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
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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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