No. 14-0302 IN THE SUPREME COURT OF TEXAS 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. HYDER JR. MARITAL TRUST, ET AL., Respondents. Appeal from the Fourth Court of Appeals at San Antonio, Texas MOTION FOR REHEARING Bart A. Rue State Bar No. 17380500 [email protected]Matthew D. Stayton State Bar No. 24033219 [email protected]Joe Greenhill State Bar 24084523 [email protected]Kelly Hart & Hallman LLP 201 Main Street, Suite 2500 Fort Worth, Texas 76102 Telephone: (817) 332-2500 Telecopier: (214) 878-9280 Deborah G. Hankinson State Bar No. 00000020 [email protected]Rebecca Adams Cavner State Bar No. 00784900 [email protected]Hankinson LLP 750 N. St. Paul Street, Suite 1800 Dallas, Texas 75201 Telephone: (214) 754-9190 Telecopier: (214) 754-9140 Counsel for Petitioners Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc. FILED 14-0302 8/5/2015 2:49:37 PM tex-6370247 SUPREME COURT OF TEXAS BLAKE A. HAWTHORNE, CLERK
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No. 14-0302
IN THE SUPREME COURT OF TEXAS
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. HYDER JR. MARITAL TRUST, ET AL.,
Respondents.
Appeal from the Fourth Court of Appeals at San Antonio, Texas
MOTION FOR REHEARING
Bart A. Rue State Bar No. 17380500 [email protected] Matthew D. Stayton State Bar No. 24033219 [email protected] Joe Greenhill State Bar 24084523 [email protected] Kelly Hart & Hallman LLP 201 Main Street, Suite 2500 Fort Worth, Texas 76102 Telephone: (817) 332-2500 Telecopier: (214) 878-9280
Deborah G. Hankinson State Bar No. 00000020 [email protected] Rebecca Adams Cavner State Bar No. 00784900 [email protected] Hankinson LLP 750 N. St. Paul Street, Suite 1800 Dallas, Texas 75201 Telephone: (214) 754-9190 Telecopier: (214) 754-9140
Counsel for Petitioners Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc.
FILED14-03028/5/2015 2:49:37 PMtex-6370247SUPREME COURT OF TEXASBLAKE A. HAWTHORNE, CLERK
ii
TABLE OF CONTENTS
Table of Authorities ................................................................................................ iiii
Reasons for Rehearing ............................................................................................... 1
I. The Court Created Out of a Single Overriding Royalty Two Royalties Having Entirely Different Values. ................................................................... 4
A. Having Failed to Identify the Point At Which the Overriding Royalty Is To Be Valued, the Court’s Analysis Goes Far Afield of Texas Royalty Law. .......................................................................... 4
B. Whether Taken In Cash or In-Kind, An Overriding-Royalty Has One Value. ...................................................................................... 6
C. The Overriding-Royalty Provision Does Not Disallow Post-Production Costs.................................................................................... 7
D. The Gas Royalty and Overriding Royalty Are Different. ................... 12
II. The Court’s Dicta Unsettles Well-Established Law Interpreting Proceeds-Royalty Clauses. ............................................................................ 15
“production taxes” referred to in paragraph 10 are not post-production expenses
because production taxes do nothing to enhance the value of the gas and instead
are based on the act of producing gas. TEX. TAX CODE § 201.052.
9
Third, as the Dissent observed, lease provisions often allocate production-tax
liability to the royalty owner, while at the same time emphasizing that the royalty
is free from production costs. Dissent 5. The language here is substantively no
different than in many cases. See, e.g., Delta Drilling Co. v. Simmons, 338 S.W.2d
143, 147 (Tex. 1960) (overriding royalty was “free and clear of all cost of
development, except taxes”); Martin, 571 F. Supp. at 1410 (overriding royalty was
“free and clear of all cost of drilling, exploration or operation, SAVE AND
EXCEPT said interest shall be subject to . . . gross production, ad valorum and
severance taxes”). Thus, the allocation of taxes to the Hyders does not make “cost-
free” refer to post-production costs. And although the Court referred to these taxes
as “post-production taxes,” the parties labeled them “production taxes” in
paragraph 10 – yet another indication that they did not view the taxes as a post-
production expense.
The Court relied on Heritage to characterize the taxes as post-production
costs. But, at best, the language in Heritage is just an offhand comment. Heritage,
939 S.W.2d at 122. Such a passing reference should not be outcome
determinative. Nor should it be the basis for a wholesale change in the law.
The Court’s misinterpretation of “cost-free (except only its portion of
production taxes)” also fails to harmonize that clause with the rest of paragraph 10.
Southland Royalty Co. v. Pan Am. Petroleum Corp., 378 S.W.2d 50, 57 (Tex.
10
1964) (requiring courts “to harmonize and thus to give meaning to all apparently
conflicting provisions of a contract”). By failing to harmonize the various terms
within paragraph 10, the Court created a conflict between “cost-free” and “5% of
gross production.”
This overriding royalty is a gross-production royalty that is paid on the
volumes and values to be determined at the wellhead. The lessee sells the gas at
the well, and the buyer later sells the gas to third parties after the buyer has
incurred post-production expenses to enhance the value of the gas. These third-
party sales prices are used to determine the value of the wellhead gas so that the
overriding royalty can be paid. To ascertain the value of the wellhead gas so that
the royalty can be paid on the contracted-for values, rather than on the enhanced
values reflected in the third-party sales prices, the post-production expenses must
be netted-back. The netback calculation determines the values at the wellhead on
which the royalty payments are to be made. Judice v. Mewbourne Oil Co., 939
S.W.2d 133, 135 (Tex. 1996); Heritage, 939 S.W.2d at 126-27. The Court
acknowledged that this is exactly how Chesapeake is paying the overriding royalty.
Opinion 3-4.
By interpreting “cost-free (except only its portion of production taxes)” to
disallow post-production expenses, the Court precluded the netback and moved the
valuation point downstream. In so doing, the Court “add[s] value to the Hyders’
11
overriding royalty.” Dissent 4. This interpretation creates a conflict between cost-
free and the contracted-for “5% of gross production,” which by its terms requires
that both volume and value be determined at the wellhead. See Heritage, 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.”) If
the Court interpreted “5% of gross production,” “cost-free overriding royalty,” and
“production taxes” using the meanings that Texas law attributes to them, as
explained earlier in this motion, the provisions of paragraph 10 would be
harmonized and the conflict avoided. See Heritage, 939 S.W.2d at 129-30 (Owen,
J., concurring) (“Parties entering into [oil and gas] agreements expect that the
words they have used will be given the meaning generally accorded to them.”)
Finally, the Court made the following startling statement:
But Chesapeake must show that while the general term “cost-free” does not distinguish between production and postproduction costs and thus literally refers to all costs, it nevertheless cannot refer to postproduction costs here.
Opinion 7. Thus, although Texas law has long recognized that terms like “cost-
free overriding royalty” are used to mean “free of production costs,” the Court held
that these terms now mean “free of production and post-production costs,” unless
the lessee can prove otherwise. This marks an abrupt change in the law and
ignores how this language has been interpreted previously by courts.
12
Before this Opinion, a lessee could prove that “cost-free overriding royalty”
meant cost-free of production costs only because of the use of the term “gross
production,” which has certain legal meaning, and the nature of an overriding-
royalty interest. Contracting parties who used “cost-free” or similar language now
will find this language has a different legal meaning, unless the lessee can prove
otherwise. Nothing in the parties’ agreement, this case, or in the industry today
merits upending the law this way.
D. The Gas Royalty and Overriding Royalty Are Different.
Although the overriding-royalty interest is described in the Lease that
reserves the landowners’ royalty, the parties agreed the overriding-royalty interest
would be stand-alone conveyances apart from the subject oil-and-gas lease. The
Court’s analysis recognizes but ignores the conveyances, blurring the differences
between the overriding-royalty provision (paragraph 10) and the landowners’
royalty provision (paragraph 5) and misinterpreting paragraph 10 to provide two
royalties having different values.
Paragraph 10 created a contractual obligation to convey an overriding
royalty in production from “underlying lands other than the Leased Premises or
lands pooled therewith” when Chesapeake drilled directionally deviated wells from
the surface owned by the Hyders. It prescribes a single overriding-royalty interest.
13
It contains no language that can be interpreted to provide for two differently valued
royalties.
The parties’ agreement for Chesapeake to convey an overriding royalty of
“5% of gross production” from each of these off-lease wells, if production was
obtained, was an agreement to act in the future. Like all overrides, the paragraph
10 overriding royalty was to be carved out of the lessee’s working interest. See
WILLIAMS & MEYERS, Manual of Terms, p. 674. This royalty was not to be carved
out of Chesapeake’s working interest in the Hyders’ leased premises. Instead, it
was to be carved out of Chesapeake’s working interest in leases for minerals
underlying other land. The Lease makes clear that the overriding-royalty
conveyances were to be compensation for Chesapeake’s use of the surface of the
Hyders’ leased premises, not for mineral extraction. See Lease ¶¶ 6-11 (lease
provisions involving surface use). The overriding royalty is simply the currency
with which Chesapeake agreed to pay the Hyders in the future if it used the
Hyders’ severed surface estate to drill directionally deviated wells.
When the Hyders sold the minerals under their land to Chesapeake in fee
simple determinable, they reserved to themselves in paragraph 5 a royalty interest
in the oil-and-gas production from their land described in the lease. This reserved
royalty gave them the right to share in production from that lease pursuant to
paragraph 5’s specific terms.
14
Paragraph 5(b) expressly provides that the gas royalty is a proceeds-type
royalty payable in cash or to be taken in-kind when the lessor gives notice that the
lessee should deliver his “royalty share” to a designated purchaser. Royalty is to
be paid on 25% of the “price actually received by Lessee for the gas” after its value
has been enhanced post-production, “free and clear of all production and post-
production costs and expenses.” The Court concluded that paragraph 5(b) gave the
Hyders the option to choose between two differently valued royalties. Although
the gas royalty is not at issue, it bears noting that whether the lessors are paid the
gas royalty in cash or take in-kind, they actually receive the same “royalty share”
under paragraph 5(b).
In contrast, by its terms, the overriding-royalty is in-kind and “payable” on
volumes produced from other leases. The Hyders had the right to be paid for the
value of those volumes whether the volumes were sold, lost, used, flared, or vented
gas; that is, they were to be paid on the value of the “gross production.” But they
did not have the option of selecting how the overriding royalty would be paid.
Although there is no provision in paragraph 10 for the Hyders to take
possession or direct delivery of their 5% of the production, the Court implied
otherwise. It inexplicably imported into its paragraph 10 analysis a paragraph 5
quote that “each Lessor has the continuing right and option to take its royalty share
15
in kind.” Opinion 3. From this misstep, the Court crafted its dual-valued
overriding-royalty interest. Opinion 8.
Nothing in the contract justifies importing the paragraph 5 language into
paragraph 10. Paragraph 10 stands alone as a conveyance with a different royalty
provision and different terms. Paragraph 5(b) has nothing to do with the
compensation that Chesapeake promised to the Hyders for future surface use. Nor
should it inform the Court’s analysis.
The Court either overlooked or disregarded decades of its own precedent on
interpreting overriding-royalty clauses, valuing royalties, and calculating royalty
payments, as well as the tax statutes. Had it followed its precedent, the Court
would have enforced the parties’ bargain and met the settled expectations of
landowners and the oil-and-gas industry who rely upon the predictability and
uniformity of this Court’s decisions. For these reasons, the Court should do so
now on rehearing.
II. The Court’s Dicta Unsettles Well-Established Law Interpreting Proceeds-Royalty Clauses.
Although whether gas royalties have been properly paid on proceeds is not
at issue, the Court’s interpretation of the proceeds royalty infected its interpretation
of the overriding royalty. While comparing paragraphs 5 and 10, the Court made
sweeping statements in dicta about paying royalties on proceeds that contradict
longstanding oil-and-gas jurisprudence:
16
• “Often referred to as a ‘proceeds lease,’ the price-received basis for payment is sufficient in itself to excuse the lessors from bearing postproduction costs.” Opinion 5.
• “A gas royalty does not bear postproduction costs . . . because the amount is based on the price actually received by the lessee.” Opinion 8.
These pronouncements represent a sea change in the law and significant confusion
will follow.
The Court also made a related statement in dicta that will create further
confusion:
The 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.
Opinion 5. This statement implies that when a lessee under a proceeds lease sells
at the wellhead to its affiliate, royalty payments must be based on the gross
proceeds the affiliate received on its third-party sales, rather than on the proceeds
actually received by the lessee. If the Court meant this, its position is contrary to
established law.
This Court has consistently held that under a proceeds lease, the lessee owes
the lessor a royalty based on the price the lessee receives from its buyer in an
actual sale of gas. Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex.
2008); Union Pac. Res. Group, Inc. v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003);
Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372 (Tex. 2001). But a royalty owner
17
is not entitled under a proceeds lease to a royalty calculated on the price the
lessee’s buyer receives for the gas, without netting-out post-production expenses
that the lessee’s buyer incurs. So says Texas Law. See, e.g., Occidental Permian
Ltd. v. Helen Jones Found., 333 S.W.3d 392, 400 (Tex. App.—Amarillo 2011, pet.
denied) (evidence of proceeds received by an affiliated but different company from
sales at locations far removed from the wellhead is not evidence of the amount the
lessee realized from sale of raw gas at the well); Tana Oil & Gas Corp. v.
(lessee’s royalty obligations are independent of gas-purchase contracts; the
royalties are fixed and unaffected by the gas contracts; there is no privity between
lessor and purchaser who contracts with the lessee); see Middleton, 613 S.W.2d at
245 (same). The Court’s dicta contradicts this established precedent.
Relying on these established legal principles, parties who negotiate a
proceeds lease intend that the royalty will be based on the proceeds the lessee
actually receives for the sale of the gas. The price the lessee’s buyer ultimately
obtains for the gas after processing, transporting, and marketing it to a purchaser
hundreds of miles away is simply not part of the deal between the royalty owner
18
and the lessee, unless specifically provided for under the lease. For the Court to
imply that a proceeds-lease royalty owner, absent some special language in the
lease changing how royalty is to be computed, is entitled to payments based on the
gross amount the lessee’s buyer receives for the gas, without deductions for post-
production costs, defeats the parties’ expectations and is a radical departure from
existing law.
The Court’s footnote that “Chesapeake does not dispute that ‘the price
actually received by the Lessee’ for purposes of the gas royalty is the gas sales
price its affiliate, Marketing, received” reflects a misunderstanding of
Chesapeake’s position. Opinion n.17. Chesapeake did not dispute for purposes of
this lawsuit that the price actually received by the lessee was the price its buyer
received from third-parties. Although Chesapeake argued that post-production
costs incurred after it delivered the gas to a third-party at the gathering-system
tailgate but before the gas was sold to another third-party could be netted-out of
royalty, the court of appeals held that post-production costs incurred before the
point of sale to a third-party were prohibited under the lease. If it were not for
special lease language purportedly prohibiting post-production costs incurred
between the wellhead and lessee’s point of delivery or sale to a third-party, the
Hyders would have no basis to argue that royalty should not be computed based on
proceeds received by the lessee at the point of sale at the well.
19
Because the proper interpretation of the gas royalty is not the subject of this
appeal, the Court announced a new rule on proceeds leases without the benefit of
briefing on this very important subject. This significant departure from prior law
will create widespread disruption in the oil-and-gas industry. The Court should
grant this Motion for Rehearing to correct what may have been inadvertent, but
nonetheless grave, misstatements of Texas law. If the Court intends to change the
law, Chesapeake respectfully requests it wait to do so until a case presents itself
that will allow the issues to be fully briefed and considered.
PRAYER
Chesapeake respectfully requests that this Court withdraw its Opinion,
rehear this cause, reverse the judgment of the Court of Appeals, and render
judgment that Respondents take nothing from Petitioners.
20
Respectfully submitted,
/s/ Deborah G. Hankinson
Bart A. Rue State Bar No. 17380500 [email protected] Matthew D. Stayton State Bar No. 24033219 [email protected] Joe Greenhill State Bar 24084523 [email protected] Kelly Hart & Hallman LLP 201 Main Street, Suite 2500 Fort Worth, Texas 76102 Telephone: (817) 332-2500 Telecopier: (214) 878-9280
Deborah G. Hankinson State Bar No. 00000020 [email protected] Rebecca Adams Cavner State Bar No. 00784900 [email protected] Hankinson LLP 750 N. St. Paul Street, Suite 1800 Dallas, Texas 75201 Telephone: (214) 754-9190 Telecopier: (214) 754-9140 Counsel for Petitioners
CERTIFICATE OF COMPLIANCE
Based on a word count run in Microsoft Word 2007, this motion for rehearing contains 4,328 words, excluding the portions of the document exempt from the word count under Texas Rule of Appellate Procedure 9.4(i)(1).
/s/ Rebecca Adams Cavner Rebecca Adams Cavner
21
CERTIFICATE OF SERVICE
I hereby certify that on August 5, 2015, a true and correct copy of this motion for rehearing was served electronically on the following counsel of record for Respondents through the electronic filing manager in accordance with Rule 9.5(b) of the Texas Rules of Appellate Procedure:
Michael A. Heidler [email protected] Vinson & Elkins LLP 2801 Via Fortuna, Suite 100 Austin, Texas 78746 Counsel for Amicus Curiae Texas Oil & Gas Association
Marie R. Yeates [email protected] Vinson & Elkins LLP 1001 Fannin street, Suite 2500 Houston, Texas 77002 Counsel for Amicus Curiae Texas Oil & Gas Association
David J. Drez III [email protected] Jeffrey W. Helberg, Jr. [email protected] Jacob T. Fain [email protected] Wick Phillips Gould & Martin, LLP 100 Throckmorton, Suite 500 Fort Worth, Texas 76102 Counsel for Respondents
Ken Slavin [email protected] Kemp Smith LLP 221 North Kansas, Suite 1700 El Paso, Texas 79901 Counsel for Amicus Curiae The General Land Office Of the State of Texas
Roger D. Townsend [email protected] Robert B. Dubose [email protected] Alexander Dubose Jefferson & Townsend LLP 1844 Harvard Street Houston, Texas 77008 Counsel for Amicus Curiae Wesley West Minerals, Ltd. and Longfellow Ranch Partners LP
Dana Livingston [email protected] Alexander Dubose Jefferson & Townsend LLP 515 Congress Avenue, Suite 2350 Austin, Texas 78701 Counsel for Amicus Curiae Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP
22
Hon. Raul A. Gonzalez [email protected] 10511 River Plantation Dr. Austin, Texas 78747 Counsel for Texas Land and Mineral Owners Association and National Association of Royalty Owners-Texas, Inc.
John B. McFarland [email protected] Graves, Dougherty, Hearon & Moody, P.C. 401 Congress Avenue, Suite 2200 Austin, Texas 78701 Counsel for Texas Land and Mineral Owners Association and National Association of Royalty Owners-Texas, Inc.
/s/ Rebecca Adams Cavner Rebecca Adams Cavner
23
APPENDIX
Tab Item
1. Opinion
2. Dissenting Opinion
3. Lease
Tab 1
IN THE SUPREME COURT OF TEXAS
444444444444
NO. 14-0302444444444444
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. HYDER JR. MARITAL TRUST; BRENT ROWAN HYDER,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
overriding royalty to include a share of the value of the gas produced, less pro rata taxes paid on the gas).
See supra n.19. 22
BLACK’S LAW D ICTIONARY 818 (10th ed. 2014).23
7
volume on which a royalty is due must be determined at the wellhead says nothing about whether
the overriding royalty must bear postproduction costs.
This is clear from the other royalty provisions. The oil royalty is paid on all oil produced and
bears postproduction costs. The gas royalty is due on all gas produced and used or sold—that is, all
gas produced except that lost before sale or use. 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.
Chesapeake argues that the gas royalty provision shows that when the parties wanted a
postproduction-cost-free royalty, they were much more specific. But as we have already said, the
additional detail in the gas royalty provision serves only, if anything, to emphasize its cost-free
nature. The simple “cost-free” requirement of the overriding royalty achieves the same end.
The overriding royalty provision reads as though the royalty is in kind, but Chesapeake does
not argue that it must be, and in fact the royalty has always been paid in cash. Were the Hyders to
take their overriding royalty in kind, as they are entitled to do, they might use the gas on the property,
transport it themselves to a buyer, or pay a third party to transport the gas to market as they might
negotiate. In any event, the Hyders might or might not incur postproduction costs equal to those
charged by Marketing. The lease gives them that choice. The same would be true of the gas royalty,
which is to be paid in cash but can be taken in kind. The fact that the Hyders might or might not be
subject to postproduction costs by taking the gas in kind does not suggest that they must be subject
to those costs when the royalty is paid in cash. The choice of how to take their royalty, and the
8
consequences, are left to the Hyders. Accordingly, we conclude that “cost-free” in the overriding
royalty provision includes postproduction costs.
The Hyders offer another reason for our conclusion. They argue that the lease’s disclaimer
of any application of the holding of Heritage Resources shows that the parties intended an overriding
royalty free of postproduction costs. That case involved royalty provisions based on the market value
of gas at the well with “no deductions from the value of the Lessor’s royalty by reason of any”
postproduction costs. The Court concluded that the no-deductions phrase was unambiguous and24
ineffective to free the royalties from postproduction costs. Justice Owen’s concurring opinion, which
became the plurality opinion for the Court, explained:25
There is little doubt that at least some of the parties to these agreementssubjectively intended the phrase at issue to have meaning. However, the use of thewords “deductions from the value of Lessor’s royalty” is circular in light of this andother courts’ interpretation of “market value at the well.” The concept of“deductions” of marketing costs from the value of the gas is meaningless when gasis 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 givenpoint of sale, less the reasonable cost to get the gas to that point of sale, includingcompression, transportation, and processing costs. Evidence of market value is oftencomparable sales, as the Court indicates, or value can be proven by the so-callednet-back approach, which determines the prevailing market price at a given point andbacks 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 thatthere are no marketing costs to “deduct” from value at the wellhead.
. . . .
Heritage Res., 939 S.W.2d at 120–121.24
Justice Baker initially delivered the opinion for the Court, joined by Chief Justice Phillips, Justice Cornyn,25
Justice Enoch, and Justice Spector. Id. at 120. Justice Owen, joined by then-Justice Hecht, concurred in the judgment.
Id. at 124. Justice Gonzalez, joined by Justice Abbott, dissented. Id. at 131. On rehearing, Chief Justice Phillips joined
Justice Owen, Justice Cornyn and Justice Spector joined Justice Gonzalez, and Justice Enoch recused himself. 960
S.W.2d 619, 620 (Tex. 1997) (Gonzalez, J., dissenting on denial of motion for rehearing).
9
As long as “market value at the well” is the benchmark for valuing the gas,a phrase prohibiting the deduction of post-production costs from that value does notchange the meaning of the royalty clause. . . . All costs would already be borne by thelessee. It could not be said under that circumstance that the clause is ambiguous. Itcould only be said that the proviso is surplusage.26
Market value, if calculated without reference to factors necessary to that determination, is not market
value.
Heritage Resources does not suggest, much less hold, that a royalty cannot be made free of
postproduction costs. Heritage Resources holds only that the effect of a lease is governed by a fair
reading of its text. A disclaimer of that holding, like the one in this case, cannot free a royalty of
postproduction costs when the text of the lease itself does not do so. Here, the lease text clearly frees
the gas royalty of postproduction costs, and reasonably interpreted, we conclude, does the same for
the overriding royalty. The disclaimer of Heritage Resources’ holding does not influence our
conclusion.
* * * * *
The court of appeals’ judgment is affirmed.
Nathan L. HechtChief Justice
Opinion delivered: June 12, 2015
939 S.W.2d at 130–131 (citations omitted).26
10
Tab 2
IN THE SUPREME COURT OF TEXAS
444444444444
NO. 14-0302444444444444
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. HYDER JR. MARITAL TRUST; BRENT ROWAN HYDER,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
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.
4
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, includingbut not limited to, production, gathering, separating, storing, dehydrating,compressing, transporting, processing, treating, marketing, delivering, or any othercosts and expenses incurred between the wellhead and Lessee’s point of delivery orsale 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. BrownJustice