Court Opinion

ID: 5128205
Source: CourtListenerOpinion
Date Created: 2021-11-22 08:15:49.396068+00
Date Added: 2024-06-11T08:23:05.716630
License: Public Domain

In the
                     Court of Appeals
             Second Appellate District of Texas
                      at Fort Worth
                  ___________________________
                       No. 02-18-00424-CV
                  ___________________________

 SHIRLAINE WEST PROPERTIES LIMITED AND NATHAN K. GRIFFIN, ON
BEHALF OF THE ESTATE OF LORRAINE E. WEST AND ON BEHALF OF THE
             ESTATE OF SHIRLEY A. WEST, Appellants

                                 V.

JAMESTOWN RESOURCES, L.L.C. AND TOTAL E&P USA, INC., Appellees

                On Appeal from the 96th District Court
                       Tarrant County, Texas
                   Trial Court No. 096-289847-17
Before Birdwell and Wallach, JJ.; and Gonzalez, J.1 (Judge Gonzalez not participating)
                    Memorandum Opinion by Justice Wallach

       1
         The Honorable Ruben Gonzalez, Judge of the 432nd District Court of Tarrant County,
sitting by assignment of the Chief Justice of the Texas Supreme Court pursuant to Section 74.003(h)
of the Government Code. See Tex. Gov’t Code Ann. § 74.003(h).

                                                2
                           MEMORANDUM OPINION

      This is a breach of contract case involving the interpretation of a natural gas

lease royalty clause. Appellants (the Lessors) sued Appellees (the Lessees) for

underpayment of royalties, contending that the contract language unambiguously

provides for valuing the Lessors’ royalty by a percentage of the market value of the

gas at the point of sale (wellhead) adjusted by certain factors set forth in the lease

royalty clause, essentially rendering their royalty not subject to postproduction costs,

directly or indirectly.2 The Lessees contended that there was no underpayment of

royalties because the lease unambiguously provides that the royalty is a percentage of

the market value of the gas “at the point of sale,” and because the point of sale is at

the wellhead, the royalty is subject to deduction for postproduction costs, as reflected

by the price the Lessors received from their wellhead gas purchasers.

      Lessors moved for partial summary judgment. Lessees moved for traditional

and no-evidence summary judgment. The trial court denied the Lessors’ motion and

granted the Lessees’ motions. The trial court granted judgment that Lessors take

nothing. In this appeal, the Lessors succinctly draw the question that is determinative

      2
       Chesapeake Exploration L.L.C. and Chesapeake Operating, L.L.C. were two of
the Appellees (Lessees) when this appeal was initially filed. After filing for bankruptcy,
which suspended this appeal, they eventually settled with Lessors, and we granted
Lessors’ unopposed motion to dismiss the two Chesapeake entities from the appeal
and to reinstate the appeal against the two remaining Lessees, dismissed the two
Chesapeake entities, and reinstated the appeal. Shirlaine West Props., Ltd. v. Chesapeake
Expl., L.L.C., No. 02-18-00424-CV, 2021 WL 4783171, at *1 (Tex. App.—Fort
Worth Oct. 14, 2021, no pet. h.) (per curiam) (mem. op. and order).

                                            3
of the case, i.e., whether the Lessors’ royalty interest is burdened with postproduction

costs. Because we conclude that the lease royalty clause is unambiguous and fixes the

wellhead as the valuation point for the Lessors’ royalty, we hold that the Lessors’

royalty is burdened with postproduction costs. We affirm the trial court’s take-nothing

summary judgment.

I.     Factual Background

       Shirlaine West Properties Limited (West) leased approximately 98.93 net

mineral acres in the Barnett Shale to Chesapeake Exploration, L.L.C. (“CE”) 3 in early

2010. The royalty clause in this lease states, in pertinent part,

       3. As royalty, Lessee covenants and agrees: . . . (b)[1] to pay Lessor for
       gas including casinghead gas and other gaseous substances produced
       from said land and sold or used on or off the premises twenty-five percent
       (25%) of the market value at the point of sale, use or other disposition of all such gas.
       [2] The market value of all gas shall be determined at the specified location and by
       reference to the gross heating value (measured in British thermal units)
       and quality of the gas. [3] The market value used in the calculation of all royalty
       under this Lease shall never be less than the total proceeds received by Lessee in
       connection with the sale, use or other disposition of oil or gas produced or sold from the
       leased premises. [4] The royalty reserved to Lessor hereunder shall be free
       and clear of all costs and expenses whatsoever, except ad valorem and
       production taxes. [5] By way of explanation but not limitation, it is
       agreed between the Lessor and Lessee, that, notwithstanding any
       language herein to the contrary, all oil, gas or other proceeds accruing to

       3
        Chesapeake Operating, L.L.C. (CO), on behalf of CE, was the sole operator of
the two gas wells involved in this dispute (the Duke United 1H and Duke United 2H
wells). Subsequent to the original lease, CE assigned an undivided 25% interest in all
of its Barnett Shale leases, including this lease, to Total. CE also assigned an undivided
2.5% interest to Jamestown in the Duke United 1H well. In November 2016, CE
assigned its remaining interest to Total. Chesapeake, Jamestown, and Total may be
collectively referenced as Lessees. CE administered all royalties for the Lessees.

                                                   4
      the Lessor under this lease or by state law shall be without deduction for
      the cost of producing, gathering, storing, separating, treating,
      dehydrating, compressing, processing, transporting, and marketing the
      oil, gas and other products produced hereunder to transform the
      product into marketable form; however, any such costs which result in
      enhancing the value of the marketable oil, gas or other products to
      receive a better price may be deducted from Lessor’s share of
      production so long as they are based on Lessee’s actual cost of such
      enhancements. [6] However, in no event shall Lessor receive a price that
      is less than, or mare [sic] than, the price received by Lessee. [7] If Lessee
      realizes proceeds of production after deduction for any expenses of production,
      gathering, dehydration, separation, compression, transportation, treatment, processing,
      storage or marketing, then the proportionate part of such deductions shall be added to
      the total proceeds received by Lessee for purposes of this paragraph. [8] Lessor and
      Lessee hereby agree that the holding in Heritage Resources, Inc. v Nations
      Bank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms
      of this lease.4 [Emphasis and sentence numbers added.]

      Gas was not produced under the lease until 2012. No royalties were paid under

the lease until September 2015 because of a title dispute.

      CO sold the gas it produced from the leased premises for CE and Jamestown

to Chesapeake Energy Marketing, L.L.C. (CEM). Title to the gas sold to CEM

transferred at the custody meter at the wellhead. CEM and CO had a Base Contract

for Purchase and Sale of Natural Gas (Base Contract), which established the gas price

that CEM paid to CO on behalf of CE. The price was calculated as the weighted

average sale price (WASP) that unaffiliated downstream purchasers paid CEM in

arms-length transactions less the actual postproduction costs that CEM paid to third

      4
        Sentence 8’s disclaimer of the holding in Heritage Resources does not affect this
court’s decision. The court will look to the text of the agreement to ascertain the
royalty obligations. See Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 876 (Tex.
2016) (op. on reh’g).

                                                5
parties to move the gas from the wellhead to the downstream points of sale. The

reasonableness of the WASP calculations was not challenged. CEM charged CO a 3%

marketing fee. CO added that 3% fee back to the proceeds it received from CEM.5 It

is undisputed that when the Lessors signed the lease, they were aware that CO would

sell the gas to an affiliated company at the wellhead.

        CO did not engage in post-production activities such as compressing,

transporting, processing, or treating the gas it sold to CEM at the wellhead. The gas

produced from the lease required no special treatment of any kind to be sold and

transported off the lease. It was lean, unprocessed, and produced at low pressure, and

it was in a marketable form at the wellhead.

        The gas purchased at the wellhead by CEM went to its gathering pipeline

system, which transported the gas to intrastate or interstate pipelines. While CEM

sold some of the gas at the connection to the intra/inter-state pipelines to third

parties, CEM paid third party pipeline owners to transport most of the gas further

downstream on transmission pipelines for sale at a higher price to unaffiliated third

parties. 6

        5
          Lessors have not been harmed by the deduction and it is not an issue in this
appeal.

        On or about August 7, 2014, West distributed its interest in the Lease to
        6

Lorraine E. West and to Nathan K. Griffin, on behalf of the Estate of Shirley A.
West, in equal shares. Lorraine West died in 2016 and Griffin was appointed as her
estate’s personal representative.

                                            6
      Total took in kind its working interest share of the gas produced from the

lease. Total then sold its share of the gas at the wellhead to Total Gas & Power North

America, Inc. (Gas & Power). Title to the gas transferred from Total to Gas & Power

at the custody transfer meter at or near the wellhead. Total had a Base Contract for

Sale and Purchase of Natural Gas with Gas & Power to purchase its in-kind share of

the gas at the wellhead, which was the point of sale. Gas & Power then moved the gas

downstream to locations for commercial resale of the gas.

      Gas & Power calculated its WASP for the gas, calculating the market-value-at-

the-wellhead based on its WASP adjusted to account for Gas & Power’s actual costs

to move the gas from the wellhead to the downstream resale points. The actual costs

(postproduction costs) included gathering and transportation costs that enhanced the

value of the already marketable gas sold at the wellhead. 7

II.   Standard of Review

      This court applies a de novo standard of review to summary judgments.

Travelers Ins. Co. v. Joachim, 315 S.W.3d 860, 862 (Tex. 2010). If competing summary

judgment motions are filed, each party must bear its burden of establishing that it is

entitled to judgment as a matter of law. Tarr v. Timberwood Park Owners Ass’n, Inc.,

      CEM and Gas & Power calculate the WASP differently: CEM calculates the
      7

WASP based on the price that it receives from the downstream, third-party sales,
while Gas & Power calculates the WASP based on indices published at the
downstream resale points. This difference is not relevant, however, because Lessors
do not challenge either WASP calculation as reflected in their Owner Accounting
Reconciliation Statement (OAR).

                                            7
556 S.W.3d 274, 278 (Tex. 2018); City of Garland v. Dall. Morning News, 22 S.W.3d 351,

356 (Tex. 2000). “If the trial court grants one motion and denies the other, the

reviewing court should determine all questions presented and render the judgment

that the trial court should have rendered.” City of Garland, 22 S.W.3d at 356–

57 (cleaned up); BlueStone Nat. Res. II, LLC v. Randle, 601 S.W.3d 848, 854 (Tex.

App.—Fort Worth April 18, 2019), rev’d in part on other grounds, 620 S.W.3d 380 (Tex.

2021).

         When a motion for summary judgment presents both no-evidence and

traditional grounds, the court first reviews the propriety of the summary judgment

under the rule 166a(i) no-evidence standards. Lightning Oil Co. v. Anadarko E&P

Onshore, LLC, 520 S.W.3d 39, 45 (Tex. 2017); Ford Motor Co. v. Ridgway, 135 S.W.3d

598, 600 (Tex. 2004). If a non-movant failed to produce more than a scintilla of

evidence under the no-evidence standards, there is no need to analyze whether a

movant’s summary judgment proof satisfied the burden related to traditional summary

judgment motions. Blackard v. Fairview Farms Land Co., 346 S.W.3d 861, 868 (Tex.

App.—Dallas 2011, no pet.). We consider the evidence in the light most favorable to

the non-movant, indulging every reasonable inference from the evidence in that

party’s favor. Sudan v. Sudan, 199 S.W.3d 291, 292 (Tex. 2006); Blackard, 346 S.W.3d at

868.

         The movant in a traditional summary judgment bears the burden of proving

there is no genuine issue of material fact regarding at least one essential element of the

                                            8
cause of action being asserted and that it is entitled to judgment as a matter of law.

Tex. R. Civ. P. 166a(c); Nassar v. Liberty Mut. Fire Ins. Co., 508 S.W.3d 254, 257 (Tex.

2017). When reviewing a traditional motion for summary judgment, the court reviews

the evidence in the light most favorable to the non-movant, indulges every reasonable

inference in favor of the non-movant, and resolves any doubts against the motion.

Lightning Oil Co., 520 S.W.3d at 45; City of Keller v. Wilson, 168 S.W.3d 802, 824 (Tex.

2005).

III.     Rules of Contract Construction

         Contract language which can be given a certain or definite meaning is

unambiguous. In that situation, the court interprets the contractual language as a

matter of law. DeWitt Cnty. Elec. Coop., Inc. v. Parks, 1 S.W.3d 96, 100 (Tex. 1999);

Castillo Info. Tech. Servs., LLC v. Dyonyx, L.P., 554 S.W.3d 41, 45 (Tex. App.—Houston

[1st Dist.] 2017, no pet.). Contract language is not ambiguous simply because it is

unclear or because the parties “assert forceful and diametrically opposing

interpretations.” In re D. Wilson Constr. Co., 196 S.W.3d 774, 781 (Tex. 2006) (orig.

proceeding); DeWitt Cnty. Elec. Coop., 1 S.W.3d at 100. An ambiguity arises only after

the application of established rules of interpretation leaves the language susceptible to

more than one reasonable meaning. DeWitt Cnty. Elec. Coop., 1 S.W.3d at 100. An oil

and gas lease is a contract, and its terms are interpreted according to rules of contract

construction. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005); BlueStone,

                                           9
601 S.W.3d at 854–55. The rules of construction applicable to oil and gas lease

contracts were aptly summarized by this court in BlueStone:

      “In construing an unambiguous oil and gas lease, . . . we seek to enforce
      the intention of the parties as it is expressed in the lease.” [Tittizer,
      171 S.W.3d at 860]. “We give terms their plain, ordinary, and generally
      accepted meaning[s] unless the instrument shows that the parties used
      them in a technical or different sense.” Heritage Res., Inc. . . . , 939 S.W.2d
      [at] 121 . . . .

      “We examine the entire lease and attempt to harmonize all its parts, even
      if different parts appear contradictory or inconsistent.” Anadarko
      Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002) (citing Luckel
      v. White, 819 S.W.2d 459, 461 (Tex. 1991)). A court examines all of the
      lease’s provisions “because we presume that the parties to a lease intend
      every clause to have some effect.” Id. (citing Heritage Res., 939 S.W.2d at
      121). Finally, we “cannot change the contract merely because we or one
      of the parties comes to dislike its provisions or thinks that something
      else is needed in it.”

BlueStone, 601 S.W.3d at 855.

IV.   Analysis

      Like BlueStone, this case is yet another episode in the endless struggle in the oil

and gas context between lessors and lessees in the allocation of post-production costs

in the calculation of royalty payments. We addressed the basic structure of oil and gas

lease royalty terminology in BlueStone and encourage its review for the historical legal

background of the treatment of oil and gas lease royalty clauses.

      For now, we will focus on three main principles. First, a mineral lease is a

contract and is governed by the rules of contract law. Id. at 854–55. Second, oil and

gas lease law, though framed in contract terms, has developed unique legal

                                            10
interpretations of royalty clauses, which can make understanding these contracts

difficult for the unwary. See id. at 855–60. Third, even though these unique

applications may make words and phrases about royalties mean something different

than they would appear, or maybe mean nothing at all, the parties may agree to alter

those unique meanings by the terms of their contract. The ultimate answer in each

case depends on whether the words used clearly express the intent of the parties to

deviate from the traditional meanings. Burlington Res. Oil & Gas Co. v. Tex. Crude

Energy, LLC, 573 S.W.3d 198, 204 (Tex. 2019); Heritage Res., 939 S.W.2d at 121;

BlueStone, 601 S.W.3d at 867; see also Warren v. Chesapeake Expl., L.L.C, 759 F.3d 413,

415 (5th Cir. 2014).

      A royalty is generally defined as the landowner’s share of production. Although

not subject to the costs of production, a royalty is usually subject to post-production

costs such as taxes, treatment costs to render the gas marketable, and transportation

costs. However, the parties may alter this general rule by agreement. Burlington Res.,

573 S.W.3d at 203; Heritage Res., 939 S.W.2d at 121–22. Royalties that are calculated

based on market value at the wellhead generally burden the lessor’s royalty with a

proportionate share of postproduction costs. Burlington Res., 573 S.W.3d at 204;

Heritage Res., 939 S.W.2d at 122–23. In leases that value the lessor’s royalty based on

market value at the wellhead, provisions that purport to deduct or exempt

postproduction costs from the lessor’s royalty are considered mere surplusage. Heritage

Res., 939 S.W.2d at 123 (holding that, in market-value-at-the-well lease, royalty

                                          11
language reciting that lessor’s royalty interest would be free and clear of, or without

deductions for, postproduction costs was mere surplusage); see also Burlington Res.,

573 S.W.3d at 204 (overriding royalty interest assignments which required oil or gas to

be delivered “into the pipeline” fixed the valuation point at the wellhead, which

allowed the lessee to deduct postproduction costs from the overriding royalty despite

language that the royalty would be free of postproduction costs and a valuation clause

providing that value from a sale on or off the lease would be based on the “amount

realized” from the sale of such oil or gas in arms-length transactions).

      However, courts have upheld the right of lessors and lessees to contract for a

lessor’s royalty to be free of postproduction costs. Two examples are “proceeds”

leases and “amount realized” leases. A proceeds lease is found in Hyder, involving

separate oil and gas royalty clauses. 483 S.W.3d at 871. The lessor’s oil royalty,

according to the Texas Supreme Court, bore postproduction costs because it was paid

on the market value of the oil at the wellhead. Id. at 873. By contrast, the gas royalty

language provided for a royalty of “25% of the price actually received by Lessee” and

further provided that the “royalty [was] expressly free and clear of all production and

post-production costs and expenses” and listed examples of such expenses. Id. at 871–

72. The Court said that

      [t]he gas royalty in the lease does not bear postproduction costs because
      it is based on the price Chesapeake actually receives for the gas through
      its affiliate, Marketing, after postproduction costs have been paid. Often
      referred to as a “proceeds lease,” the price-received basis for payment in
      the lease is sufficient in itself to excuse the lessors from bearing

                                           12
      postproduction costs. And of course, like any other royalty, the gas
      royalty does not share in production costs. But the royalty provision
      expressly adds that the gas royalty is “free and clear of all production and
      post-production costs and expenses,” and then goes further by listing
      them. This addition has no effect on the meaning of the provision. It
      might be regarded as emphasizing the cost-free nature of the gas royalty,
      or as surplusage.

      ....

      The gas royalty does not bear postproduction costs, not because it is
      based on a volume other than full production, but because the amount is
      based on the price actually received by the lessee, not the market value at
      the well.

Id. at 873, 875 (footnotes omitted). From this we see that the operative language is the

“actual proceeds received” language, the “free and clear” language being either

surplusage or mere emphasis language.

      Likewise, “amount realized” clauses require the calculation of the royalty based

on the amount the lessee receives under its contract for the sale of the gas. Bowden v.

Phillips Petrol. Co., 247 S.W.3d 690, 699 (Tex. 2008). As noted by the Fifth Circuit in

Warren,

      The Warrens’ leases provide in the pre-printed royalty clause that they
      are entitled to 22.5% “of the amount realized by Lessee, computed at the
      mouth of the well.” As the Warrens recognize in their brief, the term
      “amount realized” “require[s] measurement of the royalty based on the
      amount the lessee in fact receives under its sales contract for the gas.”
      Had the lease provided only that the Warrens are to receive 22.5% of the
      amount realized by Lessee, there would be little question that the
      Warrens would be entitled to 22.5% of the sales contract price that the
      lessee received, with no deduction of post-production costs. But that is
      not what the lease provides.

                                          13
759 F.3d at 417. The court then went on to point out that the “computed at the

mouth of the well” language rendered the proceeds to be net of postproduction costs.

      We must now apply these principles to the West lease. Sentences 1 and 2 of the

royalty clause (the third numbered paragraph) set the direction for the ultimate

outcome of the dispute. They state that Lessee agrees

      [1] to pay Lessor for gas including casinghead gas and other gaseous
      substances produced from said land and sold or used on or off the
      premises twenty-five percent (25%) of the market value at the point of sale, use or
      other disposition of all such gas. [2] The market value of all gas shall be determined
      at the specified location and by reference to the gross heating value (measured in
      British thermal units) and quality of the gas. [Emphasis and sentence numbers
      added.]

      These sentences fix market value as the measure of value and set the location

of the value at the point of sale. It is uncontroverted that the point of sale of the gas

in question was at the wellhead. A lease need not use the words “at the wellhead” to

expressly fix the location. As the Texas Supreme Court noted in Burlington Resources,

      To sum up, the Valuation Clause [of the lease in question] specifies that
      the royalty payment shall be calculated based on the “amount realized”
      from the sale, but the agreements also provide that the royalty interest
      shall be delivered “into the pipelines, tanks, or other receptacles with
      which the wells may be connected.” In the context of these agreements,
      this latter term fixes the royalty’s valuation point at the physical spot
      where the interest must be delivered—at the wellhead or nearby.

573 S.W.3d at 211. Having established that the agreements provided for royalty

payments on the amount realized from the sale of the gas at the pipeline, the Court

held that “[t]his gives Burlington the right to subtract post-production costs from the

‘amount realized’ in downstream sales prices in order to calculate the product’s value

                                               14
as it flows ‘into the pipelines, tanks or other receptacles with which the wells may be

connected.’” Id.

       Having established that the West lease is a market-value-at-the-well lease, we

can evaluate the impact of the other provisions of the royalty clause. Sentences 4, 5,

and 6 are the types of provisions that in “market-value-at-the-well” royalty provisions

are considered surplusage, or restatements of existing law, as a matter of law. Heritage

Res., 939 S.W.2d at 122–23. As stated by Justice Owen in her concurring opinion in

Heritage Resources,

              There is little doubt that at least some of the parties to these
       agreements subjectively intended the phrase at issue to have meaning.
       However, the use of the words “deductions from the value of Lessor’s
       royalty” is circular in light of this and other courts’ interpretation of
       “market value at the well.” The concept of “deductions” of marketing
       costs from the value of the gas is meaningless when gas is valued at the
       well. Value at the well is already net of reasonable marketing costs. The
       value of gas “at the well” represents its value in the marketplace at any
       given point of sale, less the reasonable cost to get the gas to that point of
       sale, including compression, transportation, and processing costs.
       Evidence of market value is often comparable sales, as the Court
       indicates, or value can be proven by the so-called net-back approach,
       which determines the prevailing market price at a given point and backs
       out the necessary, reasonable costs between that point and the wellhead.
       But, regardless of how value is proven in a court of law, logic and
       economics tell us that there are no marketing costs to “deduct” from
       value at the wellhead.

939 S.W.2d at 130 (Owen, J. concurring).

       We turn next to sentences 3 and 7 of the third numbered paragraph of the

lease. Sentence 3 reads, “The market value used in the calculation of all royalty under

this Lease shall never be less than the total proceeds received by Lessee in connection

                                            15
with the sale, use or other disposition of oil or gas produced or sold from the leased

premises.”

       There is no dispute that Lessees have paid Lessors their royalties using not less

than the total proceeds received by Lessees. This, of course, leads to the central

dispute in the case, which revolves around Sentence 7. Sentence 7 reads, “If Lessee

realizes proceeds of production after deduction for any expenses of production,

gathering,    dehydration,   separation,   compression,    transportation,   treatment,

processing, storage or marketing, then the proportionate part of such deductions shall

be added to the total proceeds received by Lessee for purposes of this paragraph.”

       Lessors contend that by Lessees selling the gas to Gas & Power and CEM with

postproduction costs deducted from the purchase price, Lessees realize proceeds after

deduction for expenses identified in Sentence 7, and Lessors are therefore entitled to

have these expenses added back into the “total proceeds” to be used for calculating

royalties under Sentence 3. Such an interpretation would create an internal conflict

between the market-value-at-the-well provisions in Sentences 1 and 2 and the

combination of sentences 3 and 7 to form a “total proceeds” lease. This interpretation

would effectively convert a market-value-at-the-well lease into a “total proceeds”

lease, which is not consistent with precedent. As noted by the Texas Supreme Court

in Burlington Resources,

       We have never construed a contractual “amount realized” valuation
       method to trump a contractual “at the well” valuation point. To the
       contrary, prior decisions suggest that when the parties specify an “at the

                                           16
       well” valuation point, the royalty holder must share in post-production
       costs regardless of how the royalty is calculated. This is generally the case
       even when the agreement calls for payments based on the “amount
       realized” or “proceeds.” Allowing the holder of an “at the well” royalty
       to escape his responsibility for post-production costs would improperly
       convert the royalty interest from a royalty on raw products at the well to
       a royalty on refined, downstream products.

573 S.W.3d at 205 (internal citations omitted).

       In construing a lease, courts will “examine and consider the entire writing in an

effort to harmonize and give effect to all the provisions of the contract so that none

will be rendered meaningless.” Valence Operating Co. v. Dorsett, 164 S.W.3d 656,

662 (Tex. 2005); accord Hysaw v. Dawkins, 483 S.W.3d 1, 4 (Tex. 2016); Heritage Res.,

939 S.W.2d at 121; Westport Oil & Gas Co., L.P. v. Mecom, 514 S.W.3d 247, 251 (Tex.

App.—San Antonio 2016, no pet.). Remembering that Sentences 1 and 2 provide that

market value is at the point of sale, not necessarily at the well, other potential sales at

other points might appropriately fall within the ambit of Sentence 7. But we are not

presented with such facts and need not prognosticate about them. For this

circumstance, Sentence 7 is simply not applicable and cannot be used by Lessors to

avoid sharing postproduction costs in a sale at the well which they have agreed to

value at the well. See Burlington Res., 573 S.W.3d at 206.

       Lessors rely heavily on the Supreme Court’s opinion in Hyder. This reliance is

misplaced. The Hyder holding concerns an overriding royalty interpretation.

Overriding royalties, like royalties, are generally not subject to costs of production but

are generally subject to postproduction costs. 483 S.W.3d at 872. The Hyder lease

                                            17
provided for “‘a perpetual, cost-free (except only its portion of production taxes)

overriding royalty of five percent (5.0%) of gross production obtained from

directional wells drilled on the lease but bottomed on nearby land.’” Id. Although the

Court held that the overriding royalty created by this language was free of

postproduction costs, its rationale was never clearly explained. What is clear is that the

Hyder overriding royalty language did not value the royalty on the market value at the

well. Thus, Hyder does not control in this case.

V.    Conclusion

      Lessors’ only cause of action against Lessees is for breach of contract. Lessees

filed no-evidence motions for summary judgment based on no evidence of breach of

an agreement and no evidence of damages, both of which are elements of Lessors’

actions against Lessees. See City of Colony v. N. Tex. Mun. Water Dist., 272 S.W.3d 699,

739 (Tex. App.—Fort Worth 2008, pet. dism’d). The trial court granted the no-

evidence motions. Finding the lease agreement unambiguous, no evidence of breach

of the lease agreement, and no damages caused by any alleged breach, we affirm the

take-nothing summary judgment in favor of Lessees Jamestown Resources, L.L.C. and

Total E&P USA, Inc. Having affirmed the granting of the no-evidence motions, we

need not address the traditional motions for summary judgment. See Ridgway,

135 S.W.3d at 600; Solano v. Landamerica Com. Title of Fort Worth, Inc., No. 02-07-152-

CV, 2008 WL 5115294, at *4 (Tex. App.—Fort Worth Dec. 4, 2008, no pet.) (per

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curiam) (mem. op.). We affirm the trial court’s judgment for Jamestown Resources,

L.L.C. and Total E&P USA, Inc.

                                                 /s/ Mike Wallach
                                                 Mike Wallach
                                                 Justice

Delivered: November 18, 2021

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