In the

Court of Appeals

Second Appellate District of Texas

at Fort Worth ___________________________

No. 02-18-00424-CV

___________________________

On Appeal from the 96th District Court

Tarrant County, Texas

Trial Court No. 096-289847-17

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
2

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).
3

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).
4

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.
5

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).
6

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.

6

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

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.
7

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-atthe-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., 

7

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

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).
8

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 
9

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, 
10

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 
11

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
12

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 
13

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.
14

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 
15

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 
16

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 
17

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 
18

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 noevidence 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 
19

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