Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc. v. Martha Rowan Hyder, Individually, and as Independent and Trustee Under the Will of Elton M. Hyder, Jr., and as Trustee Under the Elton M. Hyder Jr. Residuary Trust, and as Trustee of the Elton M. Hyder Jr. Marital Trust Brent Rowan Hy

IN THE SUPREME COURT OF TEXAS
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NO . 14-0302
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CHESAPEAKE EXPLORATION, L.L.C. AND
CHESAPEAKE OPERATING, INC., PETITIONERS,
v.

MARTHA ROWAN HYDER, INDIVIDUALLY, AND AS INDEPENDENT EXECUTRIX AND
TRUSTEE UNDER THE WILL OF ELTON M. HYDER, JR., DECEASED, AND AS
TRUSTEE UNDER THE ELTON M. HYDER JR. RESIDUARY TRUST, AND AS TRUSTEE
OF THE ELTON M. H YDER JR . M ARITAL TRUST ; BRENT ROWAN H YDER ,
INDIVIDUALLY AND AS TRUSTEE OF THE CHARLES HYDER TRUST AND AS
TRUSTEE OF THE GEOFFREY HYDER TRUST; WHITNEY HYDER MORE,
INDIVIDUALLY AND AS TRUSTEE OF THE ELTON MATTHEW HYDER IV TRUST, AS
TRUSTEE OF THE PETER ROWAN MORE TRUST, AS TRUSTEE OF THE LILI LOWDON
HYDER TRUST, AND AS TRUSTEE OF THE SAMUEL DOUGLAS MORE TRUST; AND
HYDER MINERALS, LTD., RESPONDENTS

4444444444444444444444444444444444444444444444444444
ON PETITION FOR REVIEW FROM THE
COURT OF APPEALS FOR THE FOURTH DISTRICT OF TEXAS
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JUSTICE BROWN , joined by JUSTICE WILLETT , JUSTICE GUZMAN , and JUSTICE LEHRMANN ,
dissenting.

I disagree with the Court that the overriding royalty clause expresses an intent to modify the

default rule that such an interest bears post-production costs. I would reverse the court of appeals and

hold that Chesapeake’s deduction of post-production costs was proper. I respectfully dissent.
 The disputed clause gives the Hyders a “cost-free (except only its portion of production

taxes) overriding royalty of five percent (5.0%) of gross production obtained from each [directionally

drilled] well.” This Court has held that “[a]n overriding royalty is an interest in the oil and gas

produced at the surface, free of the expense of production.” Paradigm Oil, Inc. v. Retamco

Operating, Inc., 372 S.W.3d 177, 180 n.1 (Tex. 2012) (quoting Stable Energy, L.P. v. Newberry, 999

S.W.2d 538, 542 (Tex. App.—Austin 1999, pet. denied)). Though it is free of production expenses,

an overriding royalty generally bears its share of post-production costs. French v. Occidental

Permian Ltd., 440 S.W.3d 1, 3 (Tex. 2014) (citing Heritage Res., Inc. v. NationsBank, 939 S.W.2d

118, 121–22, 123 (Tex. 1996)); Blackmon v. XTO Energy, Inc., 276 S.W.3d 600, 604 (Tex.

App.—Waco 2008, no pet.) (“Whatever costs are incurred after production of the gas or minerals

are normally proportionately borne by both the operator and the royalty interest owners.” (emphasis

in original) (quoting Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 444–45 (Tex.

App.—Corpus Christi 2006, pet. denied))). Parties to a lease, however, are free to allocate those

costs as they wish. French, 440 S.W.3d at 8 (citing Heritage, 939 S.W.2d at 121–22). As with any

other contract, we construe an oil-and-gas lease to give effect to the intent it expresses. Tittizer v.

Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005) (per curiam).

I agree with the Court that the measure of the overriding royalty here—“gross production

obtained from each such well”—refers to the total volume of minerals extracted from the ground

before any are used to fuel production or transportation or are lost en route to market. Exxon Corp.

v. Middleton, 613 S.W.2d 240, 244 (Tex. 1981) (“Production means actual physical extraction of the

mineral from the land.” (citing Monsanto Co. v. Tyrrell, 537 S.W.2d 135 (Tex. Civ. App.—Houston

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[14th Dist.] 1976, writ ref’d n.r.e.))); Blackmon, 276 S.W.3d at 604 (“Historically, ‘production’

ceases once the lessee extracts oil or gas from the ground at the wellhead.” (quoting Byron C.

Keeling & Karolyn King Gillespie, The First Marketable Product Doctrine: Just What Is the

“Product”?, 37 ST . MARY ’S L.J. 1, 88–89 (2005))). I disagree, however, that this measure allows

valuation downstream at any point of sale. The clause does not refer to any point of resale

downstream. It implicates only one location—the wellhead at which point each directional well

produces.

By contrast, the Hyders’ gas royalty is “twenty-five percent (25%) of the price actually

received” upon resale by Chesapeake. That price necessarily reflects any post-production value

added, and the Court rightly observes it thus does not bear post-production costs. See ante at ___;

cf. Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 137 (Tex. 1996) (holding royalty based on “gross

proceeds” would not allow deductions but royalty based on “net proceeds” would). The parties could

have expressed the overriding royalty similarly, but they did not do so. See Middleton, 613 S.W.2d

at 245 (“If the parties intended royalties to be calculated on the amount[-]realized standard, they

could and should have used only a ‘proceeds-type’ clause.” (emphasis in original)).

Post-production activities will add value to the Hyders’ overriding royalty—their share of

minerals produced from the directional wells—but it has not yet done so at the time of production.

Though the overriding royalty may not have been expressed using the familiar market-value-at-the-

well language, I read its value as being just that. Cf. Heritage, 939 S.W.2d at 131 (Owen, J.,

concurring) (“There are any number of ways the parties could have provided that the lessee was to

bear all costs of marketing the gas.”).

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 I further disagree that whether the Hyders accept cash rather than their share of production

in kind should affect that value. Had they taken the actual gas as it was produced, they certainly

would incur post-production and transportation costs in marketing the gas. They could, of course,

also use that gas on the property for whatever purpose they found useful. But the manner in which

they accept their royalty should not determine the value they receive. That Chesapeake undertook

to market the gas should not saddle Chesapeake with post-production costs or entitle the Hyders to

more than the royalty for which they bargained.

Likewise, I think the “cost-free” designation should not operate to add value to the Hyders’

overriding royalty, and I disagree with the Court that it expresses an intent to abrogate the default

rule that the lessee bears post-production costs. Though it need not be further spelled out that a

royalty interest is free of production costs, parties commonly do so anyway. See, e.g., Martin v.

Glass, 571 F. Supp. 1406, 1410 (N.D. Tex. 1983), aff’d,736 F.2d 1524 (5th Cir. 1984) (interpreting

overriding royalty that was “free and clear of all cost of drilling, exploration or operation”); Delta

Drilling Co. v. Simmons, 338 S.W.2d 143, 147 (Tex. 1960) (interpreting “overriding royalty interest,

free and clear of all cost of development”); McMahon v. Christmann, 303 S.W.2d 341, 343 (Tex.

1957) (considering overriding royalty that was “free of cost or expense”); Midas Oil Co. v. Whitaker,

123 S.W.2d 495, 495 (Tex. Civ. App.—Eastland 1938, no writ) (interpreting overriding royalty that

was “free of cost”). As the Court recognizes, courts often read such language as simply stressing the

production-cost-free nature of a royalty without struggling to ascertain any additional meaning. See

ante at ___. I would do so here.

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 The Court points out that the disputed clause excepts from the “cost-free” designation the

Hyders’ share of production taxes, which it suggests cuts against Chesapeake’s interpretation. Ante

at ___. It may be true that we have, on occasion, generally categorized taxes as a post-production

cost. See Heritage, 939 S.W.2d at 122. But, as the Court recognizes, parties often allocate tax

liability on the royalty owner while at the same time specifically emphasizing that the royalty is free

from production costs. See, e.g., Martin, 571 F. Supp. at 1410 (interpreting overriding royalty that

was “free and clear of all cost of drilling, exploration or operation, SAVE AND EXCEPT said

interest shall be subject to its proportionate part of all gross production, ad valorem and severance

taxes”); Delta Drilling, 338 S.W.2d at 147 (interpreting overriding royalty that was “free and clear

of all costs of development, except taxes”); R.R. Comm’n v. Am. Trading & Prod. Corp., 323 S.W.2d

474, 477 (Tex. Civ. App.—Austin 1959, writ ref’d n.r.e.) (interpreting overriding royalty that was

“free of all costs, except taxes”). The drafting in those instances suggests some parties consider taxes

production costs. The taxes at issue here are specifically referred to as “production taxes,” aligning

them with production, not post-production, costs. See TEX . TAX CODE §§ 201.001(6), .051, .052

(imposing production tax calculated on “market value of gas produced and saved” and defining

production as “gross amount of gas taken from the earth”). I do not believe the reference to

production taxes here supports an inference that “cost-free” refers to post-production costs.

As recognized in Heritage, royalty clauses that purport to modify a royalty valued at the well

are inherently problematic. 939 S.W.2d at 130 (Owen, J., concurring) (“The concept of ‘deductions’

of marketing costs from the value of the gas is meaningless when gas is valued at the well.”). Here,

no post-production costs have been incurred at the time of production, and it means nothing to say

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the overriding royalty is free of those yet-to-be incurred costs. I would resolve this tension to give

full meaning to “gross production,” which defines the interest where “cost-free” is only an adjective

describing it.

Where the overriding royalty interest is merely “cost-free,” the 25% oil-and-gas royalty is

specified as being:

free and clear of all production and post-production costs and expenses, including
but not limited to, production, gathering, separating, storing, dehydrating,
compressing, transporting, processing, treating, marketing, delivering, or any other
costs and expenses incurred between the wellhead and Lessee’s point of delivery or
sale of such share to a third party.

(emphasis added). The Court touches on the interpretive issues this language presents. Because the

gas royalty is valued by sale price after post-production value has already been added, the Court

deems the language ineffective and suggests it is surplusage or it at most emphasizes the cost-free

nature of the gas royalty. Ante at ___. I agree. Application to the oil royalty, defined as “twenty-five

percent (25%) of the market value at the well,” is no less problematic. As Heritage illustrates, a

market-value-at-the-well royalty is calculated by deducting post-production costs, and a court may

have difficulty giving effect to language that may be read as intent to free the royalty from those

costs. While the “free and clear” language here may seem to express intent that both royalties do not

bear post-production costs, giving it that effect is logically difficult.

This may be where the so-called Heritage disclaimer, located in the oil-and-gas royalty

clause, comes into play. I do not argue with the Court’s assessment that Heritage “holds only that

the effect of a lease is governed by a fair reading of its text,” ante at ___, and I agree a disclaimer

of that precedent cannot itself free a royalty of post-production costs. But the “free and clear”

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language here is similar in specificity to the language held ineffective in Heritage, which provided

“there shall be no deductions from the value of Lessor’s royalty by reason of any required processing,

cost of dehydration, compression, transportation or other matter to market such gas.” 939 S.W.2d

at 120– 21. The disclaimer could be interpreted as a belt-and-suspenders attempt to ensure the “free

and clear” language is given effect despite its conflict with the oil royalty’s market-value-at-the-well

definition.

We are not asked to resolve these interpretive issues. But the vast difference between the

royalty and overriding royalty clauses drills home my interpretation of the latter. If the extensive,

specific, and detailed “free and clear” language should be read as only emphatic or surplusage, so

should the mere “cost-free” designation. If the “free and clear” language expresses intent to modify

the market-value-at-the-well oil royalty so that it does not bear post-production costs, the mere “cost-

free” adjective cannot express the same intent as to the overriding royalty.

For the same reasons, I disagree with the Hyders that the Heritage disclaimer requires a broad

construction of “cost-free.” Where the oil-and-gas royalty’s extensive “free and clear” language

resembles the language interpreted in Heritage, the overriding royalty’s language does not. Where

the “no deductions” language in Heritage was meaningless and ineffective, I read “cost-free” as

redundant but not meaningless. And though the disclaimer expressly extends to “the terms and

provisions of this Lease,” its location in the oil-and-gas-royalty clause highlights that it is intended

to support the “free and clear” language, not to give the simple “cost-free” designation any additional

meaning.

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 ***

Parties are free to allocate post-production costs as they wish, and “[o]ur task is to determine

how those costs were allocated under [this] particular lease[].”Heritage, 939 S.W.2d at 124 (Owen,

J., concurring). I read the overriding-royalty clause as granting the Hyders a percentage of production

before post-production value is added and without allocating their share of post-production costs to

Chesapeake. I would thus hold Chesapeake properly deducted post-production costs to arrive at the

royalty’s value and would reverse the court of appeals’ judgment.

______________________________
Jeffrey V. Brown
Justice

OPINION DELIVERED: June 12, 2015

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