gas, it requires that all calculations shall be based on gas as it exists in the reservoir so that royalties must be paid on liquid condensate both as it is produced in liquid form and as it exists in gaseous form in the reservoir.

The interpretation of the formation production provision in the Hooks’ Leases is a matter of contract construction. Whether a contract is ambiguous is a question of law for the court. J.M. Davidson, Inc. v. Webster, 128 S.W.3d 223, 229 (Tex.2003). We construe the parties’ intentions as expressed in the document, considering the entire writing and attempting to harmonize and give effect to all of the contract’s provisions with reference to the whole agreement. Frost Nat’l Bank v. L & F Distribs., 165 S.W.3d 310, 311-12 (Tex.2005). “We construe contracts ‘from a utilitarian standpoint bearing in mind the particular business activity-sought to be served’ and ‘-will avoid when possible and proper a construction which is unreasonable, inequitable, and oppressive.’ ” Id.; accord Ace Ins. Co. v. Zurich Am. Ins. Co., 59 S.W.Bd 424, 428 (Tex.App.-Houston [1st Dist.] 2001, pet. denied). If, after the rules of construction are applied, the contract can be given a definite or certain legal meaning, it is unambiguous and we construe it as a matter of law. Frost Nat’l Bank, 165 S.W.3d at 312.

Article III of the Hooks’ Leases, governing the payment of royalties, addresses a number of royalty payment issues. In each case, it unambiguously states that Samson will pay 25% of the proceeds it receives, whether for gas or for liquids, as royalties to the Hooks unless the proceeds are below market value, in which case it must pay 25% of market value. In no place do the Leases state that, having paid royalties to the Hooks from the proceeds it receives on the sale of gas or liquid condensate, Samson must pay for the condensate a second time as it existed as gas in the reservoir. Article III does not state that Samson must pay a 25% royalty on “formation production” in addition to royalty on gas and liquids as produced, and we decline to read that provision into the unambiguous language of the Lease. See Mann Frankfort Stein & Lipp Advisors Inc. v. Fielding, 289 S.W.3d 844, 850 (Tex.2009) (“[Tjerms are to be implied in contract, not because they are reasonable, but because they are necessarily involved in the contractual relationship, such that the parties must have intended them and must have failed to express them only because of sheer inadvertence or because they are too obvious to need expression.”). We agree with Samson that the unambiguous meaning of these lease provisions is that the Hooks are entitled to a 25% royalty on all gas and liquid hydrocarbons at the time proceeds are received from their sale.

We hold that, under its plain language, the formation production clause in Article III(K) of the Hooks’ Jefferson County and Hardin County Leases does not operate to double the amount of royalties owed on the liquid condensate produced from the well. Therefore, the trial court erred in awarding the Hooks damages calculated under the formation production clause in their Leases.

We sustain Samson’s fifth issue.

4. The Trial Court’s Grant of a Permanent Injunction

In its eighth issue, Samson claims that the trial court erred by granting a permanent injunction in its judgment that requires it to fulfill certain contractual provisions upon pain of contempt of court. Samson claims that no evidence was presented of the elements necessary for a permanent injunction.

The first item of injunctive relief requires Samson to pay the Hooks royalty on production from the BSM A-l well commencing with production after May 2008. The fourth item states that Samson shall be liable for all ad valorem taxes on the Hooks’ interests in the oil and gas leases at issue after November 2007, as long as those leases are in effect. The fifth item requires Samson to provide the Hooks with certain notices and information “as required by the oil and gas leases in this case while those leases are in effect.”

A permanent injunction is proper only when there is evidence of four elements: (1) a wrongful act; (2) imminent harm; (3) irreparable injury, and (4) no adequate remedy at law. Jordan v. Landry’s Seafood Rest., Inc., 89 S.W.3d 737, 742 (Tex.App.-Houston [1st Dist.] 2002, pet. denied). The ruling is reviewed for an abuse of discretion. Id. Courts do not enforce contractual rights by permanent injunction unless the complaining party can show an inadequate remedy at law and irreparable injury. Cytogenix, Inc. v. Waldroff, 213 S.W.3d 479, 487 (Tex.App.Houston [1st Dist.] 2006, pet. denied). Moreover, in order to grant specific performance of a contract via an injunction, present performance of the contract’s terms must be possible. Id. “A court should not decree future contractual performance by requiring a party to perform a continuous series of acts, extending through a long period of time, over which the court exercises its supervision.” Id. Unless a “significant public interest” is involved, parties to a contract are “left to their remedies at law.” Id.

The Hooks have failed to cite to us any evidence showing that they are in danger of imminent harm or irreparable injury from Samson’s failure to pay them royalties on production from the BSM A-l well or ad valorem taxes or failure to provide them with lease notices and information. Nor have they shown that they have no adequate remedy at law for their grievances. Moreover, at least three of the items of injunctive relief decree future contractual performance, which is forbidden by Cytogenix. Id. Accordingly, we conclude that the trial court abused its discretion by including injunctive relief in its order (1) in the absence of any evidence of the elements of a permanent injunction and (2) when the injunctive relief decrees future contractual performance.

5. Attorney’s Fees and Post judgment Interest Rate

In its eighth issue, Samson complains about the grant of attorney’s fees in the final judgment. The parties stipulated that the Hooks’ right to collect attorney’s fees was contingent on the Hooks prevailing at trial and on appeal. During trial, the parties also stipulated that Samson owed the Hooks $52,257.22 related to ad valorem taxes. Although Samson asked this Court to reverse the trial court’s judgment “in its entirety,” the parties do not challenge the agreement as to Samson’s payment of ad valorem taxes. However, the Hooks argue on rehearing that Samson’s stipulation regarding ad valorem taxes means that the Hooks prevailed on a claim, and, thus, they are entitled to stipulated attorney’s fees under the terms of a separate pre-trial fee stipulation.

The pre-trial fee stipulation provided that the stipulated attorney’s fees “are owed to [the Hooks] by [Samson] if [the Hooks] prevail on any of their claims.” The agreement then provided specific exceptions for claims not relevant here. The parties made a separate stipulation during trial that addressed the issue of the ad valorem taxes.

An “agreement between the parties will not be given greater effect than intended,” and “[a] stipulation will not be construed as an admission of a fact intended to be controverted.” Austin v. Austin, 603 S.W.2d 204, 207 (Tex.1980). Nothing in the ad valorem tax stipulation indicated that it was intended to constitute an admission that the Hooks had prevailed on that issue. Thus, the stipulated payment of ad valorem taxes does not entitle the Hooks to claim attorney’s fees. See id. Because we have reversed the portions of the judgment in favor of the Hooks on which they could claim to be prevailing parties, and upon which their right to attorney’s fees is contingent, we conclude that the Hooks are not entitled to attorney’s fees.

We sustain Samson’s eighth issue.

Additionally, in two sentences in its appellate brief, Samson claimed that “[i]t was error to award post judgment interest of 18% compounded annually. Instead, the post judgment interest should be at the same rate as a proper prejudgment interest rate.” We asked for and received supplemental briefing from both parties on this issue. The supplemental issue, as phrased by Samson, is as follows: “Should the post judgment interest rate be 5% as set by Texas Finance Code § 304.003, rather than the rate of 18% as stated in the Final Judgment?” In its supplemental briefing and in its motion for rehearing filed on March 16, 2012, the Hooks argue that post judgment interest should be awarded at the “maximum allowed by law (per the leases).” However, the agreement under which Samson is obligated to pay the ad valorem taxes, the only recovery to which the Hooks are entitled, is the stipulation entered by the parties during trial, not the leases. The ad valo-rem tax stipulation does not provide an interest rate.

When the interest rate is not specified in a contract, post judgment interest should be calculated based on the statutory rate provided in Texas Finance Code section 304.003. See Tex. Fin.Code Ann. § 304.003 (Vernon 2006) (providing judgment interest rate when interest rate or time price differential is not in contract). Section 304.003(b) provides that, “[o]n the 15th day of each month, the consumer credit commissioner shall determine the post judgment interest rate to be applied to a money judgment rendered during the succeeding calendar month.” Id. § 304.003(b). Section 304.003(c) provides that, with exceptions not applicable here, “[t]he post judgment interest rate is ... the prime rate as published by the Board of Governors of the Federal Reserve System on the date of computation” or “five percent a year if the prime rate ... described by Subdivision (1) is less than five percent.” Id. § 304.003(e)(( )-(2). The prime rate is published in the Texas Register by the Secretary of State. Id. § 304.004 (Vernon 2006). This Court may take judicial notice of the correct, published rate on appeal. See Office of Pub. Util. Counsel v. Pub. Util. Comm’n of Tex., 878 S.W.2d 598, 600 (Tex.1994).

Here, when the trial court entered its final judgment on December 11, 2008, the judgment interest rate according to the consumer credit commissioner was five percent. See Judgment Rate Summary, http://www.occc.state.tx.us/pages/infi_rates/ Index.html (last visited May 22, 2012). Thus, the post judgment interest rate on Samson’s obligation to pay the stipulated ad valorem taxes should be five percent. See Tex. Fin.Code Ann. § 304.003(c).

We sustain Samson’s issue on the post judgment interest rate.

C. CONCLUSION

We reverse the trial court’s final judgment awarding the Hooks damages on their fraud, fraudulent inducement, statutory fraud, and formation production claims and render judgment that the Hooks take nothing by these claims. We likewise reverse the trial court’s final judgment as it reaffirms and incorporates its summary judgments on the Hooks’ unpool-ing and most favored nations claims and render judgment that the Hooks take nothing by these claims. Because of our holding on these issues, we vacate the trial court’s award of attorney’s fees. Finally, we vacate the permanent injunction entered against Samson by the trial court. We further hold that the proper post judgment interest rate is five percent.

II. THE HOOKS’CROSS-APPEAL

Before trial, the Hooks and Samson filed cross-motions for summary judgment on the issue of whether Samson breached the offset obligations in the Hardin County Leases. The trial court granted Samson’s motion and denied the Hooks’ motion on this issue without stating its reasons.

The Hooks filed a cross-appeal claiming, in one issue, that the trial court erred in granting Samson’s motion for summary judgment and denying their own. The Hooks include in this issue sub-issues regarding the correct interpretation of Samson’s offset obligations under the Jefferson County and Hardin County Leases, an exception in the Leases for pre-existing wells, and the statute of limitations.

Samson contends that the Hooks have waived their appeal of the summary judgments by failing to preserve it. It further argues that the trial court correctly interpreted the Hardin County Leases with respect to the issues raised by the Hooks on cross-appeal and correctly rendered summary judgment holding that the Hooks’ offset claims are contract claims that are barred by limitations.

A. STANDARD OF REVIEW

To prevail on a summary judgment motion, a movant has the burden of proving that it is entitled to judgment as a matter of law and that there is no genuine issue of material fact. Tex.R. Civ. P. 166a(c); Cathey v. Booth, 900 S.W.2d 339, 341 (Tex. 1995). Neither party herein argues that a genuine issue of material fact exists which precludes summary judgment; instead, both claim that, as a matter of law, they are entitled to summary judgment based on the language of the Leases.

B. STATUTE OF LIMITATIONS

The Hooks’ claims that Samson breached its offset obligations are breach of contract claims. The four-year statute of limitations applies to the Hooks’ contract claims. See Stine v. Stewart, 80 S.W.3d 586, 592 (Tex.2002); HECI Exploration Co., 982 S.W.2d at 885. “It is well-settled law that a breach of contract claim accrues when the contract is breached.” Stine, 80 S.W.3d at 592.

Here, Samson’s alleged breach of its offset obligations occurred ninety days from the date of first production from the wells in question. For the BSM No. 1 well, the ninety days ran in January 2001. For the BSM A-l well, the ninety days ran in September 2001. The Hooks did not file suit until November 2006, more than five years later.

We conclude that the Hooks’ cause of action for Samson’s breach of its offset obligations was barred by the four-year statute of limitations.

Because our resolution of this issue is dispositive, we do not reach the other sub-issues raised in the Hooks’ cross-appeal.¹⁰

We overrule the Hooks’ issue on cross-appeal.

III. CONCLUSION

We modify the applicable post judgment interest rate to five percent and affirm the portion of the trial court’s judgment awarding the Hooks $52,257.22 related to ad valorem taxes as stipulated by the parties. We reverse the remaining portions of the final judgment of the trial court, including the awards to the Hooks of $20,081,638.07 for damages proximately cause by fraud, $848,854.01 for damages for breach of the most favored nations clause, and $766,626.85 for damages for “unpooling” related to the BSM A-l well, attorney’s fees, other fees and costs. We hold that the Hooks take nothing by those claims, and we vacate the permanent injunction entered against Samson.

Justice SHARP, concurring in part and dissenting in part.

2 . See Brookshire Bros., Inc. v. Smith, 176 S.W.3d 30, 40 & n. 2 (Tex.App.-Houston [1st Dist.] 2004, pet. denied).

3 . This issue was added at Samson’s request by order dated June 10, 2010, and both parties were required to and did file supplemental briefs thereon.

4 . Article VI(A) of the Jefferson County Lease provided, in pertinent part, as follows:

[I]n the event a well producing from a unit not comprised of acreage from the leased premises ... which has been classified as "gas” ... is completed on adjacent or nearby lands not more than one thousand three hundred and twenty feet (1,320') from the leased premises, or draining the leased premises, Lessee covenants and agrees to, within ninety (90) days from the date production is first sold, removed or otherwise marketed from said adjacent or nearby producing well, either (1) commence with due diligence operations for the actual drilling of an offset well on the leased premises to the base of the formation from which the adjacent or nearby producing well is producing, (2) pay Lessors as compensatory royalty, in addition to any royalties currently due, a sum equal to the royalties which would be payable under this lease on the production from said adjacent or nearby producing well had same been producing on the leased premises, or (3) in lieu of drilling such offset well or paying such compensatory royalty, release by recordable instrument the offset acreage, as hereinafter defined. "Offset Acreage,” as used herein-above, shall be defined as a unit which would surround such a well if same were completed on the leased premises; provided, however, that if any portion of the offset acreage would be included in a producing unit designated by Lessee hereunder, then if Lessee elects to surrender and release such offset acreage, it may retain and except from such release the producing stratum or strata included in such producing unit, but such offset acreage must conform to the depth, size and shape limitations contained in Paragraph V. herein. The provisions hereof shall apply regardless of whether lands upon which offset wells may be located are owned by Lessor or any of them or not, and with regard to wells located within the hereinabove prescribed distances from the leased premises, regardless of whether drainage is actually proved to be taking place or not. Notwithstanding anything herein to the contrary, Lessee shall have no obligations under this Article VI in the event a producing well on nearby or adjacent land is already offset by a well on the leased premises or on acreage pooled therewith producing from the same producing horizon from which production has been secured from any well on nearby or adjacent lands.

5 . The severed lawsuits are Klorer v. Samson Lone Star, No. B-173,008; Bordages v. Samson Lone Star, No. B-173,008-A; and Hooks v. Samson Lone Star, No. B-173.008-B. Only Hooks has gone to trial. Klorer and Bordages remain pending.

6 . Question Four, the question asking for a finding that the harm to the Hooks resulted from fraud, and Question Five, asking for a finding that Samson had actual awareness of the falsity of the representation, instructed the jury to answer the questions only if it unanimously answered "yes” to Questions One and Two. Only eleven of the twelve jurors answered "yes” to Questions One and Two; therefore, the jury properly refrained from answering Questions Four and Five.

7 . Question Seven, seeking a finding that Samson secured execution of a document by deception, instructed the jury to answer the question only if it unanimously answered "yes” to Question Four or Five. Because the jury did not answer Question Four or Five, it properly refrained from answering Question Seven.

8 . At trial, Samson stipulated that it owed the Hooks $52,257.22 for ad valorem taxes that the Hooks had paid through November 2007.

This stipulation and the amount of ad valorem taxes owed by Samson to the Hooks is not challenged on appeal.

9 . Although the jury found that the Hooks' cause of action for fraud accrued on "Hooks’ birthday April 2007," the record shows that Hooks’ birthday was in November and that it was on his birthday in November 2006 that he attended the seminar for oil and gas attorneys where he first heard about the other mineral-rights owners’ suits against Samson.

10 . Likewise, we do not reach Samson's claims of waiver.