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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
Argument.................................................................................................................... 4
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
Prayer ....................................................................................................................... 19
Certificate of Compliance ........................................................................................ 20
Certificate of Service ............................................................................................... 21
Appendix .................................................................................................................. 23
iii
TABLE OF AUTHORITIES
Cases
Blackmon v. XTO Energy, Inc., 276 S.W.3d 600 (Tex. App.—Waco 2008, no pet.) ........................................ 5
Bowden v. Phillips Petroleum Co., 247 S.W.3d 690 (Tex. 2008) .........................................................................16
Danciger Oil & Refineries, Inc. v. Hamill Drilling Co., 171 S.W.2d 321 (Tex. 1943) ........................................................................... 5
Delta Drilling Co. v. Simmons, 338 S.W.2d 143 (Tex. 1960) ........................................................................... 9
Exxon Corp. v. Middleton, 613 S.W.2d 240 (Tex. 1981) .....................................................................5, 17
Fire Ass’n of Philadelphia v. Love, 101 Tex. 376 (1908) ........................................................................................ 5
Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) .......................................................... 4, 9, 10, 11
Judice v. Mewbourne Oil Co., 939 S.W.2d 133 (Tex. 1996) .........................................................................10
LeCuno Oil Co. v. Smith, 306 S.W.2d 190 (Tex. App.—Texarkana 1957, writ ref’d n.r.e.) ................... 8
Martin v. Glass, 571 F. Supp. 1406 (N.D. Tex. 1983) ...................................................... 6, 8, 9
Occidental Permian Ltd. v. Helen Jones Found., 333 S.W.3d 392 (Tex. App.—Amarillo 2011, pet. denied) ..........................17
Southland Royalty Co. v. Pan Am. Petroleum Corp., 378 S.W.2d 50 (Tex. 1964) ....................................................................... 9-10
Tana Oil & Gas Corp. v. Cernosek, 188 S.W.3d 354 (Tex. App.—Austin 2006, pet. denied) ..............................17
iv
Transamerican Natural Gas Corp. v. Finkelstein, 933 S.W.2d 591 (Tex. App.—San Antonio 1996, writ denied) ....................17
Union Pac. Res. Group, Inc. v. Hankins, 111 S.W.3d 69 (Tex. 2003) ...........................................................................16
Wilson v. United Tex. Transmission Co., 797 S.W.2d 231 (Tex. App.—Corpus Christi 1990, no pet.) ...................... 6-7
Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368 (Tex. 2001) ...........................................................................16
Statutes
TEX. TAX CODE § 201.001(6) ..................................................................................... 8
TEX. TAX CODE § 201.052 ......................................................................................... 8
Other Authorities
WILLIAMS & MEYERS, Manual of Oil & Gas Terms (15th ed.) ...........................7, 13
1
REASONS FOR REHEARING
The Court should withdraw its Opinion and rehear the case for two reasons.
First, the Court misread the contract’s single overriding-royalty provision to
create two royalties having different values, depending on whether the royalty
owners choose to take their interests in cash or in-kind. No Texas court has ever
interpreted a royalty clause in this anomalous way. As the Dissent correctly noted,
“the manner in which [the royalty owners] accept their royalty should not
determine the value they receive.”
According to the Court, the contract allows the Hyders to pick the royalty
they like best: (1) the one with a lower value, which they can take in-kind and
which “might” or “might not” bear post-production costs; or (2) the more valuable
royalty, which is paid in cash and bears no post-production costs. The Court said
that “[t]he lease gives them that choice” but never identified any language in the
overriding-royalty provision that could be construed to create two differently
valued overriding royalties. There is none.
The overriding royalty described in the Lease is a stand-alone interest
relating to other leases on other lands. It is a “gross-production” royalty that
compensates the Hyders when Chesapeake uses their severed surface estate to drill
directionally deviated wells to produce minerals underlying other lands. The
overriding royalty is “payable” on the volumes produced from these other leases.
2
The Court recognized the overriding-royalty provision as a “conveyance.”
Nothing in this stand-alone conveyance gives the Hyders the option of selecting
how the overriding royalty is paid, and nothing in it justifies the Court’s using the
provisions of the unrelated gas royalty to modify the overriding-royalty provision.
In interpreting the overriding-royalty provision, the Court disregarded its
own precedent, which set uniform standards for interpreting royalty clauses and
valuing royalties. Had the Court instead applied its precedent, the tax statutes, and
decades of Texas oil-and-gas law:
• It first would have decided the point at which the overriding “gross-
production” royalty was to be paid. But it did not. That inquiry would have
identified only one location – at the well.
• It would next have ascertained the value “at the well” of the Hyders’
royalty portion of gross-production by netting-back from the downstream third-
party sales prices the post-production expenses that enhanced the value of the gas.
• It would have determined that production taxes are what the
Legislature says they are – production taxes – and that production taxes tax
production and do not enhance the value of gas post-production.
• It would have concluded that the words “cost-free” and the like have
nothing to do with disallowing post-production costs and that a contrary decision
3
would preclude any netback calculation and improperly add value to the Hyders’
royalty by moving the point of valuation downstream.
Texas law has been carefully crafted over many decades to encourage an
effective and efficient oil-and-gas industry. Yet, the Court has now inexplicably
ignored the law. Respectfully, the Court’s opinion is wrong, and its rushed
decision should be corrected. Rehearing is merited so that consistency in our oil-
and-gas jurisprudence can be maintained. This has been the hallmark of this
Court’s previous decisions.
Second, although the interpretation of the gas royalty is not at issue, the
Court wrote extensively about it, and in dicta, contradicts and confuses the law on
proceeds royalties. The Court twice stated that a proceeds royalty categorically
does not bear post-production costs. These statements directly contradict this
Court’s precedent. The Court also implied in dicta that, when a lessee sells at the
wellhead to its affiliate, proceeds-royalty payments must be based on the gross
proceeds received by the lessee’s affiliate on third-party sales, rather than on the
proceeds actually received by the lessee. This has never been Texas law and is
contrary to the way the Court has dealt previously with affiliate sales.
Rehearing is also merited to correct these misstatements of Texas law.
4
ARGUMENT
I. The Court Created Out of a Single Overriding Royalty Two Royalties Having Entirely Different Values.
The Court misread paragraph 10 and concluded that the single overriding-
royalty interest may be valued in two different ways at the Hyders’ choice. Three
defects in the Court’s analysis led to this anomalous result. First, by failing to
identify the point at which the overriding-royalty’s value is fixed, the Court did not
value the overriding royalty according to the parties’ agreement and long-standing
Texas royalty law. Second, the Court misinterpreted the phrase “cost-free (except
only its portion of production taxes),” and then failed to recognize that its
misinterpretation cannot be harmonized with the requirement that the overriding
royalty be valued on “5% of gross production.” Third, the Court misused the
unrelated gas-royalty provision to modify the overriding-royalty provision.
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.
The Court missed the proper starting point for its analysis when it failed to
identify the point at which the overriding royalty is to be valued. Because a
royalty will have different values depending on its valuation location, Texas law
requires that a lease first be interpreted to determine the point at which the royalty
is to be calculated. Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 123 (Tex.
1996) (to determine correctly paid royalties under the lease, “we must first
5
determine the market value of the gas at the well,” the point at which royalty is to
be calculated); Danciger Oil & Refineries, Inc. v. Hamill Drilling Co., 171 S.W.2d
321 (Tex. 1943) (royalty payments were to be based on value of the gas at the
wellhead, not on value after being processed). The Court never explained why this
essential determination is missing from the Opinion. In contrast, the Dissent
determined that the language “5% of gross production obtained from each well,”
established the point at which the overriding royalty is to be valued. Dissent 3.
Texas law supports this conclusion. “Production means actual physical
extraction of the minerals from the land.” Dissent 2 (quoting Exxon Corp. v.
Middleton, 613 S.W.2d 240, 244 (Tex. 1981)). “‘Production’ ceases once the
lessee extracts oil or gas from the ground at the wellhead.” Blackmon v. XTO
Energy, Inc., 276 S.W.3d 600, 604 (Tex. App.—Waco 2008, no pet.) (production
is not the “act of transporting, gathering, treating, processing or marketing oil or
gas”). In turn, gross has an ordinary meaning: “[w]hole; entire; total; without
deduction.” Fire Ass’n of Philadelphia v. Love, 101 Tex. 376, 380 (1908). “Gross
production” therefore refers to the raw gas when it is produced at the wellhead
before any gas has been lost, used in the course of post-production activities, or
processed. As the Dissent emphasized, the royalty clause “implicates only one
location–the wellhead at which point each directional well produces.” Dissent 3.
As the Dissent further observed, the overriding-royalty provision is utterly devoid
6
of any language that would allow the Court to place the point of royalty-valuation
location downstream at the resale point or anywhere else but the wellhead. Dissent
3.
Yet, the Court concluded that the phrase “5% of gross production” refers to
volume only and does not define the point at which the overriding royalty is to be
valued. Opinion 7-8. After disclaiming the full import of the words “gross
production,” it then remained silent on the dispositive issue of the royalty-
valuation location. Opinion 7-8. At best, the Court implicitly answered the
question by disallowing post-production costs, thereby moving the valuation
location downstream to a resale point, and awarding the Hyders their royalty on the
value of the gas when it is sold downstream (5% of the third-party gas sales price).
This is simply wrong.
B. Whether Taken In Cash or In-Kind, An Overriding-Royalty Has One Value.
The Court said that the “[t]he choice of how to take their royalty, and the
consequences, are left to the Hyders.” Opinion 8-9. Not unexpectedly, the case
law is to the contrary. When a royalty owner takes an in-kind royalty in cash, he is
entitled to receive only the monetary equivalent of the in-kind payment. There is
no choice to be made. See Martin v. Glass, 571 F. Supp. 1406, 1410 (N.D. Tex.
1983) (royalty owner is entitled to “either his proportionate share of the actual
mineral produced . . . in barrels of oil, or the market value in cash of his
7
proportionate share”); Wilson v. United Tex. Transmission Co., 797 S.W.2d 231,
233 (Tex. App.—Corpus Christi 1990, no pet.) (royalty owner receiving his royalty
“in kind” is entitled to a share of the oil or gas as produced whereas a royalty
owner receiving his royalty “in money” is entitled to cash for the value or market
price of his share of the product); WILLIAMS & MEYERS, Manual of Oil & Gas
Terms p. 917-18 (15th ed.) (same). By summarily rejecting this rule, the Court
inexplicably allows the Hyders to take in cash more than they bargained to receive
in-kind, even though paragraph 10 does not provide such a right.
C. The Overriding-Royalty Provision Does Not Disallow Post-Production Costs.
As the Court acknowledged, Texas law has long recognized that “drafters
frequently specify that an overriding royalty does not bear production costs” by
using words like “cost-free.” Opinion 7. Thus, the Court would seem to have no
problem reaffirming that the phrases “overriding royalty,” “cost-free royalty,”
“overriding royalty free of production costs,” “overriding royalty free of all cost of
development,” and “overriding royalty free of all cost of drilling,” all mean the
same thing: an interest carved from the working interest that is a type of royalty
and that does not bear production costs. Opinion 6-7, n.19. The Court similarly
seems to have no problem saying that under prior Texas law, these terms have
nothing to do with disallowing post-production costs. Opinion 7. Yet, this
controlling law did not carry the day.
8
Instead, according to the Court, because production taxes are post-
production expenses, “[i]t would make no sense to state that a royalty is free of
production costs, except for post-production taxes (no dogs allowed, except for
cats).” Opinion 6. Respectfully, the clause at issue is “all dogs,” and the Court’s
conclusion that “production taxes [ ] are postproduction taxes” is wrong for three
reasons.
First, the Texas statutes that prescribe production taxes define production as
“the gross amount of gas taken from the earth or water” and calculate the taxes on
the “market value of gas produced and saved.” TEX. TAX CODE §§ 201.001(6),
201.052. Not surprisingly, the Legislature entitled the tax a “Production Tax,” not
a “Post-Production Tax,” thereby “aligning [the taxes at issue] with production, not
post-production costs.” Dissent 5.
Second, post-production expenses are costs incurred after production to
enhance the value of the gas. These costs include compression, transportation,
processing, and marketing. See Martin, 571 F. Supp. at 1411; LeCuno Oil Co. v.
Smith, 306 S.W.2d 190, 193 (Tex. App.—Texarkana 1957, writ ref’d n.r.e.). The
“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.
Cernosek, 188 S.W.3d 354, 361 (Tex. App.—Austin 2006, pet. denied) (under
proceeds lease, royalty owners were not entitled to royalties based on gross amount
buyer received for gas after processing); Transamerican Natural Gas Corp. v.
Finkelstein, 933 S.W.2d 591, 598 (Tex. App.—San Antonio 1996, writ denied)
(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
HYDER MINERALS, LTD., RESPONDENTS
4444444444444444444444444444444444444444444444444444
ON PETITION FOR REVIEW FROM THE
COURT OF APPEALS FOR THE FOURTH DISTRICT OF TEXAS
4444444444444444444444444444444444444444444444444444
Argued March 24, 2015
CHIEF JUSTICE HECHT delivered the opinion of the Court, in which JUSTICE GREEN, JUSTICE
JOHNSON, JUSTICE BOYD, and JUSTICE DEVINE joined.
JUSTICE BROWN filed a dissenting opinion, in which JUSTICE WILLETT, JUSTICE GUZMAN andJUSTICE LEHRMANN joined.
Generally speaking, an overriding royalty on oil and gas production is free of production
costs but must bear its share of postproduction costs unless the parties agree otherwise. The only
question in this case is whether the parties’ lease expresses a different agreement. We conclude it
does and therefore affirm the court of appeals’ judgment.1
The Hyder family leased 948 mineral acres in the Barnett Shale. Chesapeake Exploration,2
L.L.C., acquired the lessee’s interest. The lease was negotiated and drafted by counsel for the3
Hyders and the original lessee.
The lease contains three royalty provisions. One is for 25% of “the market value at the well
of all oil and other liquid hydrocarbons”. No oil is produced from the lease. Another royalty is for
25% “of the price actually received by Lessee” for all gas produced from the leased premises and
sold or used. The lease adds that the royalty is expressly “free and clear of all production and post-4
production costs and expenses,” and lists examples of various expenses. The third provision, the5
one here in dispute, calls for “a perpetual, cost-free (except only its portion of production taxes)
427 S.W.3d 472 (Tex. App.—San Antonio 2014). 1
The Hyder respondents include Martha Rowan Hyder, individually and as independent executrix and trustee2
under the Will of Elton M. Hyder Jr., deceased, 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 Hyder Minerals, Ltd. We refer to the lessors as the Hyders.
Petitioners are Chesapeake Exploration, L.L.C., and an affiliate that acts as its agent for all natural gas3
operations on the property, Chesapeake Operating, Inc. We refer to them collectively as Chesapeake.
The lease provides that this royalty is “for natural gas, including casinghead gas and other gaseous substances4
produced from the Leased Premises and sold or used on or off the Leased Premises” and that “[i]n no event shall the
volume of gas used to calculate Lessors’ royalty be reduced for gas used by Lessee as fuel for lease operations or for
compression or dehydration of gas.”
The royalty provision continues: “including but not limited to, production, gathering, separating, storing,5
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. Lessor’s royalty share
shall also be free and clear of all costs of construction, operation or depreciation of any plant or other facilities or
equipment used for processing or treating paid production.”
2
overriding royalty of five percent (5.0%) of gross production obtained” from directional wells drilled
on the lease but bottomed on nearby land. The lease contains two other provisions relevant to our6
consideration. One is this disclaimer: “Lessors and Lessee agree that the holding in the case of
Heritage Resources, Inc. v. NationsBank, 939 S.W. 2d 118 (Tex. 1996) shall have no application to
the terms and provisions of this Lease.” The other is that “each Lessor has the continuing right and
option to take its royalty share in kind”. No lessor has ever exercised that right. While the overriding
royalty appears to be in kind, the parties do not disagree that it can be paid in money.
The Hyders and Chesapeake agree that the overriding royalty is free of production costs; they
dispute whether it is also free of postproduction costs. There are twenty-nine producing gas wells
on the leased or pooled land, seven of which are directional wells bottomed on and producing from
lands not subject to the lease. Chesapeake sells all the gas produced to an affiliate, Chesapeake
Energy Marketing, Inc. (“Marketing”), which then gathers and transports the gas through both
affiliated and interstate pipelines for sale to third-party purchasers in distant markets. Marketing pays
Chesapeake a “gas purchase price” for volumes determined at the wellhead or—during earlier
periods—at the terminus of Marketing’s gathering system. The gas purchase price is calculated based
on a weighted average of the third-party sales prices received (the “gas sales price”) less
The lease states that “Lessee shall, within sixty (60) days from the date of first production from each6
[directional] well, convey to Lessors” the overriding royalty. The parties treat this royalty provision like a conveyance,
and so do we. Only two of the respondents, Brent Rowan Hyder and Whitney Hyder More, are alleged to own overriding
royalties. Because all respondents join in the arguments made here, we refer to the overriding royalties as due to the
Hyders.
3
postproduction costs. The overriding royalty Chesapeake pays the Hyders is 5% of the gas purchase7
price. The Hyders contend that their overriding royalty should be based on the gas sales price.
After a bench trial, the trial court rendered judgment for the Hyders, awarding them
$575,359.90 in postproduction costs that Chesapeake wrongfully deducted from their overriding
royalty. The court of appeals affirmed. We granted Chesapeake’s petition for review. 8 9
In Heritage Resources, Inc. v. NationsBank, we noted that a royalty is free of production
expenses but “usually subject to post-production costs, including taxes . . . and transportation
costs.” But we added that “the parties may modify this general rule by agreement.” We long ago10 11
defined an overriding royalty as “a given percentage of the gross production carved from the working
interest but, by agreement, not chargeable with any of the expenses of operation.” That agreement12
is now understood to be part of an overriding royalty, and an overriding royalty is like a landowner’s
Marketing deducts, as postproduction costs, gathering and transportation costs and a 3% marketing fee.7
427 S.W.3d 472 (Tex. App.—San Antonio 2014). 8
58 Tex. Sup. Ct. J. 227 (Jan. 30, 2015).9
939 S.W.2d 118, 121–122 (Tex. 1996); accord French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex.10
2014).
Heritage Res., 939 S.W.2d at 122; accord French, 440 S.W.3d at 3.11
MacDonald v. Follett, 180 S.W.2d 334, 336 (Tex. 1944).12
4
royalty in that it usually bears postproduction costs but not production costs, though the parties may13
agree to a different arrangement.14
Two of the royalty provisions in the Hyder–Chesapeake lease are clear. The oil royalty bears
postproduction costs because it is paid on the market value of the oil at the well. The market value15
at the well should equal the commercial market value less the processing and transporting expenses
that must be paid before the gas reaches the commercial market.16
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. Often referred to as a “proceeds lease”, the price-received basis for payment17
is sufficient in itself to excuse the lessors from bearing postproduction costs. And of course, like any
See Paradigm Oil, Inc. v. Retamco Operating, Inc., 372 S.W.3d 177, 180 n.1 (Tex. 2012) (“An overriding13
royalty is an interest in the oil and gas produced at the surface, free of the expense of production.” (internal quotation
marks omitted)); see also Alamo Nat’l Bank v. Hurd, 485 S.W.2d 335, 339 (Tex. Civ. App.—San Antonio 1972, writ
ref’d n.r.e.) (“An overriding royalty is first and foremost a royalty interest. In other words, it is an interest in oil and gas
produced at the surface, free of the expenses of production.”).
See Heritage Res., 939 S.W.2d at 122 (noting that parties may agree to modify the general rule that a royalty,14
though not subject to production costs, is subject to postproduction costs); 8 H. W ILLIAM S & C. MEYERS, O IL AND GAS
LAW : MANUAL OF O IL AND GAS TERM S 731 (2014) (“One of the most important aspects of an ‘overriding royalty’ . . .
is that it is a ‘royalty,’ viz., in the absence of an express agreement to the contrary it is free of costs of which the lessor’s
royalty is free and it is subject to the costs to which the lessor’s royalty is subject.”).
See Heritage Res., 939 S.W.2d at 122.15
Id.16
Chesapeake does not dispute that “the price actually received by the Lessee” for purposes of the gas royalty17
is the gas sales price its affiliate, Marketing, received, nor do the Hyders argue that the gas sales price was unfair. Cf.
Phillips Petroleum Co. v. Yarbrough, 405 S.W.3d 70, 78 (Tex. 2013) (“A duty to market is implied in leases that base
royalty calculations on the price received by the lessee for the gas. Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 373–74
(Tex. 2001).”).
5
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.18
It might be regarded as emphasizing the cost-free nature of the gas royalty, or as surplusage.
The overriding royalty in the Hyder–Chesapeake lease is not as clear as either of the other
two royalty provisions. The Hyders argue that the requirement that the overriding royalty be “cost-
free” can only refer to postproduction costs, since the royalty is by nature already free of production
costs without saying so. But as with the gas royalty, “cost-free” may simply emphasize that the
overriding royalty is free of production costs. Chesapeake argues that “cost-free overriding royalty”
is merely a synonym for overriding royalty, and a number of lease provisions discussed in other cases
support that view.19
The exception for production taxes, which are postproduction expenses, cuts against20
Chesapeake’s argument. It would make no sense to state that the royalty is free of production costs,
except for postproduction taxes (no dogs allowed, except for cats). The exception for taxes might
be taken to indicate that “cost-free” refers only to postproduction costs. But a taxes exception to
The court of appeals reasoned otherwise, relying on the “free and clear” language to conclude that both the18
oil and gas royalties are free of postproduction costs. 427 S.W.3d at 477–478. Chesapeake has not challenged that ruling
in this Court.
See, e.g., McMahon v. Christmann, 303 S.W.2d 341, 343 (Tex. 1957) (lease providing an “overriding royalty19
. . . free of cost or expense”); 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.) (agreement reserving an “overriding royalty of 3/8ths of 8/8ths of all the oil, gas
and other minerals produced and saved from said lands . . . free of all costs, except taxes”); Midas Oil Co. v. Whitaker,
123 S.W.2d 495, 495 (Tex. Civ. App.—Eastland 1938, no writ) (assignor’s retention of “an overriding royalty of 7/32
of all oil, gas or other minerals . . . free of cost to himself”).
Heritage Res., 939 S.W.2d at 122.20
6
freedom from production costs is not uncommon in leases, suggesting only that lease drafters are21
not always driven by logic.
We thus disagree with the Hyders that “cost-free” in the Hyder–Chesapeake overriding
royalty provision cannot refer to production costs. As noted above, drafters frequently specify that
an overriding royalty does not bear production costs even though an overriding royalty is already free
of production costs simply because it is a royalty interest. But Chesapeake must show that while22
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.
Chesapeake argues that because the overriding royalty is paid on “gross production”, the
reference is to production at the wellhead, making the royalty tantamount to one based on the market
value of production at the wellhead, which bears postproduction costs. “Gross” means
“[u]ndiminished by deduction; entire”. We agree with Chesapeake, as do the Hyders, that “gross23
production” is the entire amount of gas produced, including gas used by Chesapeake or lost in
postproduction operations. But the parties do not dispute that the overriding royalty may be paid in
cash and not in kind, though the Hyders retained the right to take it in kind. Specifying that the
See, e.g., Martin v. Glass, 571 F. Supp. 1406, 1410 (N.D. Tex. 1983); Delta Drilling Co. v. Simmons, 33821
S.W.2d 143, 147 (Tex. 1960); McMahon, 303 S.W.2d at 350; Graham v. Prochaska, 429 S.W.3d 650, 653 (Tex.
App.—San Antonio 2013, pet. filed); Am. Trading & Prod. Corp., 323 S.W.2d at 477; Wahlenmaier v. Am. Quasar
Petroleum Co., 517 S.W.2d 390, 392 (Tex. Civ. App.—El Paso 1974, writ ref’d n.r.e.); see also Zephyr Oil Co. v.
Cunningham, 265 S.W.2d 169, 172 (Tex. Civ. App.—Fort Worth 1954, writ ref’d n.r.e.) (lessor sought reformation of
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
HYDER MINERALS, LTD., RESPONDENTS
4444444444444444444444444444444444444444444444444444
ON PETITION FOR REVIEW FROM THE
COURT OF APPEALS FOR THE FOURTH DISTRICT OF TEXAS
4444444444444444444444444444444444444444444444444444
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
2
[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.”).
3
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, 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.
7
* * *
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
OPINION DELIVERED: June 12, 2015
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