Opinion issued March 15, 2016




                                In The

                          Court of Appeals
                                For The

                       First District of Texas
                         ————————————
                          NO. 01-09-00328-CV
                        ———————————
SAMSON LONE STAR LIMITED PARTNERSHIP, N/K/A SAMSON LONE
             STAR, L.L.C., Appellant/Cross-Appellee
                                  V.
  CHARLES G. HOOKS, III, INDIVIDUALLY AND AS INDEPENDENT
   EXECUTOR OF THE ESTATE OF CHARLES G. HOOKS, JR., AS
 TRUSTEE OF THE SCOTT IRA MCKEEVER TRUST AND THE DAVID
 WAYNE MCKEEVER TRUST, AND ON BEHALF OF CHAS. G. HOOKS
  & SON, A GENERAL PARTNERSHIP, MCKEEVER PARTNERSHIP,
  LTD., AND CHARLES G. HOOKS III AND SUE ANN HOOKS, AS CO-
    TRUSTEES UNDER THE WILL OF CHARLES G. HOOKS, SR.,
                   Appellees/Cross-Appellants


                 On Appeal from the 60th District Court
                       Jefferson County, Texas
                    Trial Court Case No. B173008B
                                  OPINION

      Samson Lone Star Limited Partnership, n/k/a Samson Lone Star, L.L.C.

(“Samson”), originally appealed the trial court’s final judgment in favor of

appellees, Charles G. Hooks, III, Individually and as Independent Executor of the

Estate of Charles G. Hooks, Jr., as Trustee of the Scott Ira McKeever Trust and the

David Wayne McKeever Trust, and on Behalf of Chas. G. Hooks & Son, a General

Partnership, McKeever Partnership, Ltd., and Charles G. Hooks III and Sue Ann

Hooks, as Co-Trustees Under the Will of Charles G. Hooks, Sr. (collectively,

“Hooks”). The judgment arose from an oil and gas case Hooks filed against

Samson with respect to three oil and gas leases, two in Hardin County, Texas and

one in Jefferson County. Hooks asserted multiple causes of action against Samson,

including breach of contract, fraud, fraudulent concealment, statutory fraud, and

negligent misrepresentation. The trial court granted summary judgment in favor of

Samson on Hooks’ claim that Samson breached certain offset obligations under the

leases, and it granted summary judgment in favor of Hooks on his claim that

Samson breached the “most favored nations” clause in the leases and breached the

leases related to the “unpooling” of Hooks’ two leases in Hardin County. The

issues of fraud and underpayment of royalties on “formation production” were

tried to a jury, which found in Hooks’ favor. The trial court’s final judgment




                                        2
awarded Hooks more than $21 million in damages based on the summary

judgment rulings and the jury’s verdict.

      On appeal, this Court reversed the judgment in favor of Hooks except for an

agreed ad valorem tax payment. See Samson Lone Star, Ltd. P’ship v. Hooks, 389

S.W.3d 409, 439 (Tex. App.—Houston [1st Dist.] 2012), aff’d in part and rev’d in

part, 457 S.W.3d 52 (Tex. 2015). The Texas Supreme Court reversed our holding

that the fraud claims and breach of offset obligations under the Hardin County

Leases were barred by limitations and our holding that Samson had not breached

the most-favored-nations clause. Hooks v. Samson Lone Star, Ltd. P’ship, 457

S.W.3d 52, 61, 63, 69 (Tex. 2015). It affirmed in part and reversed in part our

determination of the applicable post-judgment interest rate, and it affirmed our

holdings on the formation-production and unpooling claims. Id. at 65–66, 70. It

remanded the case to this Court for us to consider the factual sufficiency of the

jury’s fraud limitations findings, the legal and factual sufficiency of the jury’s

findings on Hooks’ fraud claims, the damages for Hooks’ claim that Samson

breached the most-favored-nations clause, and the merits of Hooks’ claim that

Samson breached its offset obligations under his leases in Hardin County.

      On remand, Samson argues that: (1) & (2) the evidence was legally and

factually insufficient to support the jury’s verdict on Hooks’ common law and

statutory fraud claims; (3) the evidence was legally and factually insufficient to


                                           3
support the damages awarded on Hooks’ fraud claims, which requires a remand

“for a reduction and recalculation of the fraud damages, including attendant

prejudgment and post-judgment interest issues”; (4) the evidence was factually

insufficient to support the jury’s finding on limitations for the fraud claim; and

(5) we must recalculate the damages owed to Hooks’ based on his most-favored-

nations claim, including the applicable rate of prejudgment interest.

      In a single cross issue, Hooks challenges the trial court’s denial of its motion

for summary judgment on his claims that Samson breached certain offset

obligations with respect to the Hardin County Leases.

      We reverse the trial court’s judgment and remand for a new trial, unless

Hooks accepts the remittitur we suggest below, in which case we will modify the

judgment and affirm as modified.

                        I. SAMSON’S APPEAL ON REMAND

                                   Background

A.    Hooks’ Fraud Claim Relating to the Jefferson County Lease

      In 1999, Hooks entered into an oil and gas lease with Samson covering 640

acres Hooks owns in Jefferson County (the “Jefferson County Lease”). Hooks also

entered into two oil and gas leases with Samson covering tracts in Hardin

County—a 95-acre tract and a 10-acre tract (the “Hardin County Leases”). All

three leases, including the Jefferson County Lease, contained a section called


                                          4
“Offset Obligations,” in which Samson covenanted to operate the leased premises

as a reasonably prudent operator would and to protect the leased premises from

drainage. The offset obligation provision specifically 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) commence with due diligence operations for the actual drilling

of an offset well; (2) pay 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. The

Jefferson County Lease did not provide for pooling.

      The Lease also contained a provision providing for a “late charge” for

unpaid royalties:

      All past due royalties (including any compensatory royalties payable
      under [the offset obligations provision]) shall be subject to a Late
      Charge based on the amount due and calculated at the maximum rate
      allowed by law commencing on the day after the last day on which
      such monthly royalty payment could have been timely made and for
      each calendar month and/or fraction thereof from the date until paid,
      plus attorney’s fees, court costs, and other costs in connection with the
      collection of the unpaid amounts. Any Late Charge that may become
      applicable shall be due and payable on the last day of each month
      when this provision becomes applicable.




                                         5
Hooks’ Leases contained a “most favored nations” clause providing that, under

certain circumstances, the royalties payable to Hooks must be elevated to match

the highest royalty payable to Samson’s other lessors.

      In March 2000, a third-party surveyor created a plat for a proposed gas well,

the Black Stone Minerals No. 1 (“BSM 1 well”), on a tract adjacent to the

Jefferson County Lease. This plat showed that the surface drillsite was outside the

1,320-foot buffer zone around Hooks’ Jefferson County Lease that triggered

Samson’s offset obligations under the Lease. However, the well was a directional

well that slanted away from the surface drillsite, and the plat showed that Samson

planned for a bottom hole location 1,080 feet from Hooks’ Jefferson County Lease.

Samson filed the March 2000 plat with the Railroad Commission of Texas.

      In April 2000, Samson began to drill the BSM 1 well. A directional survey,

completed in July 2000 and also filed with the Railroad Commission, showed that

the BSM 1 well bottomed 1,184 feet from Hooks’ Jefferson County Lease, within

the 1,320-foot buffer zone. Samson completed the BSM 1 well in August 2000,

and the first gas sales occurred in late October 2000.

      Samson then began the process of reconfiguring the BSM 1 pooling unit. A

new plat, dated November 16, 2000, incorrectly placed the well’s bottom hole at

“±1400′ scaled” from the border of Hooks’ Jefferson County Lease. In December

2000, Samson filed a copy of this plat with the Railroad Commission as part of an


                                          6
application to pool. As the supreme court pointed out, the plat was signed by

Samson’s landman, Glenn Lanoue, who certified that it was “a true and correct plat

based on the best of my knowledge.” See Hooks, 457 S.W.3d at 59–60.

      At trial, Lanoue testified regarding the creation of that plat. He did not give

the surveyor the information from the directional survey showing the exact

location of the BSM 1 well bottom hole. Rather, he sent the surveyor information

indicating that the bottom hole of the BSM 1 well was “740 feet from the east line

and 290 feet from the south line,” which resulted in the notation on the plat that the

bottom hole was “±1400′ scaled” from the Jefferson County Lease. He testified at

trial that he created these notations himself. He further testified that 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.”

      On February 15, 2001, Samson sent Hooks a letter offering to pool 50 acres

covered by the Jefferson County Lease into the re-designated BSM 1 pooling unit.

Attached to the letter was a copy of the plat of the reconfigured unit that 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 Hooks’ Jefferson County Lease to permit pooling—

Charles Hooks, a landowner and an attorney who had participated in a number of

oil and gas deals and who managed his family’s oil and gas interests, called


                                           7
Lanoue and sought more information. Charles Hooks inquired about the BSM 1

well’s location and about how his property fit into the proposed pooling unit.

Lanoue told him that the well was about 1,500 feet away from the boundary line of

Hooks’ Jefferson County Lease.

      Hooks requested a plat showing where his acreage would lie within the

proposed reconfigured BSM 1 unit. That same day, Lanoue sent Hooks the scaled

plat of the re-designated BSM 1 pooling unit that Samson had filed with the

Railroad Commission in December 2000. This plat did not use the exact location

of the BSM 1 well’s bottom hole as determined by the directional survey

completed in July 2000, but showed that it was “1,400′± FEL Unit,” or

approximately 1,400 feet from the eastern line of the BSM unit. The coordinates

for the bottom hole location placed the well outside the Jefferson County Lease’s

buffer zone.

      Hooks testified that he understood the plat to show the bottom hole location

as falling outside the buffer zone for his lease, which he believed confirmed

Lanoue’s representation during their phone call that the bottom hole of the well fell

about 1,500 feet beyond the Jefferson County Lease line. Likewise, Paul Beale, a

geophysicist and vice-president for Samson, agreed that the plat Lanoue sent to

Hooks showed that the well fell outside the buffer zone. Brian Sullivan, one of

Samson’s own expert witnesses, examined the plat Samson had provided to Hooks


                                         8
and testified that, assuming the accuracy of the notation that the bottom hole of the

BSM 1 well was “740 feet” from the east line of the unit, the plat showed that the

scaled distance between the BSM 1 bottom hole and Hooks’ lease was

approximately 1,480 feet. And Nedra Foster, Hooks’ survey expert, testified that

the plat was “fairly clear” that the bottom hole was “about, plus or minus, 1,400

feet” from Hooks’ lease line.

      After making the pooling offer to Hooks, Lanoue executed the designation

of the BSM 1 pooling unit in February 2001 and recorded it in the county’s real

property records on March 7, 2001, showing Hooks as participating in the pool for

the BSM 1 unit. However, Hooks did not actually consent to pool the fifty acres

from his Jefferson County Lease into the BSM 1 unit until May 25, 2001, and he

conditioned his assent on a formal amendment to the Jefferson County Lease

which he was to prepare and submit to Samson. Hooks did not submit the formal

amendment, however, and the parties never executed such an amendment. Instead,

Hooks agreed to a division order setting out his percentage of the unit’s proceeds,

which stated that Samson would pay Hooks royalties based on a stated percentage

of his acreage in the unit to the entire acreage of the BSM 1 unit unless notified

otherwise in writing.

      After Hooks agreed to be included in the BSM 1 unit, Samson sent royalty

checks to Hooks for his unit interest continuing through the time of trial, and


                                         9
Hooks cashed those checks. However, the royalty checks did not include

compensatory royalties calculated under the terms of the offset provision in the

Jefferson County Lease for a well drilled within the 1,320-foot buffer zone. Hooks

asserts that the amount of royalty under the pooling agreement was approximately

one-fourteenth of what he would have received under his contractual right to

compensatory royalties.

      After Hooks agreed to pool fifty acres of his Jefferson County Lease into the

BSM 1 unit, Samson drilled a second well, the Joyce DuJay No. 1 well (“DuJay 1

well”), within the 1,320-foot buffer zone of Hooks’ Jefferson County Lease. That

well was completed in January 2002 and was made part of another pooling unit,

the DuJay 1 unit, in which Hooks also participated and from which he received

royalties. This well was offset by the BSM 1 unit. Hooks testified that no one at

Samson made any fraudulent statements to him specifically regarding the DuJay 1

unit. However, Hooks’ damages expert, Charles Graham, testified that Samson’s

fraud in procuring Hooks’ agreement to pool his lease into the BSM 1 unit led

Hooks to believe that the offset obligations as to the DuJay 1 well were met by the

BSM 1 well.

B.    Procedural History

      In the fall of 2006, Charles Hooks attended a seminar for oil and gas

attorneys and met another attorney who was representing some third-party lessors


                                        10
in a lawsuit against Samson based on complaints of pooling issues unrelated to the

BSM 1 well. On November 16, 2006, Hooks joined that lawsuit, but his claims

were later severed into this separate cause of action. Hooks originally asserted

causes of action for breach of contract and common law and statutory negligence.

After obtaining discovery that revealed the misleading nature of the information he

received from Samson prior to consenting to pool a portion of his Jefferson County

Lease into the BSM 1 unit, Hooks amended his suit in May 2007 to add his fraud

claims.

      The trial court rendered partial summary judgment on some of Hooks’

claims. Relevant to our consideration of this case on remand, the trial court

rendered summary judgment in Hooks’ favor on his claim that Samson breached

the most-favored-nations clause.

      Hooks presented expert testimony and documents supporting his claim for

damages, including evidence of what the compensatory royalties would have been

for both the BSM 1 and DuJay 1 wells had he not been fraudulently induced into

pooling rather than enforcing the offset obligations in the Jefferson County Lease.

The expert evidence demonstrated that the unpaid compensatory royalties for

production from the BSM 1 well totaled $3,553,200.15; the unpaid compensatory

royalties for production from the DuJay 1 well totaled $3,112,015.22; the unpaid




                                        11
royalty on “formation production”1 from the BSM 1 well totaled $504,368.64; the

unpaid royalty on formation production from the DuJay 1 well totaled

$426,550.01; the amounts due under the Lease’s late charge provision totaled

$12,995,832.05; and the credit to Samson for royalties it had already paid under

the fraudulent pooling agreement totaled $510,328.01.

      Regarding the jury charge, Samson objected to a portion of the charge on

fraud. It specifically objected to the inclusion of the statement, “You are instructed

that when a party makes a representation and later acquires new information which

makes the representation untrue or misleading, the party must disclose such

information to anyone whom he knows to be still acting on the basis of the original

statement.” However, it did not object to the remainder of the fraud question

setting out the elements of fraud, defining “misrepresentation” as meaning “a false

statement of fact,” and providing an instruction that fraud can also occur when a

party fails to disclose a material fact under certain circumstances. The trial court

overruled Samson’s objection.




1
      Formation Production is the calculation of the total amount of natural gas taken
      from a gas 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. Samson Lone Star, Ltd. P’ship, 389 S.W.3d 409,
      436 (Tex. App.—Houston [1st Dist.] 2012), aff’d in part and rev’d in part, 457
      S.W.3d 52 (Tex. 2015).
                                           12
      Samson also objected to the instruction on damages. It argued that allowing

the jury to consider “lost income to the Hooks that was a natural, probable, and

foreseeable consequence of Samson’s fraud” was not the proper measure of

damages. It argued that the “[p]roper measure of damages in a fraud case is what

you gave up versus what you received.” Samson asserted that the alleged fraud

induced Hooks to give up “his right to sue Samson in February of 2001 for breach

of contract, which means the measure of damages is what was the value of that

breach of contract lawsuit that he gave up in February versus what he actually

ended up receiving.” Hooks argued that the instruction properly addressed

proximate cause for consequential damages. The trial court denied Samson’s

objection.

      Hooks and Samson agreed to certain stipulations that were entered into the

trial court’s record. Regarding damages, the parties stipulated to the amount of

damages for “[u]npaid royalty on production through May 2008, plus late charges

as of August 1, 2008,” for the various wells and units both including and not

including Hooks’ claims for royalties based on formation production. They

stipulated to $212,825.25 in lost royalties and $218,625.46 in late charges for the

DuJay 1 well and unit. The parties also entered into a stipulation regarding

attorney’s fees.




                                        13
      The jury found that Samson committed fraud against Hooks. It further found

that the sum of money that would fairly and reasonably compensate Hooks for the

damages proximately caused by such fraud was $20,081,638.07. Finally, the jury

found that Hooks, in the exercise of reasonable diligence, should have discovered

Samson’s fraud by “Hooks’ Birthday April 2007.”2

      Pursuant to the jury’s findings, the trial court’s summary judgment ruling on

Hooks’ claim for breach of the most-favored-nations clause, and the stipulations of

the parties, the trial court rendered judgment in favor of Hooks, awarding

$20,081,638.07 for damages proximately caused by fraud, $848,854.01 as damages

for breach of the most-favored-nations clause, and damages related to ad valorem

taxes in the amount of $52,257.22.3 The trial court also awarded Hooks attorney’s

fees consistent with the parties’ stipulation on that issue, and it awarded expert

witness fees, costs for copies of depositions, pre-judgment interest, and post-

judgment interest at a rate of 18% compounded annually.

                                         Fraud

      Samson challenges the sufficiency of the evidence of the jury’s findings

relating to Hooks’ fraud claims.

2
      Hooks’ birthday is not in April, but this is what the jury answered.
3
      The trial court also awarded Hooks $766,626.85 as damages for his “unpooling”
      claim related to yet another well, the Black Stone Minerals A-1 well. We reversed
      this portion of the trial court’s judgment, and the supreme court affirmed our
      judgment on this issue.
                                           14
A.    Standard of Review

      In reviewing a legal sufficiency challenge to the evidence, we view the

evidence in the light most favorable to the finding, crediting favorable evidence if

a reasonable factfinder could, and disregarding contrary evidence unless a

reasonable factfinder could not. City of Keller v. Wilson, 168 S.W.3d 802, 827

(Tex. 2005). A party bringing a legal sufficiency challenge to a finding on which it

did not have the burden of proof must demonstrate that there is no evidence to

support the adverse finding. See Exxon Corp. v. Emerald Oil & Gas Co., 348

S.W.3d 194, 215 (Tex. 2011). We may not sustain a legal sufficiency or no-

evidence point unless the record demonstrates that: (1) there is a complete absence

of evidence of a vital fact; (2) the court is barred by the rules of law or of evidence

from giving weight to the only evidence offered to prove a vital fact; (3) the

evidence to prove a vital fact is no more than a scintilla; or (4) the evidence

established conclusively the opposite of the vital fact. City of Keller, 168 S.W.3d at

810. The factfinder is the sole judge of the witnesses’ credibility and the weight to

give their testimony. Id. at 819.

      In reviewing the factual sufficiency of the evidence, we are required to

examine all of the evidence, and we will set aside the judgment only if it is so

contrary to the overwhelming weight of the evidence as to be clearly wrong and

unjust. Cain v. Bain, 709 S.W.2d 175, 176 (Tex. 1986). Unlike a legal-sufficiency


                                          15
review, a factual-sufficiency review requires that we review the evidence in a

neutral light. Id.; Nelson v. Najm, 127 S.W.3d 170, 174 (Tex. App.—Houston [1st

Dist.] 2003, pet. denied). The factfinder may choose to “believe one witness and

disbelieve others” and “may resolve inconsistencies in the testimony of any

witness.” McGalliard v. Kuhlmann, 722 S.W.2d 694, 697 (Tex. 1986); see also

City of Keller, 168 S.W.3d at 819–21.

B.    Statute of Limitations for Fraud

      Samson challenges the factual sufficiency of the evidence supporting the

jury’s finding that, exercising reasonable diligence, Hooks could not have

discovered his fraud claim until April 2007. The supreme court determined that the

question of when Hooks could have discovered Samson’s fraud was properly a

question of fact for the jury and that the evidence was legally sufficient to support

the jury’s finding that Hooks could not have discovered Samson’s fraud until April

2007. See Hooks, 457 S.W.3d at 61. It remanded the issue for us to consider the

factual sufficiency of the evidence supporting the jury’s finding. See id. Samson

now argues that Hooks’ testimony stated only when he discovered the claim and

that he did not testify as to “why, in the exercise of reasonable diligence (as an

experienced oil and gas attorney and mineral owner), he could not have discovered

his claim earlier.”




                                         16
      As a general rule, a cause of action accrues and the limitations period begins

to run when facts come into existence that authorize a party to seek a judicial

remedy. Exxon Corp., 348 S.W.3d at 202. Generally, the limitations period for a

fraud claim is four years. TEX. CIV. PRAC. & REM. CODE ANN. § 16.004 (Vernon

2002). However, under certain circumstances, limitations will not begin to run

until the plaintiff “knew or should have known of facts that in the exercise of

reasonable diligence would have led to the discovery of the wrongful act.” Exxon

Corp., 348 S.W.3d at 216; see also Hooks, 457 S.W.3d at 56–57 (discussing

discovery rule in relation to this case). Here, the supreme court held that “[b]ecause

‘fraud vitiates whatever it touches,’ limitations does not start to run until the fraud

is discovered or the exercise of reasonable diligence would discover it.” Hooks,

457 S.W.3d at 57 (quoting Borderlon v. Peck, 661 S.W.2d 907, 909 (Tex. 1983)

and citing BP Am. Prod. Co. v. Marshall, 342 S.W.3d 59, 69 (Tex. 2011)).

      The supreme court further held “that when the defendant’s fraudulent

misrepresentations extend to the Railroad Commission record itself, earlier

inconsistent filings cannot be used to establish, as a matter of law, that reasonable

diligence was not exercised. Under these circumstances, reasonable diligence

remains a fact question.” Hooks, 457 S.W.3d at 61. The supreme court went on to

state that “[t]he factfinder, no doubt, may consider [Hooks’] failure to examine

older records when determining whether reasonable diligence was exercised, but


                                          17
their availability is not enough to establish that reasonable diligence was not

exercised as a matter of law.” Id. Accordingly, because the supreme court

remanded for us to consider the factual sufficiency of the evidence supporting the

jury’s finding, we are required to examine all of the evidence in a neutral light, and

we will set aside the jury’s verdict only if it is so contrary to the overwhelming

weight of the evidence as to be clearly wrong and unjust. See Cain, 709 S.W.2d at

176.

       The evidence at trial showed that the public records themselves were

inconsistent. Samson originally filed the March 2000 plat with the Railroad

Commission showing the proposed location of the BSM 1 well. It showed that

Samson planned for a bottom hole location 1,080 feet from Hooks’ Jefferson

County Lease. Samson also filed a directional survey, completed in July 2000,

showing that the BSM 1 well bottomed 1,184 feet from Hooks’ Jefferson County

Lease, within the 1,320-foot buffer zone. However, Samson subsequently filed a

new plat, dated November 16, 2000, that incorrectly placed the well’s bottom hole

at “±1400′ scaled” from the border of Hooks’ Jefferson County Lease. This is the

same plat that Samson sent to Hooks to procure his consent to pool a portion of his

lease into the BSM 1 unit.

       Although Hooks did not testify explicitly regarding why he did not discover

the fraud claim earlier, he did testify that he inquired with Samson, by speaking


                                         18
with Glenn Lanoue, about the exact location of the well and his Lease’s location

within the BSM 1 pooling unit because he wanted to know whether the well drilled

close to his lease line might trigger the offset obligations. He also testified that he

requested a plat to confirm Lanoue’s representation that the well’s bottom hole was

located 1,500 feet from his Lease. The information that Samson gave him did not

convey the exact location of the well’s bottom hole as established by the

directional survey, but instead identified the location of the well’s bottom hole as

“±1400′ scaled” from the border of Hooks’ Jefferson County Lease. Hooks

testified that he understood this notation to confirm Lanoue’s representation over

the phone that the well fell outside the buffer zone for his Jefferson County Lease,

and he relied upon those representations. Although some experts acknowledged

that the “±” notion implied that there could be as much as a 100-foot margin on the

measurements, others—including Beale, Samson’s vice president, and Foster,

Hooks’ survey expert—testified that the plat showed that the well’s bottom hole

fell outside the buffer zone, consistent with Hooks’ own interpretation.

      Hooks testified that he was an attorney and had extensive experience with

the oil and gas industry. He further testified that he did not become aware of larger

problems with his lease until he attended the oil and gas conference in Fall 2006

and learned of litigation pending against Samson. During the course of litigation,

Samson produced documents through discovery that revealed the actual location of


                                          19
the BSM 1 well’s bottom hole and Samson’s use of misleading plats to obtain his

consent to pool.

      In light of this conflicting evidence, the jury had the discretion to resolve the

conflicts by determining that Hooks had exercised reasonable diligence in

requesting information from Samson and that the existence of relevant information

buried within conflicting public records did not sufficiently put him on notice of

his fraud claims prior to April 2007. See Exxon Corp., 348 S.W.3d at 216; see also

Hooks, 457 S.W.3d at 56–57.

      We overrule Samson’s challenge to the factual sufficiency of the evidence

supporting the jury’s finding that Hooks, in the exercise of reasonable diligence,

would not have necessarily discovered his fraud claim prior to April 2007.

C.    Fraud Claims

      Samson challenges the legal and factual sufficiency of Hooks’ common-law

and statutory fraud claims.

      To prevail on a fraud claim, the plaintiff must prove that the defendant

(1) made a material misrepresentation, (2) knew the representation was false or

made it recklessly without any knowledge of its truth, (3) intended that the plaintiff

would act upon the representation or intended to induce the plaintiff’s reliance on

the representation, and that (4) the plaintiff justifiably relied upon the

representation and thereby suffered injury. Exxon Corp., 348 S.W.3d at 217. To


                                          20
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.).

        1.     Material Misrepresentation

      First, Samson argues that the evidence was insufficient to show that it made

an actionable misrepresentation. Samson argues that “[t]he plat was marked

‘scaled,’ meaning it was inexact and the distance upon which [Hooks] testified he

relied said ‘1400′± Scaled.’” It asserts that this notation was “too indefinite to form

the basis of a misrepresentation when someone is attempting to determine whether

a well is 1320 feet from a lease line.”

      A material representation is one which “a reasonable person would attach

importance to and would be induced to act on . . . in determining his choice of

actions in the transaction in question.” Italian Cowboy Partners, Ltd. v. Prudential

Ins. Co. of Am., 341 S.W.3d 323, 337 (Tex. 2011) (quoting Smith v. KNC Optical,

Inc., 296 S.W.3d 807, 812 (Tex. App.—Dallas 2009, no pet.)). However, “[v]ague

representations cannot constitute a material representation actionable under our

laws.” Cadle Co. v. Davis, No. 04-09-00763-CV, 2010 WL 5545389, at *8 (Tex.

App.—San Antonio Dec. 29, 2010, pet. denied) (mem. op.) (citing In re Media

Arts Grp., Inc., 116 S.W.3d 900, 910 (Tex. App.—Houston [14th Dist.] 2003, orig.

proceeding [man. denied]) (statement “don’t worry about it” was too vague to


                                          21
constitute material misrepresentation in claim of fraudulent inducement); Bank

One, Tex., N.A. v. Little, 978 S.W.2d 272, 280 (Tex. App.—Fort Worth 1998, pet.

denied) (imprecise or vague representation constitutes mere opinion and is not

actionable misrepresentation under DTPA); Hedley Feedlot, Inc., v. Weatherly

Trust, 855 S.W.2d 826, 839 (Tex. App.—Amarillo 1993, writ denied) (imprecise

statement not actionable misrepresentation under DTPA)).

      Hooks testified that, before agreeing to pool a portion of his lease into the

BSM 1 unit, he contacted Lanoue to inquire about the BMS 1 well’s location and

about how his property fit into the unit. During their phone conversation, Lanoue

represented that the BSM 1 well was located 1,500 feet from the boundary of

Hooks’ lease. Lanoue subsequently sent Hooks a copy of the plat that Samson had

filed with the Railroad Commission in December 2000 to confirm his

representation regarding the well’s location. This plat did not use the exact location

of the BSM 1 well’s bottom hole as determined by the directional survey

completed in July 2000, but instead showed that it was “1,400′± FEL Unit,” or

approximately 1400 feet from the eastern line of the BSM unit. The coordinates for

the bottom hole location placed the well outside the Jefferson County Lease’s

1,320-foot buffer zone. Hooks testified that he understood the plat sent to him by

Lanoue to show that the bottom hole’s location fell outside the buffer zone for his

lease, which he believed confirmed Lanoue’s representation during their phone call


                                         22
that the bottom hole of the well fell about 1,500 feet beyond the Jefferson County

Lease line.

      Although Lanoue’s representation over the phone and the notations on the

plat regarding the location of the well were not precise, neither were they such

vague or imprecise representations that they cannot constitute a material

representation for fraud purposes. See Cadle Co., 2010 WL 5545389, at *8; In re

Media Arts Group, Inc., 116 S.W.3d at 910. This is especially true here, where the

exact location of the well was highly relevant to Hooks’ decision regarding pooling

and both parties were aware of the circumstances that made the location of the

well’s bottom hole material, such that Samson should have known that Hooks

would rely on its information. In representing the location of the BSM 1 well’s

bottom hole, Samson—as the party with superior access to the relevant

information—provided an answer to Hooks’ inquiry’s regarding the location of the

well and his lease’s location within the proposed pooling unit by supplying

inaccurate or imprecise information even though it had a survey showing the exact

location of the well’s bottom hole. Hooks testified that he relied on the answer to

this inquiry when he agreed to pool fifty acres of his Jefferson County Lease into

the BSM 1 unit at Samson’s request. See Italian Cowboy, 341 S.W.3d at 337

(stating that material representation is one which “a reasonable person would

attach importance to and would be induced to act on”).


                                        23
      We conclude that the record contains legally sufficient evidence of an

actionable, material misrepresentation. See Italian Cowboy, 341 S.W.3d at 337;

City of Keller, 168 S.W.3d at 827.

      Samson points out that witnesses acknowledged that there could be as much

as a 100 foot “tolerance.” However, other witnesses, including Hooks—an attorney

with extensive experience managing oil and gas deals—Hooks’ survey expert,

Foster, and Beale, Samson’s vice-president, testified that the plat demonstrated that

the BSM 1 well was located outside the buffer zone. The jury was the exclusive

judge of the credibility of these witnesses and the weight to be given to their

testimony, and it was entitled to “believe one witness and disbelieve others” and

“resolve conflicts” in the evidence. See City of Keller, 168 S.W.3d at 819–21;

McGalliard, 722 S.W.2d at 697. Thus, we conclude that the evidence was likewise

factually sufficient to demonstrate the existence of a material misrepresentation.

        2.     Intent to Induce Reliance

      Samson also argues that there is no evidence it had any intent to defraud

Hooks when it supplied the plat. In Texas’s fraud jurisprudence, courts considering

the intent element focus on the defendant’s knowledge and intent to induce

reliance. Ernst & Young, L.L.P. v. Pac. Mut. Life Ins. Co., 51 S.W.3d 573, 578

(Tex. 2001). A defendant who acts with knowledge that a result will follow is

considered to intend the result. Id. at 579. A party’s intent is determined at the time


                                           24
that it makes the complained-of representation; however, intent may be inferred

from the party’s acts made after the representation. Aquaplex Inc. v. Rancho La

Valencia, Inc., 297 S.W.3d 768, 775 (Tex. 2009). “[I]ntent to defraud is not usually

susceptible to direct proof.” Id. at 774–75. Thus, intent to defraud, or intent to

induce reliance, most often must be proven by circumstantial evidence. Spoljaric v.

Percival Tours, Inc., 708 S.W.2d 432, 435 (Tex. 1986). “Intent is a fact question

uniquely within the realm of the trier of fact because it so depends upon the

credibility of the witnesses and the weight to be given to their testimony.” Id. at

434.

       In response to Samson’s request that he pool a portion of his Jefferson

County Lease into the BSM 1 unit, Hooks made inquiries regarding the location of

the BSM 1 well and his Lease’s location within the unit. At the time of this

inquiry, Samson had already received the results of the directional survey showing

the exact location of the BSM 1 well’s bottom hole to be 1,184 feet from Hooks’

Jefferson County Lease, within the buffer zone. And it had filed a plate with this

information with the Railroad Commission. Nevertheless, Lanoue told Hooks over

the phone that the well was 1,500 feet away from his lease line, which was outside

the buffer zone, and Samson sent Hooks a plat showing that the well’s bottom hole

was “1400′±” from Hooks’ lease line, which was likewise outside the buffer zone.

After making the pooling offer to Hooks, but before Hooks agreed to pool, Lanoue


                                        25
executed the designation of the BSM 1 pooling unit in February 2001 and recorded

it in the county’s real property records on March 7, 2001, showing Hooks as

participating in the pool for the BSM 1 unit.

      The timing of these actions—that Samson used an inaccurate and misleading

plat when it already knew the exact location of the bottom hole in addressing

Hooks’ inquiries related to pooling a portion of lease and that Samson filed

documents with the Railroad Commission indicating that Hooks was part of the

pooling unit before he consented to the pooling—is circumstantial evidence of

Samson’s intent to induce Hooks’ reliance on its representations in agreeing to

pool. See Aquaplex Inc., 297 S.W.3d at 775; Spoljaric, 708 S.W.2d at 435. The

record indicates that, at the time it misrepresented the location of the BSM 1 well’s

bottom hole, Samson knew that it had drilled the well within the Jefferson County

Lease’s buffer zone, thereby triggering the offset obligations under the terms of the

Lease. Rather than meet its obligations, Samson sought Hooks’ consent to pool. In

the course of obtaining Hooks’ consent, it used an inaccurate plat. The payments

that Samson made to Hooks under the pooling agreement were considerably less

than the payments that would have been due under the compensatory royalty

provision in the Jefferson County Lease’s offset obligations.

      Samson points to Lanoue’s testimony that he thought Hooks wanted the plat

to see where his lease was located within the unit, and the plat accurately


                                         26
represented that information. Hooks himself admitted that he might not have told

Samson why he cared about the locations of the BSM 1 well. However, the jury

considered all of the testimony and evidence presented, as recounted above, and

this evidence is not so overwhelming as to render the jury’s findings clearly wrong

and unjust. See Cain, 709 S.W.2d at 176.

      Considering Samson’s knowledge and the circumstantial evidence of its

intent to induce reliance, we conclude that the evidence was legally and factually

sufficient to demonstrate intent. See Ernst & Young, L.L.P., 51 S.W.3d at 578; see

also City of Keller, 168 S.W.3d at 827.

        3.    Justifiable Reliance

      Samson argues that Hooks ignored the “±” part of the plat and “could not

justifiably have relied on such an indefinite measurement when he was looking for

a precise answer to his supposed question—a question he never even posed to

Samson.”

      Fraud also requires that the plaintiff show actual and justifiable reliance.

Grant Thornton LLP v. Prospect High Income Fund, 314 S.W.3d 913, 923 (Tex.

2010). “In measuring justifiability, we must inquire whether, ‘given a fraud

plaintiff’s individual characteristics, abilities, and appreciation of facts and

circumstances at or before the time of the alleged fraud[,] it is extremely unlikely

that there is actual reliance on the plaintiff’s part.’” Id. (quoting Haralson v. E.F.


                                          27
Hutton Grp., Inc., 919 F.2d 1014, 1026 (5th Cir. 1990)). Reliance is not justified if

there are “red flags” indicating such reliance is unwarranted. Id. The plaintiff must

prove that based on the alleged misrepresentation, he either took an action or failed

to take an action, which caused him harm. O & B Farms, Inc. v. Black, 300 S.W.3d

418, 421 (Tex. App.—Houston [14th Dist.] 2009, pet. denied); see also Van

Marcontell v. Jacoby, 260 S.W.3d 686, 691 (Tex. App.—Dallas 2008, no pet.) (“A

plaintiff establishes reliance by showing the defendant’s acts and representations

induced him to either act or refrain from acting, to his detriment.”). The issue of

justifiable reliance is generally a question of fact.4 See Prize Energy Res., L.P. v.

Cliff Hoskins, Inc., 345 S.W.3d 537, 584 (Tex. App.—San Antonio 2011, no pet.);

1001 McKinney Ltd. v. Credit Suisse First Bos. Mortg. Capital, 192 S.W.3d 20, 30

(Tex. App.—Houston [14th Dist.] 2005, pet. denied).

4
      The issue of justifiable reliance may become a question of law when the
      undisputed or conclusively proven facts demonstrate circumstances under which
      reliance cannot be justified—such as when the party had actual knowledge of the
      representation’s falsity or the representation directly contradicts the express terms
      of a written agreement. See, e.g., JSC Neftegas-Impex v. Citibank, N.A., 365
      S.W.3d 387, 407–09 (Tex. App.—Houston [1st Dist.] 2011, pet. denied) (op. on
      reh’g) (reliance on representation not justified, as matter of law, when party had
      actual knowledge of representation’s falsity); DeClaire v. G & B McIntosh Family
      Ltd. P’ship, 260 S.W.3d 34, 47 (Tex. App.—Houston [1st Dist.] 2008, no pet.)
      (“[R]eliance upon an oral representation that is directly contradicted by the
      express, unambiguous terms of a written agreement between the parties is not
      justified as a matter of law.”). However, the circumstances here raise a question of
      fact. Just as the question of what constituted reasonable diligence in discovering
      the fraud was a fact issue to be determined by the jury, see Hooks, 457 S.W.3d at
      60, so too is the question of whether Hooks was justified in relying on Samson’s
      verbal and written representations where there was some contradicting information
      available in the public record.
                                           28
      Hooks is an attorney with considerable experience managing oil and gas

interests. He testified that he inquired about the exact location of the well and of

his Lease within the BSM 1 pooling unit because it was important to him to know

whether the well was within the buffer zone of his Jefferson County Lease.

Hooks—like Samson itself—was aware of the offset obligations in the Jefferson

County Lease that could be triggered by drilling close to his Lease line. He

testified that he would not have consented to pool if he had known that the bottom

hole of the well actually fell within the buffer zone. Furthermore, other witnesses,

including Beale and Foster, testified that it was reasonable to interpret the plat

relied upon by Hooks—the same plat Samson had filed with the Railroad

Commission—as showing that the well fell outside the buffer zone.

      Thus, there was sufficient evidence to support the jury’s determination that,

given his individual characteristics, abilities, and appreciation of facts and

circumstances here, Hooks justifiably relied upon Samson’s representations

regarding the location of the well. See Grant Thornton LLP, 314 S.W.3d at 923.

The facts that the plat included notations that the distances were “scaled” and

included a “±” marking—indications that it might not be exact—are not sufficient

to undermine the evidence supporting the jury’s finding of Hooks’ justifiable

reliance. See id. Samson’s verbal and written representations about the location of

the BSM 1 well’s bottom hole were made in response to Hooks’ inquiry about the


                                        29
exact nature of the BSM 1 pooling unit that Samson sought to create. Samson had

also filed the same plat in the Railroad Commission records, thus extending its

misrepresentation into the public record. Hooks testified that he agreed to pool

based on Samson’s misrepresentations regarding the well’s bottom hole location

and that he would not have consented to the pooling if he had known that the well

fell within the buffer zone of his Jefferson County Lease, thereby triggering the

offset obligations. The evidence also established that his reliance on Samson’s

misrepresentation caused him harm, because the royalties he received as part of the

BSM 1 unit were much lower than the compensatory royalties he was entitled to

under the terms of his Lease. See O & B Farms, Inc., 300 S.W.3d at 421.

      Samson argues that it did not know Hooks was relying on the plat in the way

he testified—as evidence of the location of the BSM 1 well’s bottom hole.

However, as discussed above, both Hooks and Samson were aware of the offset

obligations in the Jefferson County Lease, and Hooks testified regarding his

reasons for seeking additional information before agreeing to pool. Because the

record supports the jury’s conclusion that Samson’s misrepresentation was material

to the transaction and made with the intent to induce his reliance upon it, Samson’s

specific knowledge of the reasons for Hooks’ inquiry is irrelevant. See Exxon

Corp., 348 S.W.3d at 217 (setting out elements of fraud); Italian Cowboy Partners,




                                        30
Ltd., 341 S.W.3d at 337 (holding that material representation is one which “a

reasonable person would attach importance to and would be induced to act on”).

      Samson also argues that Hooks did not continue to rely on the plat after

consenting to the unit and that he had an equal opportunity to discover the truth

through “multiple public records.” However, intent to induce reliance and

justifiable reliance are determined at the time of the alleged fraud. See Grant

Thornton LLP, 314 S.W.3d at 923 (“In measuring justifiability, we must inquire

whether, ‘given a fraud plaintiff’s individual characteristics, abilities, and

appreciation of facts and circumstances at or before the time of the alleged fraud[,]

it is extremely unlikely that there is actual reliance on the plaintiff’s part.’”)

(emphasis added, brackets in original); Aquaplex Inc., 297 S.W.3d at 775 (holding

that party’s intent is determined at time that it makes complained-of

representation).

      Furthermore, the public records themselves were inconsistent. As discussed

above, Samson originally filed the March 2000 plat with the Railroad Commission.

This plat showed the proposed locations of the BSM 1 well, indicating that the

surface drillsite was outside the 1,320-foot buffer zone, but the bottom hole

location was planned to fall 1,080 feet from Hooks’ Jefferson County Lease.

Samson also filed a directional survey, completed in July 2000, showing that the

BSM 1 well bottomed 1,184 feet from Hooks’ Jefferson County Lease, within the


                                         31
1,320-foot buffer zone. Samson subsequently reconfigured the BSM 1 pooling unit

and filed a new plat, dated November 16, 2000, that incorrectly placed the well’s

bottom hole at “±1400′ scaled” from the border of Hooks’ Jefferson County Lease.

This is the same plat that Samson sent to Hooks to procure his consent to pool a

portion of his lease into the BSM 1 unit. In light of this conflicting evidence, the

jury had the discretion to resolve the conflicts by determining that the public

records did not provide Hooks with an equal opportunity to discover the location of

the well’s bottom hole.

      We overrule Samson’s challenges to the legal and factual sufficiency of the

evidence supporting the jury’s findings on Hooks’ common-law fraud claim.5


5
      Samson argues that it had no duty to disclose the location of the well’s bottom
      hole, as a matter of law, and that there was no evidence that is breached such a
      duty. The existence of a duty to disclose is relevant when a failure to disclose is
      the basis of a fraud cause of action. See Bradford v. Vento, 48 S.W.3d 749, 755
      (Tex. 2001) (holding that in absence of duty to disclose, failure to disclose
      generally cannot serve as evidence of fraud). Here, however, Hooks’ fraud claim
      is based on Samson’s affirmative misrepresentation. Thus we need not determine
      whether Samson had a duty to disclose.
              Samson also complains that the trial court erred in submitting a failure to
      disclose instruction to the jury in the question on fraud, but it did not object to the
      portion of the jury charge instructing the jury that fraud could be based on a failure
      to disclose. It objected only to the inclusion of the legally correct statement that a
      party who has already made a representation must also disclose newly acquired
      information that makes the previous representation untrue or misleading. See, e.g.,
      Ginn v. NCI Bldg. Sys., Inc., 472 S.W.3d 802, 836 (Tex. App.—Houston [1st
      Dist.] 2015, no pet.) (stating that duty to disclose may arise when one party makes
      representation, which gives rise to duty to disclose new information that party is
      aware makes earlier representation misleading or untrue) (citing Solutioneers
      Consulting, Ltd. v. Gulf Greyhound Partners, Ltd., 237 S.W.3d 379, 385 (Tex.
      App.—Houston [14th Dist.] 2007, no pet.)). Thus, this argument is unavailing.
                                            32
D.    Fraud Damages

      Samson challenges the legal and factual sufficiency of Hooks’ fraud

damages evidence.6

      The jury determined that $20,081,638.01 “would fairly and reasonably

compensate [Hooks] for [his] damages, if any, that were proximately caused by”

Samson’s fraud. The charge instructed the jury to consider the “[l]ost income to

[Hooks] that was the natural, probable, and foreseeable consequence of Samson’s

fraud.”

      The amount awarded by the jury corresponds to the amount of compensatory

royalties, including royalty due on formation production and the associated late

charges, due under the terms of the Jefferson County Lease for production from the

BSM 1 and DuJay 1 wells. Samson argues that there is insufficient evidence

supporting the jury’s damages award. Hooks argues that “[u]pon remittitur for the

amount not permitted under the Texas Supreme Court opinion, the damages award

is factually and legally sound.”

          1.   Proper Measure of Damages

      Samson argues that because Hooks “chose to pursue an incorrect measure of

damages, there is no evidence of damages” and “[t]he damages testimony is based

6
      Samson also argues that the evidence supporting Hooks’ statutory fraud claims
      was legally and factually insufficient. Because the jury’s findings regarding
      Hooks’ common-law fraud claim sufficiently support the jury’s findings of
      damages, we need not address these arguments.
                                        33
on a flawed methodology.” Samson argues that, in seeking “lost profits,” Hooks

“proved only the same damages they would have presented for the breach of oil

and gas lease claim they previously lost on summary judgment” and the lost profits

are not properly part of an out-of-pocket damages calculation. Samson further

complains that Hooks’ attempt to categorize his damages as consequential

damages is unavailing, as he did not plead for such damages and is not entitled to

them. Thus, we first consider the proper measure of damages.

      A party may recover actual damages on a successful fraud claim, and, “[a]t

common law, actual damages are either ‘direct’ or ‘consequential.’” Baylor Univ.

v. Sonnichsen, 221 S.W.3d 632, 636 (Tex. 2007) (quoting Arthur Andersen & Co.

v. Perry Equip. Corp., 945 S.W.2d 812, 816 (Tex. 1997)). Generally, “Texas

recognizes two measures of direct damages for common-law fraud: the out-of-

pocket measure and the benefit-of-the bargain measure.” Zorrilla v. Aypco Constr.

II, LLC, 469 S.W.3d 143, 153 (Tex. 2015) (quoting Formosa Plastics Corp. USA v.

Presidio Eng’rs & Contractors, Inc., 960 S.W.2d 41, 49 (Tex. 1998)). The former

“derive[s] from a restitutionary theory” while the latter “derive[s] from an

expectancy theory.” Id. (citing Sonnichsen, 221 S.W.3d at 636). Out-of-pocket

damages are measured by the difference between the value expended versus the

value received, thus allowing the injured party to recover based on the actual injury

suffered. Id. (citing Formosa Plastics, 960 S.W.2d at 49). Benefit-of-the-bargain


                                         34
damages are measured by the difference between the value as represented and the

value received, allowing the injured party to recover profits that would have been

made had the bargain been performed as promised. Id.

      Consequential damages are damages that result naturally but not necessarily

from the wrongful act. Sonnichsen, 221 S.W.3d at 636; Arthur Andersen & Co.,

945 S.W.2d at 816. Consequential damages are recoverable only if the

misrepresentation is a producing cause of the loss, i.e. if the losses are foreseeable

and directly traceable to and result from the misconduct. Arthur Andersen & Co.,

945 S.W.2d at 817; see Formosa Plastics, 960 S.W.2d at 49 n.1 (“When properly

pleaded and proved, consequential damages that are foreseeable and directly

traceable to the fraud and result from it might be recoverable.”). And, unlike direct

damages, consequential damages may include subsequent losses if those losses

were reasonably foreseeable and have the requisite nexus to the wrong. Arthur

Andersen & Co., 945 S.W.2d at 817.

      Samson argues that the lost-income damages found by the jury, reflecting

the compensatory royalties and associated late charges, are a contract measure of

damages. However, the fact that Hooks’ loss was an economic loss related to the

subject matter of his contract with Samson does not prevent his recovery of tort

damages. See Formosa Plastics, 960 S.W.2d at 47 (holding that “tort damages are

not precluded simply because a fraudulent representation causes only an economic


                                         35
loss”). The jury was asked to determine the amount of money that would

compensate Hooks for the damages proximately caused by Samson’s fraud and

was told to consider the “[l]ost income to [Hooks] that was the natural, probable,

and foreseeable consequence of Samson’s fraud.” This is a proper measure of

consequential damages, which are recoverable as fraud damages so long as Hooks

properly pleaded and proved them. See Formosa Plastics, 960 S.W.2d at 49 n.1;

Arthur Andersen & Co., 945 S.W.2d at 817.

      Samson also argues that Hooks did not properly plead for consequential

damages. See Formosa Plastics, 960 S.W.2d at 49 n.1. However, as Hooks argues,

he pleaded for “damages for injuries that were the proximate result of Samson’s

fraud,” and he specifically pleaded that those damages were “equal to at least the

compensatory royalties [Hooks] would have been due under [his] Jefferson County

Lease in the absence of any purported pooling.” In his sixth amended petition—the

first petition including his fraud claim—Hooks alleged that he was “injured as a

direct, proximate, natural, and reasonable result of Samson’s false representations.”

He contended that Samson’s fraud vitiated the pooling agreement, and thus his

interests “were not pooled into the [BSM 1 well and unit,]” but he recognized that

“Samson contends otherwise.” Hooks alleged that “if Samson is correct that the

Hooks Interest[s] were pooled into [the BSM 1 well and unit], [he] [is] entitled to

damages equal to at least the difference between the value of that with which [he]


                                         36
parted, and the value [he] actually received, as a result of Samson’s false

representations. Such damages would equal at least the compensatory royalties [he]

would have been due under [his] Jefferson County Lease in the absence of any

purposed pooling. . . .” Hooks maintained these claims throughout trial. Thus, the

pleadings adequately put Samson on notice of the damages being sought by Hooks.

See Horizon CMS Healthcare Corp. v. Auld, 34 S.W.3d 887, 897 (Tex. 2000)

(discussing fair notice rule).

      Samson further argues that Hooks “could not seek compensatory damages”

unless he sought to set aside his consent to pool a portion of his Jefferson County

Lease into the BSM 1 unit. Samson cites Fortune Production Co. v. Conoco, Inc.,

52 S.W.3d 671 (Tex. 2000), to support its contention that Hooks “could stand on

the bargain and recover fraud damages, or [he] could seek rescission of the consent

to pool” but he “could not do both.” Fortune Production does not support

Samson’s argument. In that case, the supreme court stated that “there may be

circumstances under which a party who was induced to enter a contract by fraud

may ratify that contract in such a manner that a claim for damages is foreclosed,”

and it held that the evidence of ratification in that case was legally sufficient to

foreclose some portion of the plaintiffs’ claims for damages. Id. at 676. Here, by

contrast, Hooks did not ratify the BSM 1 pooling agreement. Instead, Hooks filed

his fraud claim upon learning of Samson’s misrepresentation, thus demonstrating


                                        37
his intent to pursue fraud damages rather than to ratify or to rescind the

fraudulently induced agreement. See id. at 676–77.

        2.    Sufficiency of the Evidence of the Amount of Damages

      We turn next to the legal and factual sufficiency of the evidence supporting

the jury’s award of fraud damages totaling $20,081,638.01. The evidence at trial

indicated that Samson’s drilling of the BSM 1 well triggered the offset obligations

in the Jefferson County Lease. Samson neither drilled an offset well nor released

Hooks’ lease within ninety days of first production from this well, which left only

the remedy of payment of compensatory royalties. See Hooks, 457 S.W.3d at 68

(addressing question of whether, “because the contract gave Samson alternatives

that were not recurring, Samson may prevent Hooks from suing based on the one

recurring obligation”). However, Samson never paid these compensatory royalties

because it fraudulently induced Hooks into pooling a portion of his Jefferson

County Lease into the BSM 1 unit and subsequently paid him the lower royalties

due under the terms of that deal.

      Hooks testified that Samson did not make any fraudulent misrepresentations

to him specifically regarding the DuJay 1 well. However, he presented evidence

that Samson drilled the DuJay 1 well within the buffer zone of its Jefferson County

Lease, also triggering offset obligations under the terms of the lease. However,

Hooks’ damages expert, Charles Graham, testified that Samson’s fraud in


                                        38
procuring Hooks’ agreement to pool his lease into the BSM 1 unit led Hooks to

believe that the offset obligations as to the DuJay 1 well were met by the BSM 1

well.

        Hooks presented Graham’s testimony and other evidence of the amount of

the compensatory royalties and late charges he would have received under the

terms of the Lease. He also provided evidence of the amount of royalties Samson

paid under the fraudulently procured consent to pool. Graham testified that his

opinion was based on the language of Hooks’ Jefferson County Lease as applied to

Samson’s production and sales from the relevant wells. He stated that damages that

resulted from Samson’s misleading Hooks into agreeing to pool his Jefferson

County Lease into the BSM 1 unit included the compensatory royalties that would

have been due under the Lease’s offset obligations, which included $3,553,200.15

in unpaid compensatory royalties for production from the BSM 1 well and

$3,112,015.22 in unpaid compensatory royalties for production from the DuJay 1

well. He also testified that Samson’s fraud resulted in Hooks’ losing $930,918.65

in unpaid royalties for formation production and $12,995,832.05 in late charges for

unpaid royalties. Finally, Graham testified that Samson should be credited with

$510,328.01 for royalties that it paid pursuant to the fraudulently obtained pooling

agreement.




                                        39
             a. DuJay 1 well damages

      Samson argues that “[e]ven if consequential damages were permitted, ‘lost

profits’ based on the DuJay 1 well are not recoverable.” Samson argues that Hooks

admitted he was not defrauded as to the DuJay 1 well but “[a]pproximately half” of

his claim fraud damages were attributable to that well. Furthermore, “to the extent

[Hooks sought] compensatory royalty damages for the DuJay 1 well,” there was no

evidence, or insufficient evidence, supporting that claim.

      The evidence demonstrated that Samson completed the DuJay 1 well within

the buffer zone of Hooks’ Jefferson County Lease, which, like the BSM 1 well,

would have triggered the offset obligations. However, the DuJay 1 well was

“offset” by the BSM 1 well. Graham testified that, by fraudulently obtaining

Hooks’ consent to pool into the BSM 1 unit, Samson likewise prevented him from

seeking proper protection of his rights under the terms of the Lease with regard to

the DuJay 1 well. Thus, the evidence indicates that a separate misrepresentation as

to the DuJay 1 well was not required because Samson’s fraud as to the BSM 1 well

necessarily implicated Hooks’ rights as to the DuJay 1 well.

      Samson argues that Hooks did not establish cause-in-fact and foreseeability

as to damages for the DuJay 1 well as required to recover consequential damages.

It argues that it drilled the DuJay 1 well after Hooks agreed to pool his lease into

the BSM 1 unit, and, thus, Hooks would have to prove that “Samson would have


                                         40
drilled the DuJay 1 well (1) even if [Hooks] had not agreed to pool; (2) within

1320 feet of [Hooks’ tract]; and (3) [had] not released Hooks’ tract to address

offset issues.” We disagree that Hooks must prove that Samson would have drilled

the DuJay 1 well absent the fraudulently induced pooling agreement. Fraud vitiates

whatever it touches. See Hooks, 457 S.W.3d at 57 (quoting Borderlon, 661 S.W.2d

at 909). We have already upheld the jury’s determination that Samson obtained

Hooks’ consent to pool through fraud, and Hooks need not prove what Samson’s

conduct might have been if it had not committed fraud. And the evidence did

establish that Samson drilled the DuJay 1 well within 1,320 feet of Hooks’

Jefferson County Lease and that Samson did not release Hooks’ tract.

      Thus, the evidence is legally and factually sufficient to support the award of

fraud damages based on the amount of compensatory royalties—totaling

$6,665,215.37 less a credit for the $510,328.01 in royalties Samson paid pursuant

to the fraudulently obtained pooling agreement—that would have been due to

Hooks on the BSM 1 and DuJay 1 wells. These amounts were likewise foreseeable

and directly traceable to and resulted from Samson’s misconduct. See Arthur

Andersen, 945 S.W.2d at 816–17; see Formosa Plastics, 960 S.W.2d at 49 n.1.

            b. Contractual late charges as fraud damages

      Samson also argues that two-thirds of the fraud damages—the amount

represented by the late charges due on unpaid royalties under the terms of Hooks’


                                        41
Jefferson County Lease—“are not actual damages at all,” “are not proper out-of-

pocket damages,” and constitute an improper basis for calculating Hooks’ fraud

damages. Samson asserts that the “‘late charge’ damages are another way in which

[Hooks is] attempting to convert [his] barred contract case into fraud damages.”

      We have already overruled Samson’s argument that Hooks was required to

prove out-of-pocket damages to recover for Samson’s fraud. Consequential

damages are a type of actual damages that are available in fraud cases. See

Sonnichsen, 221 S.W.3d at 636 (actual damages include both direct and

consequential damages; in fraud cases, out-of-pocket and benefit-of-the-bargain

are measures of direct damages while consequential damages result naturally but

not necessarily from wrongful act). We have also rejected Samson’s argument that

the lost-income damages found by the jury, reflecting the compensatory royalties

and associated late charges, are barred solely because they could also serve as a

measure of damages for breach of contract. The fact that Hooks’ loss was an

economic loss related to the subject matter of his contract with Samson does not

prevent his recovery of tort damages. See Formosa Plastics, 960 S.W.2d at 47

(holding that “tort damages are not precluded simply because a fraudulent

representation causes only an economic loss”).

      We must then consider whether the amount of fraud damages attributable to

the late charges on the unpaid compensatory royalties that Hooks should have


                                        42
received were, as the jury was asked to determine, “[l]ost income to the Hooks that

was the natural, probable, and foreseeable consequence of Samson’s fraud.”

      Graham testified that, as a result of Samson’s fraud, it failed to pay all of the

royalties due to Hooks. He testified that this failure likewise deprived Hooks of

$12,995,832.05 in late charges that Samson would have incurred on the unpaid

compensatory royalties under the terms of the lease. The terms of the Lease itself,

which was likewise in evidence at trial, provided for the payment of the late

charges, and Graham testified that he calculated the amount due based on the terms

of the Lease. Samson could have foreseen that its fraud prevented Hooks from

seeking the compensatory royalties to which he was entitled and that its failure to

pay those amounts would invoke its obligation—duly agreed to in the Lease—to

pay late charges. Samson does not provide any argument or evidence contradicting

this testimony of Graham or otherwise argue that these late charges were not a

natural, probable, or foreseeable consequence of its wrongful act.

      Samson also argues, in part, that “[w]ith a fraud claim, the aggrieved party

can seek prejudgment interest, not ‘late charges.’” However, Hooks did not seek

prejudgment interest and the final judgment did not award any prejudgment

interest. Rather, the trial court entered judgment based on the jury’s determination

that unpaid compensatory royalties and late charges were the actual, consequential




                                          43
damages that flowed from Samson’s fraud. Thus, we need not address the question

of prejudgment interest.

      The jury’s conclusion that the late charges, like the compensatory royalties,

were foreseeable and directly traceable to and resulted from Samson’s misconduct

is supported by legally and factually sufficient evidence. See Arthur Andersen, 945

S.W.2d at 816–17; see Formosa Plastics, 960 S.W.2d at 49 n.1.

            c. Formation production damages & remittitur

      Samson argues that we must reverse the award of fraud damages in part

based on the fact that the fraud damages originally awarded by the jury included

formation production damages. The supreme court affirmed our reversal of that

portion of the damages and rendered judgment that Hooks was not entitled to

formation production damages. See Hooks, 457 S.W.3d at 65.

      The $20,081,638.07 awarded by the jury as fraud damages was based in part

on Hooks’ evidence that he was entitled to unpaid royalty on “formation

production” from the BSM 1 well totaling $504,368.64 and unpaid royalty on

formation production from the DuJay 1 well totaling $426,550.01. However, this

portion of Hooks’ evidence on fraud damages may no longer be considered to

support the jury’s award as a matter of law. See id. at 64–65 (holding that Hooks

was not entitled to royalty payments for formation production).




                                        44
      Hooks contends that this Court could suggest a remittitur that would reduce

the amount of fraud damages by $504,368.64 and $426,550.01, as the amounts

reflecting the damages based on formation production, and by $1,689,556.85 for

the late charges associated with those royalties. See TEX. R. APP. P. 46.3 (providing

that appellate court may suggest remittitur). If part of a damage verdict lacks

sufficient evidentiary support, the proper course is to suggest a remittitur of that

part of the verdict, giving the party prevailing in the trial court the option of

accepting the remittitur or having the case remanded for a new trial. See Akin,

Gump, Strauss, Hauer & Feld, L.L.P. v. Nat’l Dev. & Research Corp., 299 S.W.3d

106, 124 (Tex. 2009) (“[W]hen there is some evidence of damages, but not enough

to support the full amount, it is inappropriate to render judgment.”); Samuels v.

Nasir, 445 S.W.3d 886, 894 (Tex. App.––El Paso 2014, no pet.) (Rule 46.3 permits

Court to suggest remittitur when “appellant complains there is insufficient

evidence to support an award and the court of appeals agrees, but concludes there

is sufficient evidence to support a lesser award”).

      As set out above, the record contains some evidence that fraud damages

existed, but it did not support the full amount awarded by the trial court. See ERI

Consulting Eng’rs, Inc. v. Swinnea, 318 S.W.3d 867, 877–78, 880 (Tex. 2010)

(holding that evidence was legally insufficient to support amount of lost profit

damages awarded by trial court, but that there was “legally sufficient evidence to


                                          45
prove a lesser, ascertainable amount of lost profits with reasonable certainty,” and

remanding case to court of appeals to consider suggestion of remittitur); Aquaplex,

Inc., 297 S.W.3d at 777 (holding, in fraud case, that some evidence supported

award of fraud damages, but not at level awarded by trial court, and remanding to

court of appeals to determine whether to remand for new trial on damages or

suggest remittitur). However, the evidence does allow us to determine a lesser

award, namely, one that does not include the formation production damages

described in Graham’s testimony. We conclude that the part of the jury’s verdict

on fraud damages that was based on formation production damages now lacks

sufficient support, and we suggest a remittitur of $2,620,475.50 representing the

formation production damages and their associated late charges that are no longer

justified in this case.

       Samson also argues that the post-judgment interest rate should be 5%. The

trial court granted Hooks post-judgment interest on all of the damages awarded in

the final judgment at a rate of 18%. In its original briefing, Samson challenged the

trial court’s post-judgment interest rate. This Court agreed and determined that a

5% interest rate applied to Hooks’ recovery for ad valorem taxes—the only award

that we left in place. See Samson Lone Star, Ltd. P’ship, 389 S.W.3d at 439. The

supreme court held, however, “[T]o the extent Hooks recovers for past due

royalties, he is entitled to an 18% interest rate. For other recoveries, the statutory


                                         46
rate of 5% applies because Hooks has not directed us to any portion of the leases

providing otherwise.” Hooks, 457 S.W.3d at 69–70. Based on this language, we

conclude that Samson is correct that the 5% post-judgment interest rate applies to

Hooks’ award of damages for fraud. If Hooks agrees to the remittitur that we

suggest below, we will modify the judgment to reflect the remittitur and the proper

interest rate. If Hooks does not agree to the remittitur, we will remand the case for

a new trial on fraud and thus will not need to reform the judgment’s post-judgment

interest rate. See TEX. R. APP. P. 44.1(b) (“The court may not order a separate trial

solely on unliquidated damages if liability is contested.”).

      Thus, we overrule Samson’s issues complaining of the jury’s fraud findings.

Regarding its complaints on damages, if Hooks agrees to the remittitur, we will

reform and affirm the judgment accordingly; however, if Hooks does not accept

the remittitur, we will reverse the judgment and remand for a new trial. See TEX. R.

APP. P. 46.3; Akin, Gump, Strauss, Hauer & Feld, L.L.P., 299 S.W.3d at 124.

                           Most Favored Nations Clause

      Hooks asserted, in a motion for summary judgment, that Samson breached

the “most favored nations” clause contained in his Leases, which provided that,

under certain circumstances, the royalties payable to Hooks must be elevated to

match the highest royalty payable to Samson’s other lessors. The trial court granted

summary judgment in Hooks’ favor, holding that this clause was triggered by


                                          47
royalty Samson paid under a pooling agreement to the State of Texas that was

higher than the royalty due to Hooks.

      We originally determined that Hooks was not entitled to damages for his

claim that Samson breached the most-favored-nations clause. See Samson Lone

Star, Ltd. P’ship, 389 S.W.3d at 437. The supreme court reversed, holding that

Hooks was entitled to an increased royalty rate of 28.28896%. See Hooks, 457

S.W.3d at 63.

      Samson argues that we must reverse and remand on this issue because “the

favored nations damages wrongly include formation production damages.”

However, the damages awarded in the trial court’s judgment were based on a

stipulation that set out most-favored-nations damages with and without amounts

for formation production. Specifically, Samson stipulated to $431,450.71 in

damages for breach of the most-favored-nations clause not including royalty for

formation production. Accordingly, we may modify the judgment to reflect the

amount of damages without formation production royalties based on the parties’

stipulation.

      Regarding the post-judgment interest rate,7 the supreme court held that

Hooks is entitled to an 18% interest rate “to the extent [he] recovers for past due


7
      Samson actually argues that the “prejudgment” interest rate was improper.
      However, the trial court’s judgment did not award prejudgment interest, and the
      supreme court’s opinion on this issue addressed the post-judgment interest rate.
                                         48
royalties,” such as here, where the award constitutes higher royalties that Samson

owed Hooks but never paid. See id. at 69–70. Thus, Samson’s argument that

interest needs to be recalculated is unavailing. The 18% post-judgment interest rate

applies to the most-favored-nations damages.

      We overrule Samson’s issues regarding the most-favored-nation damages.

                         II. HOOKS’ APPEAL ON REMAND

                                   Background

A.    Hooks’ Breach of Lease Claims for Hardin County Leases

      Hooks’ cross-appeal concerns his claim that Samson breached its offset

obligations with regard to Hooks’ two Hardin County Leases. The Hardin County

Leases, like the Jefferson County Lease, contained an offset obligation provision.

That provision specifically stated that if a gas well were completed within 1,320

feet from the leased premises, then, within ninety days from the date of the sale of

first production from that well, Samson must take one of three actions:

(1) commence due diligence operations for drilling an offset well to protect against

drainage; (2) pay 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.


      See Hooks, 457 S.W.3d at 69–70. Thus, we construe this argument as a complaint
      regarding the post-judgment interest rate.
                                         49
      Both Hardin County Leases also provided for pooling in terms that were

essentially the same with respect to the manner and methods of pooling. The leases

called 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.” The pooling provision in each Lease also

stated that “[o]perations for drilling on or production of gas from any part of the

pooled unit . . . , 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” and that

“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 parties stipulated at trial that Hooks had owned

his interests in the units at issue since the date of first production in each unit.

      In February 2001, Samson completed the Black Stone Minerals A-1 well

(“BSM A-1 well”) in Hardin County. On March 21, 2001, Samson filed a Unit

Designation for a 704-acre unit called the Black Stone Minerals “A” No. 1 Gas

Unit (“BSM A-1 unit”), which unitized the lease where the BSM A-1 well was

located with Hooks’ two Hardin County Leases and other tracts, including leases

owned by the State. The designation reflected that it was effective as of first


                                            50
production and included a list of the leases pooled, including Hooks’ Hardin

County Leases. The designation for the BSM A-1 unit included gas production at

all depths between 6,000 and 13,000 feet (including what Hooks refers to as the

deeper “Doyle formation” and what he refers to as the more shallow “EY-5

formation”), although the BSM A-1 well produced gas only from the shallow EY-5

formation.

      In June 2001, the BSM A-1 well began producing. In December 2001,

Samson finished the DuJay 1 well, which produced from some of the same land

designated to the BSM A-1 unit but at a lower horizon than the BSM A-1 well. The

DuJay 1 well began producing in January 2002.

      In February 2002, Samson amended the BSM A-1 unit designation. It

executed and recorded a designation for a new unit, the Joyce DuJay No. 1 Gas

Unit (“DuJay 1 unit”) that cited an effective date as of first production of the

DuJay 1 well, i.e., January 2002. The DuJay 1 unit designated a 571-acre unit with

a different name, different leases, different depths, and different boundaries from

the BSM A-1 unit.

      Subsequently, Samson drilled another DuJay well (“DuJay A-1 well”) and

created a separate pooled unit for that well. The DuJay A-1 unit differed from the

DuJay 1 unit by depth limitation and acreage. The DuJay A-1 well began

producing on September 25, 2002, but Samson did not file the DuJay A-1 unit


                                        51
designation until July 2003. Hooks’ Hardin County Leases were likewise pooled

into the designated DuJay A-1 unit.

      However, the BSM 1 well and the BSM A-1 well both continued producing

in close proximity to the DuJay 1 and DuJay A-1 units—in fact, within 1,320 feet

of the borders of those units.

B.    Procedural History

      Before trial, Hooks and Samson filed cross-motions for summary judgment

on the issue of whether Samson breached the offset obligations in the Hardin

County Leases. Hooks argued that the plain language of the Leases and the

undisputed facts established as a matter of law that Samson was liable for the BSM

1 well’s encroachment on the DuJay 1 unit and for the BSM A-1 well’s

encroachment on the DuJay A-1 unit, triggering offset obligations under the terms

of the Leases and requiring payment of compensatory royalties.

      The trial court granted Samson’s motion and denied Hooks’ motion on this

issue without stating its reasons.

      Hooks filed a cross-appeal, claiming that the trial court erred in granting

Samson’s motion for summary judgment and denying his own. Hooks included in

this issue sub-issues regarding the correct interpretation of Samson’s offset

obligations and other provisions in the Jefferson County Lease and Hardin County

Leases and the statute of limitations. Samson contended that Hooks waived his


                                       52
appeal of the summary judgments, and it argued that the trial court correctly

interpreted the Hardin County Leases with respect to the issues raised by Hooks on

cross-appeal and correctly rendered summary judgment. We originally affirmed

the trial court’s summary judgment on this issue, holding that Hooks’ claims were

barred by the statute of limitations. Samson Lone Star, Ltd. P’ship, 389 S.W.3d at

440. The Texas Supreme Court determined that Hooks had preserved this issue for

consideration on appeal, reversed our limitations holding, and remanded to this

Court for consideration of the merits of Hooks’ claim for breach of the offset

provisions and the proper construction of the entire-acreage clause. Hooks, 457

S.W.3d at 67, 69. It held that, assuming Samson breached, Hooks could be

“entitled to damages for royalties owed within four years of filing suit.” Id. at 68–

69.

                                 Breach of Lease

      Hooks argues that he conclusively established that Samson is liable for

compensatory royalties for production from the BSM 1 and BSM A-1 wells.

A.    Standard of Review

      A party moving for Rule 166a(c) summary judgment must conclusively

prove all of the elements of its cause of action as a matter of law. TEX. R. CIV. P.

166a(c); Holy Cross Church of God in Christ v. Wolf, 44 S.W.3d 562, 566 (Tex.

2001); Rhone-Poulenc, Inc. v. Steel, 997 S.W.2d 217, 222–23 (Tex. 1999). A


                                         53
defendant moving for summary judgment on a cause of action asserted against it

must negate as a matter of law at least one element of the plaintiff’s theory of

recovery or plead and prove each element of an affirmative defense. Nelson v.

Chaney, 193 S.W.3d 161, 165 (Tex. App.—Houston [1st Dist.] 2006, no pet.).

      “When both sides move for summary judgment and the trial court grants one

motion and denies the other, the reviewing court should review both sides’

summary judgment evidence and determine all questions presented.” FM Props.

Operating Co. v. City of Austin, 22 S.W.3d 868, 872 (Tex. 2000); accord

Gillebaard v. Bayview Acres Ass’n, 263 S.W.3d 342, 348 (Tex. App.—Houston

[1st Dist.] 2007, pet. denied). The reviewing court should render the judgment that

the trial court should have rendered. See Tex. Workers’ Comp. Comm’n v. Patient

Advocates of Tex., 136 S.W.3d 643, 648 (Tex. 2004); Comm’rs Court of Titus

Cnty. v. Agan, 940 S.W.2d 77, 81 (Tex. 1997); see also Gillebaard, 263 S.W.3d at

347–48. The propriety of summary judgment is a question of law. We therefore

review the trial court’s ruling to grant one party’s motion and deny the other using

the de novo standard. Provident Life & Accident Ins. Co. v. Knott, 128 S.W.3d 211,

215 (Tex. 2003).

      “In construing contracts, we must ascertain and give effect to the parties’

intentions as expressed in the document.” Hooks, 457 S.W.3d at 63 (citing Lopez v.

Muñoz, Hockema & Reed, L.L.P., 22 S.W.3d 857, 861 (Tex. 2000)). We attempt to


                                        54
harmonize all contractual provisions by “analyzing the provisions with reference to

the whole agreement.” Id. (citing Frost Nat’l Bank v. L & F Distribs., Ltd., 165

S.W.3d 310, 312 (Tex. 2005) (per curiam)). We “construe contracts from a

utilitarian standpoint bearing in mind the particular business activity sought to be

served,” and, when possible and proper, we avoid a “construction which is

unreasonable, inequitable, and oppressive.” Id. (citing Reilly v. Rangers Mgmt.,

Inc., 727 S.W.2d 527, 530 (Tex. 1987)). If, through the use of relevant rules of

construction, the contract can be given a definite meaning, we construe it as a

matter of law. Id. at 63–64.

B.    Analysis

      In his motion for summary judgment and on appeal, Hooks argues that a

portion of the pooling provision, which he refers to as the “entire acreage clause,”

applies here to mean that the Hardin County Leases “expressly and plainly include

pooled acreage as part of the acreage of the leases.” Hooks further argues that,

because the pooled acreage is part of the lease, any producing gas well completed

within the 1,320-foot buffer zone of the unit triggered the Leases’ offset

obligations. Hooks thus argues that both the BSM 1 and the BSM A-1 wells

produced gas from within 1,320 feet of the units into which its Hardin County

Leases had been pooled and that Samson did not release Hooks’ acreage, drill an

offset well to protect against drainage, or pay compensatory royalties as required


                                        55
by the offset obligation provisions in the Hardin County Leases, thus breaching

those Leases.

      Samson urges a narrower interpretation of the entire acreage clause and

asserts that the offset obligations are not triggered by wells within 1,320 feet of a

unit boundary but only by wells within 1,320 feet of an unpooled lease boundary.8

It relies on language in the offset obligation clauses that recognize a distinction

between the “leased premises” and “acreage pooled therewith.”

      Our analysis of this issue requires that we construe the meaning and legal

effect of the pooling provision in the Hardin County Leases, which states, in

relevant part:

      Lessee, 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. . . .
             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,

8
      Samson also argues that no offset obligations arose even if we apply Hooks’ lease
      interpretation and that Hooks did not conclusively establish that it breached any
      offset obligations that arose. Samson likewise contends that it met the offset
      obligations by drilling offset wells. However, under our construction of the
      Leases, the offset obligation in the Hardin County Leases was not triggered, and
      we need not address this contention.
                                         56
      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. . . . 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. . . .

This pooling provision is substantially similar to pooling provisions that have been

used in gas leases in this State since at least the 1950s. See, e.g., Mengden v.

Peninsula Prod. Co., 544 S.W.2d 643, 644 (Tex. 1976); Skelly Oil Co. v. Harris,

352 S.W.2d 950, 954 (Tex. 1962); Tiller v. Fields, 301 S.W.2d 185, 187 (Tex. Civ.

App.—Texarkana 1957, no writ).

      The primary legal consequence of such a pooling provision is settled in

Texas law as being “that production and operations anywhere on the pooled unit

are treated as if they have taken place on each tract within the unit.” Se. Pipe Line

Co. v. Tichacek, 997 S.W.2d 166, 170 (Tex. 1999) (citing Southland Royalty Co. v.

Humble Oil & Ref. Co., 249 S.W.2d 914, 916 (Tex. 1952)); Chesapeake Expl.,


                                         57
L.L.C. v. Energen Res. Corp., 445 S.W.3d 878, 884 (Tex. App.—El Paso 2014, no

pet.). Other consequences of pooling under a provision such as the one at issue

here have likewise been “fully discussed” by the Texas Supreme Court. See

Mengden, 544 S.W.2d at 647 (construing pooling provision that is substantively

identical to provision at issue here and stating that “the other normal consequences

of pooling” were “fully discussed by this Court” in Southland Royalty Co.). In

Southland Royalty Co., the supreme court stated that the consequences of pooling

are that:

       the life of the lease is extended as to all included tracts beyond the
       primary term and for as long as oil, gas or other minerals are produced
       from any one of the tracts included in the lease; the commencement of
       a well on any one of the tracts operates to excuse the payment of delay
       rentals on all included tracts for the period stated in the lease;
       production from a well on any one of the tracts relieves the obligation
       to pay delay rentals, during production, on all included tracts; the
       lessee is relieved of the usual obligation of an implied covenant for
       reasonable development of each tract separately; wells may be located
       without reference to property lines; [and] the lessee is relieved of the
       obligation to drill offset wells on other included tracts to prevent
       drainage by a well on one or more of such tracts.

249 S.W.2d at 916.

       Hooks urges that “[t]he ‘for all purposes’ language in the ‘entire acreage’

clause is all-encompassing and subject to only one limitation not at issue here” and

that the “broad language means that, once the leased acreage is pooled, all the

acreage in the pooled unit is treated as if it were part of the lease.” Specifically,

Hooks urges this Court to conclude that “once the lease is pooled, the 1,320 foot

                                         58
protected zone [set out in the offset obligation provision of the Leases] is no longer

based on only the originally leased tract” and the “protected zone is measured from

the boundary of the unit into which the leased tract is pooled.”

      Neither the language of Hooks’ Hardin County Leases nor the precedent of

Texas courts construing the effect of a pooling provision supports such an

interpretation. The language in the Hardin County Leases’ pooling provision—

including the sentence that Hooks refers to as the “entire acreage” clause—is

standard language. This language has been construed by Texas courts as serving to

effectuate an oil and gas lessee’s ability to pool leases for purposes of preventing

waste in the development of mineral leases by providing that “production and

operations anywhere on the pooled unit are treated as if they have taken place on

each tract within the unit.” See Key Operating & Equip., Inc. v. Hegar, 435 S.W.3d

794, 798 (Tex. 2014) (quoting Tichacek, 997 S.W.2d at 170); see also Mengden,

544 S.W.2d at 647 (stating that language in pooling paragraph in leases

substantially identical to Hooks’ Hardin County Leases’ provision details “the

other normal consequences of pooling” and “were fully discussed by this Court in

[Southland Royalty Co.]”); Southland Royalty Co., 249 S.W.2d at 916 (setting out

normal consequences of pooling).

      No court has construed the decision to pool under this type of pooling

provision as extending terms specifically agreed to for the protection of an


                                         59
individual lessor, like Hooks, to an entire pooled unit, and we decline to do so. We

observe that the offset obligation provision that Hooks argues Samson breached

provides:

      Lessee covenants and agrees to operate the leased premises as a
      reasonable and prudent operator would under the same or similar
      circumstances and to protect each of the leased premises from
      drainage by reason of any well drilled on adjacent or nearby lands.
      The above covenant notwithstanding, in 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 . . ., Lessee
      covenants to, within ninety days from the date production is first sold,
      removed or otherwise marketed . . ., either to (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 compensatory
      royalties . . ., or (3) . . . release by recordable instrument the offset
      acreage. . . . Notwithstanding anything herein to the contrary, Lessee
      shall have no obligations under this Article . . . 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.

(Emphasis added).

      The language of the offset obligation expressly states that its purpose is to

protect Hooks’ Hardin County Leases from drainage. Nothing in the Leases’

pooling provision evinces a specific agreement to broaden the protection provided




                                         60
by the offset obligation to include other leases not owned by Hooks. 9 See Hegar,

435 S.W.3d at 798 (identifying pooling provision substantially identical to Hooks’

and stating that primary legal consequence of pooling is that “production and

operations anywhere on the pooled unit are treated as if they have taken place on

each tract within the unit”) (quoting Tichacek, 997 S.W.2d at 170); Southland

Royalty Co., 249 S.W.2d at 916 (outlining legal consequences of pooling “in the

absence of express agreement to the contrary” as essentially providing that

production of oil or gas from wells located on any tract in pooled unit as

production from each and all other tracts included in unit). Rather, the offset

obligation provision specifically references the “leased premises”—referring to

Hooks’ tract of land—and makes a distinction between the leased premises and

larger pooled units in which those premises might be included.

      Reading the relevant provisions with reference to the whole agreement and

construing the lease “from a utilitarian standpoint bearing in mind the particular

business activity sought to be served,” as we must, we determine that the “entire

acreage clause” included in the pooling provision was intended to effectuate and

set out the details of Samson’s pooling authority, not to extend the applicability of


9
      We observe that Samson would still have an implied duty to protect the unit from
      drainage, see Southeast Pipe Line Co. v. Tichacek, 997 S.W.2d 166, 170 (Tex.
      1999), but Hooks is not asserting a claim for actual draining of his Hardin County
      Leases. Rather, he is arguing that Samson breached the terms of his Hardin
      County Leases.
                                          61
the offset obligations. See Hooks, 457 S.W.3d at 63 (providing rules of contract

construction); Mengden, 544 S.W.2d at 647 (stating that language in pooling

paragraph in leases, including language that Hooks relies on here, details “the other

normal consequences of pooling”).

      Hooks argues that construing the pooling provision as providing that

production and operations anywhere on the pooled unit are treated as if they have

taken place on each tract within the unit “gives meaning only the first part of the

provision in which the ‘entire acreage’ clause appears” and renders useless the

portion of the pooling provision that states “and the entire unit acreage constituting

[the unit] shall be treated for all purposes . . . as if the same were included in this

Lease.” We disagree.

      In Mengden, the Texas Supreme Court construed an essentially identical

pooling provision that also included a statement that:

      [o]perations for drilling on or production of oil or gas from any part of
      the pooled unit which includes all or a portion of the land covered by
      this lease . . . shall be considered as operations for drilling on or
      production of oil or gas from land covered by this lease [w]hether or
      not the well or wells be located on the premises covered by this lease,
      and the entire acreage constituting such unit or units . . . shall be
      treated [f]or all purposes, except the payment of royalties on
      production from the pooled unit, [a]s if the same were included in this
      lease.

544 S.W.2d at 644. The supreme court stated that the pooling provision gave

Mengden, the operator’s assignee who formed the gas units, the authority to form


                                          62
the relevant gas units, thereby perpetuating the portions of the “B” lease included

in the relevant units even though the wells were located on the “A” lease portion of

the unit. Id. at 647. It further stated that the language in the pooling provision

“detailed” the “other normal consequences” of pooling. Id. We conclude, like the

court in Mengden, that, far from being rendered useless, the sentence relied upon

by Hooks is part of the pooling provision and is intended to detail the normal

consequences of pooling. Hooks has provided no argument or citation to authority

for why this Court should be the first to isolate that particular phrase from the

standard pooling language and give it the novel reading he suggests.

      Hooks also argues that Skelly Oil Co. v. Harris and Tichacek, which we cite

in our analysis construing the pooling provision, support his construction. Again,

we disagree. In Skelly Oil, the lessors sued for termination of an oil and gas lease,

and the supreme court held that the lease was kept in force by production of a well

on land with which part of the leased premises was pooled. 352 S.W.2d at 950–51.

The lessees argued that the lease had terminated because “the well was not drilled

on the land described in the lease but on acreage pooled therewith,” and they

asserted that “the pooling clause declares that production from pooled acreage shall

be treated as if production is had from the lease but does not state in so many

words that drilling operations on pooled acreage shall have the same effect as

operations conducted on land described in the lease.” Id. at 953. The supreme court


                                         63
discussed a substantively similar pooling provision to the one at issue here and

stated:

      The second sentence of Paragraph 4 states plainly and unequivocally
      that except with respect to the payment of royalties on production, the
      entire acreage pooled into a unit shall be treated for all purposes as if
      it were included in the lease. Having excepted the matter of royalty
      payments on production from this sweeping declaration, the parties
      then dealt specifically with the legal consequences of production from
      a pooled unit and the royalties which the lessor would be entitled to
      receive therefrom. It seems clear to us that these provisions were not
      intended to limit the scope and effect of the second sentence in the
      paragraph as contended by respondents. From a consideration of the
      entire lease, the terms of the 60-day clause, and the other provisions of
      Paragraph 6, it is our opinion that drilling in progress at the end of the
      primary term on pooled acreage has the same legal effect as similar
      operations conducted on land described in the lease.

Id. at 954.

      Thus, although, as Hooks argues, the supreme court “rejected an argument

that would restrict the scope of the entire acreage clause’s ‘all purpose’ language”

and referred to that language as “a sweeping declaration” that excepts only the

payment of royalties, the effect of the Skelly Oil court’s holding was consistent

with the legal consequences of pooling recognized in cases dating back at least to

Southland Royalty Co. That case held that the usual consequences of pooling were

to extend the life of the lease “as to all included tracts beyond the primary term and

for as long as oil, gas, or other minerals are produced from any one of the tracts

included in the lease” and to relieve the lessee “of the usual obligation of an

implied covenant for reasonable development of each tract separately” and “the

                                         64
obligation to drill off-set wells on other included tracts to prevent drainage by a

well on one or more of such tracts.” See Southland Royalty Co., 249 S.W.2d at

916. Nothing in Skelly Oil indicates an intention to depart from this traditional

application of the pooling provision as Hooks urges us to do here.

      Likewise, in Tichacek, the supreme court recognized again that the “primary

legal consequence of pooling” is that production and operations anywhere on the

pooled unit are treated as if they have taken place on each tract or individual lease

within the unit. 997 S.W.2d at 170 (citing Southland Royalty Co., 249 S.W.2d at

916). It applied this legal construction to conclude that when a lessee pools in good

faith, it is relieved of the obligation to reasonably develop each tract separately or

to drill off-set wells on other tracts included in the unit to prevent drainage. Id. The

Tichacek court held, then, that because the jury in that case affirmed the validity of

the pooling, the plaintiffs had to segregate the claims between pre-pooling drainage

from the leases and post-pooling drainage from the unit. Id. at 170–71. Tichacek

did not stand for the proposition that a lessor like Hooks may sue the lessee for

breach of lease based on an expanded reading of the lessee’s obligation to drill

offset wells to protect an individual lease from drainage; it stated only that the

lessee has a duty to protect the unit from drainage. Thus, Tichacek addressed a

claim arising from drainage—a claim that Hooks does not assert here.

Furthermore, in Tichacek and more recent cases, the supreme court has interpreted


                                          65
pooling clauses more narrowly than in Skelly Oil, and it relied on the language

used by the parties in construing the relevant provisions. See id. at 170; see also

Tittizer v. Union Gas Corp., 171 S.W.3d 857, 861 (Tex. 2005) (same).

      The court’s ultimate conclusion in Mengden is instructive here. The question

before the supreme court was whether the pooling of two leases extended a payout

provision and a partial reversion contained in a farmout agreement10 applicable to

only one of the pooled leases to the production from the entire unit. See Mengden,

544 S.W.2d at 644, 647–48. The court concluded that, because the leases were

properly pooled, “the total unit production and costs should be allocated to each

lease in proportion to the number of acres contributed therefrom to the respective

units” and it “found no provision in the farmout agreement or assignments to [the

defendant] which would prevent or alter the normal rights and effects of the

pooling provision of the leases.” Id. at 647. Specifically, the supreme court

reasoned that the farmout agreements applicable to the “A” and “B” leases

contained different method of calculating Mengden’s payout and the effective date

of Peninsula Production’s reversion interest in the leases and that the expenses on




10
      A farmout agreement is “a ‘very common form of agreement . . . whereby the
      owner of a lease not desirous of drilling at the time agrees to assign the lease, or
      some portion of it . . . to another operator who is desirous of drilling the tract.’”
      Mengden v. Peninsula Prod. Co., 544 S.W.2d 643, 645 n.1 (Tex. 1976) (quoting
      Williams & Meyers, OIL & GAS LAW, MANUAL OF TERMS 167 (1971)).
                                           66
lease “B” “have amounted to considerably more than” the amounts that were

recoverable on lease “A.” Id. at 648. The supreme court concluded:

      If the producing wells had been located on lease “B” portions of the
      units, it is not likely that Peninsula would contend that the payout
      provisions of farmout “B” should apply to the entire units. Neither
      should the payout provisions of farmout “A” apply to the entire units.
      We hold that payout provisions of both farmouts are applicable to the
      unit wells in proportion to the acreage that each contributed to the
      units.

Id.

      Thus, the supreme court determined that, even though the legal consequence

of pooling the “A” and “B” leases was that the acreage of the entire unit was

considered part of each lease separately, that did not mean that provisions

contained in the conveyance documents governing the individual tracts applied

universally to the entire unit. Here, that means that the legal consequence of

pooling was that “the entire acreage” constituting the pooled unit should be treated

as if it were included in Hooks’ tract. It was not a legal consequence of pooling

that all of the individual protections—including the offset obligation provisions

designed to protect Hooks’ tract from drainage—applied to the entire unit.

      Because, as a matter of law, we conclude that the drilling of wells within

1,320 feet of the pooling unit did not trigger the offset obligations in Hooks’

Hardin County Leases, we conclude that denial of Hooks’ motion for summary

judgment was proper. See TEX. R. CIV. P. 166a(c); Wolf, 44 S.W.3d at 566.


                                        67
      We overrule Hooks’ cross-issue on appeal.

                                    Conclusion

      We conclude that the evidence is insufficient to support the trial court’s

award of $20,081,638.07 for fraud damages, but the evidence is sufficient to

support an award of $17,461,162.57 for fraud damages. We suggest a remittitur of

$2,620,475.50. If Hooks files in this Court such remittitur within twenty days after

the issuance of our opinion, we will modify the trial court’s judgment to delete

$766,626.85 in “unpooling” damages; delete $2,620,475.50 remitted in fraud

damages representing the formation production damages and their associated late

charges; modify the amount of most-favored-nations damages to $431,450.71,

consistent with the parties’ stipulation; and modify the post-judgment interest rate

to reflect an 18% rate for past due royalties (i.e., the most-favored-nations

damages) and a 5% interest rate for other recoveries and affirm as modified. If the

remittitur is not timely filed, then we will let stand our current judgment reversing

the trial court’s judgment and remanding the cause for a new trial.




                                              Evelyn V. Keyes
                                              Justice

Panel consists of Justices Keyes, Massengale, and Lloyd.



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