Devon Energy Production Company, L.P., F/K/A GeoSouthern DeWitt Properties, LLC, BPX Properties (NA) LP, GeoSouthern Energy Corporation, and BPX Production Company v. Michael A. Sheppard ( 2020 )

NUMBER 13-19-00036-CV
COURT OF APPEALS
THIRTEENTH DISTRICT OF TEXAS
CORPUS CHRISTI – EDINBURG
DEVON ENERGY PRODUCTION
COMPANY, L.P., F/K/A GEOSOUTHERN
DEWITT PROPERTIES, LLC, BPX
PROPERTIES (NA) LP, GEOSOUTHERN
ENERGY CORPORATION, AND BPX
PRODUCTION COMPANY, Appellants,
v.
MICHAEL A. SHEPPARD, ET AL., Appellees.
On appeal from the 24th District Court
of DeWitt County, Texas.
MEMORANDUM OPINION
Before Chief Justice Contreras and Justices Benavides and Longoria
Memorandum Opinion by Chief Justice Contreras
We issued our memorandum opinion and judgment in this cause on June 25, 2020.
Appellants Devon Energy Production Company, L.P., f/k/a GeoSouthern DeWitt
Properties, LLC, BPX Properties LP, GeoSouthern Energy Corporation, and BPX
Production Company have filed a motion for rehearing. Pursuant to our request, appellees
Michael A. Sheppard, et al. filed a response to the motion, and appellants filed a reply to
the response. We deny the motion for rehearing but withdraw our earlier memorandum
opinion and judgment and substitute the following memorandum opinion and its
accompanying judgment in their place.
In this wide-ranging dispute concerning the valuation of oil and gas royalties,
appellants argue that the trial court erred by granting summary judgment to appellees.
Appellants also challenge the trial court’s decision to exclude their experts’ affidavits.
The case involves highly unique royalty provisions in some DeWitt County oil and
gas leases. The parties jointly filed a stipulation with the trial court setting forth twenty-
three issues, each asking whether appellants violated the leases by failing to add
particular amounts to the total figure upon which appellees’ royalty payments were based.
Upon cross-motions for summary judgment, the trial court found in favor of appellees on
all twenty-three disputed issues and rendered declaratory judgment.
We conclude that appellants are required to pay royalties on amounts attributable
to post-production costs of the types specified in the leases, even when those costs are
actually borne by a third-party downstream purchaser rather than by appellants. However,
the leases do not require appellants to pay royalties on (1) amounts deducted from a
sales price without a stated purpose, (2) volumes of gas which are used by appellants for
their own operations and never sold, (3) volumes of gas which are deemed to be lost or
unaccounted for by third parties, or (4) the excess value retained by processors as a
2
result of applying predetermined factors to measure how much of each liquid hydrocarbon
is recovered. We affirm in part and reverse and render in part.
I. BACKGROUND
A. Royalty Terms
Beginning in 2007, appellees 1 leased mineral interests to appellants under
agreements—the Sheppard Lease and the Crain Lease—which contain the following
royalty provisions:
3. The royalties to be paid by Lessee are:
(a) on oil, One-Fifth (1/5th)[ 2] of that produced and saved from said land,
the same to be delivered, free of all costs and expenses to the Lessor into
the pipeline, or other receptacle to which the Lessee may connect its wells
or the market value thereof, at the option of the Lessor, such value to be
determined by (1) the highest posted price, plus premium, if any, offered or
paid for oil, condensate, distillate, or other liquid hydrocarbons, respectively
of a like type and gravity for the field where produced and when run, or (2)
the gross proceeds of the sale thereof, whichever is greater;
(b) on gas, including casinghead gas or other gaseous substance, produced
from said land, One-Fifth (1/5th) of the greater of (1) the market value at the
wellhead of such gas, paid to Lessor free of all costs and expenses, or (2)
the gross proceeds realized from the sale of such gas, free of all costs and
expenses, to the first non-affiliated third party purchaser under a bona fide
arms length sale or contract. “Gross proceeds” (for royalty payment
purposes) shall mean the total monies and other consideration accruing to
or paid the Lessee or received by Lessee for disposition or sale of all
unprocessed gas proceeds, residue gas, gas plant products or other
products. Gross proceeds shall include, but is not limited to advance
payments, take-or-pay payments (whether paid pursuant to contract, in
settlement or received by judgment) reimbursement for production or
severance taxes and any and all other reimbursements or payments.
The parties agree that, with respect to all oil and gas produced from the leases, the royalty
Appellees are Michael A. Sheppard, Constance S. Kirk, Jennifer S. Badger, Frank B. Sheppard,
1
James K. Crain, Shirley R. Crain, Christopher M. Crain, James K. Crain III, and Patrick G. Crain.
2
The Sheppard Lease calls for a 1/5 royalty whereas the Crain Lease prescribes a 1/4 royalty. The
difference is immaterial for purposes of the issues considered here.
3
was paid as a percentage of appellants’ gross proceeds from the sale of those minerals
to downstream third-party purchasers. However, the leases’ royalty terms continue with
the following unique provision:
(c) If any disposition, contract or sale of oil or gas shall include any reduction
or charge for the expenses or costs of production, treatment, transportation,
manufacturing, process or marketing of the oil or gas, then such deduction,
expense or cost shall be added to the market value or gross proceeds so
that Lessor’s royalty shall never be chargeable directly or indirectly with any
costs or expenses other than its pro rata share of severance or production
taxes.
The leases also contained several addenda, including the following:
L. ROYALTY FREE OF COSTS:
Payments of royalty under the terms of this lease shall never bear or be
charged with, either directly or indirectly, any part of the costs or expenses
of production, gathering, dehydration, compression, transportation,
manufacturing, processing, treating, post-production expenses, marketing
or otherwise making the oil or gas ready for sale or use, nor any costs of
construction, operation or depreciation of any plant or other facilities for
processing or treating said oil or gas. Anything to the contrary herein
notwithstanding, it is expressly provided that the terms of this paragraph
shall be controlling over the provisions of Paragraph 3 of this lease to the
contrary and this paragraph shall not be treated as surplusage despite the
holding in the cases styled “Heritage Resources, Inc. v. NationsBank”, 939
S.W.2d 118 (Tex. 1996) and “Judice v. Mewbourne Oil Co.”, 939 S.W.2d
135–36 (Tex. 1996).
(Emphasis added.) This case concerns the construction and application of paragraph
3(c) 3 and Addendum L.
B. Procedural Background
On December 13, 2012, appellees filed suit alleging that appellants were selling
the oil and gas produced from the leases under contracts which contain an $18-per-barrel
3
There are two versions of the Sheppard Lease and three versions of the Crain Lease in the record.
The “shall be added” language appears in all versions of both leases, but it is not always numbered as
paragraph 3(c). We will refer to it as paragraph 3(c) for ease of reference.
4
“reduction” in the sales price attributable to “gathering and handling, including rail car
transportation.” Appellees alleged that appellants breached the leases by failing to add
the $18-per-barrel “reduction” to the amount upon which the royalty is calculated (the
royalty base) pursuant to the “shall be added” provision in paragraph 3(c) of the lease.
Appellees sought damages for breach of contract as well as declaratory relief and an
accounting. Appellees later filed two amended petitions, alleging several other instances
in which they believed appellants breached paragraph 3(c).
In March of 2017, the parties entered into a “Joint Stipulation as to Disputed Issues
for Adjudication” purporting to specify twenty-three issues for the trial court’s
consideration. 4 Each of the stipulated issues concerns a different marketing practice
engaged in by appellants which appellees contend violates the leases. Many are similar
to the claim concerning the $18-per-barrel charge in that they involve a reduction for post-
production costs, though several are not. Most of the issues contain references to
exemplar contracts between an appellant and a third-party purchaser. As to each of the
stipulated issues, the question is whether appellants breached the “shall be added” clause
of paragraph 3(c) of the leases by failing to add that particular amount to the royalty base.
The entire list of issues, including the references to exemplar contracts but excluding
record references, is attached as an appendix to this opinion.
C. Summary Judgment Motions
Both sides moved for summary judgment later in 2017. Appellees argued in their
motion that the subject leases unambiguously “require that [appellants] add any ‘reduction
4
According to the stipulation, appellees’ contract damages claim was severed into a separate
lawsuit and abated pending resolution of the declaratory judgment action.
5
or charge’ included in any ‘disposition, contract or sale of oil or gas’ back to the gross
proceeds before calculating [appellees’] royalty.” They argued that, whenever the
appellants sold oil and gas for a published price minus a fixed dollar amount, the fixed
dollar amount is a “reduction” which must be added to gross proceeds to calculate the
royalty. They also argued that, when appellants sold natural gas liquids to processors and
allowed the processors to keep a portion of the product, that reduces the volume sold,
and this “volumetric reduction” is also subject to paragraph 3(c). Appellees further
contended that, when appellants sold natural gas liquids to a processor for a percentage
of a certain defined value, the reduction to the value must be added back to the royalty
base. Finally, appellees argued that, when appellants or third parties use minerals
produced from the leases as fuel for their own operations, or set a certain percentage of
gas as “lost and unaccounted for,” that also represents a “reduction” to which paragraph
3(c) applies. As evidence supporting their motion, appellees attached sealed deposition
excerpts from Anice Johnston, Petrohawk’s Royalty Compliance Supervisor, 5 and Kim
Whyburn, Devon’s Operations Accounting Supervisor. Appellants responded, and
appellees filed a reply containing additional evidence, including an affidavit by Charles
Graham, a petroleum engineer.
In their summary judgment motion, appellants agreed that the subject leases are
unambiguous. But appellants argued that the lease bases the royalties on their “gross
proceeds” received, meaning the amount each appellant actually receives “at the point of
sale.” Thus, according to appellants, paragraph 3(c) does not require them to add
5
Following the filing of suit, Petrohawk was acquired by BHP Billiton Petroleum Properties N.A.,
LP, which later became appellant BPX Properties (NA) LP.
6
amounts to gross proceeds which were deducted for expenses which necessarily must
take place after the point of sale. Appellants attached affidavits of oil and gas industry
experts Kris Terry and Lesa Adair, as well as Lawrence Gregory, former Vice President
of Marketing and Midstream at Devon’s predecessor. They also attached sealed
deposition excerpts from Johnston and Whyburn as well as attorneys Rodney Landes,
Nelson Lee, and Diaco Aviki. Appellants filed a response accompanied by another
affidavit by Graham, as well as an affidavit by appellee Christopher Crain.
The summary judgment evidence included two “Joint Appendi[ces] to Parties’
Motions for Summary Judgment.” One of the appendices was unsealed and contained
copies of the leases at issue. The other appendix was filed under seal and contained all
of the exemplar contracts identified in the stipulation.
D. Evidentiary Motions and Rulings
Appellants objected to twenty-five individual statements made in Graham’s
affidavits on various grounds, mainly arguing that Graham offered improper and
unfounded legal opinions. Appellants also objected to Crain’s affidavit on multiple
grounds. Appellees objected to and moved to exclude the affidavits of Terry and Adair,
specifying twenty-two different statements by Terry and thirty different statements by
Adair which it contended were incompetent summary judgment evidence for various
reasons.
After a hearing on October 12, 2017, the trial court: (1) granted appellees’ motions
to exclude the affidavits of Terry and Adair; (2) overruled appellants’ objections to the
affidavits of Graham and Crain; and (3) granted summary judgment in favor of appellees
on all twenty-three issues specified in the stipulation. The trial court signed a “Declaratory
7
Judgment on the Parties’ Cross-Motions for Summary Judgment” on December 28, 2017.
Appellants attempted to perfect an appeal in 2018, but we held the December 28, 2017
judgment was not final because appellees’ claim for attorney’s fees remained pending.
See Devon Energy Prod. Co. v. Sheppard, No. 13-18-00069-CV, 2018 WL 3062579, at
*1–2 (Tex. App.—Corpus Christi–Edinburg June 21, 2018, no pet.) (mem. op.). After
appellees non-suited their request for attorney’s fees, the trial court signed an “Order
Granting Nonsuit and Final Judgment” on December 13, 2018, and this appeal followed.
II. EVIDENTIARY RULINGS
We begin by addressing appellants’ second issue, concerning the trial court’s
evidentiary rulings. Although the trial court serves as an evidentiary gatekeeper by
screening out irrelevant and unreliable expert evidence, it has broad discretion to
determine the admissibility of evidence. Exxon Pipeline Co. v. Zwahr, 88 S.W.3d 623,
629 (Tex. 2002). A trial court abuses its discretion when its ruling is arbitrary,
unreasonable, or without reference to any guiding rules or legal principles. E.I du Pont de
Nemours & Co. v. Robinson, 923 S.W.2d 549, 558 (Tex. 1995).
Appellants contend that the court erred by excluding Terry’s and Adair’s affidavits
and by overruling their objections to Graham’s and Crain’s affidavits. They principally
argue that Graham provided improper, conclusory opinions as to ultimate legal questions
facing the court. They further argue that the trial court arbitrarily and unreasonably applied
different standards to their expert affidavits. They contend that “[e]ither the experts are
admissible, or they are not. . . . There is no principled reason to reject [appellants’] experts
but accept [appellees’].”
In order to obtain reversal based on an error in the admission or exclusion of
8
evidence, an appellant must show that the ruling (1) probably caused the rendition of an
improper judgment or (2) probably prevented the appellant from properly presenting the
case on appeal. TEX. R. APP. P. 44.1(a). In their briefs on appeal, appellants do not allege
or argue that the trial court’s evidentiary rulings met this standard for reversible error. See
id.; see also TEX. R. APP. P. 38.1(i). Instead, appellants are equivocal as to whether an
analysis of the issue is necessary to the appeal’s disposition. See TEX. R. APP. P. 47.1
(“The court of appeals must hand down a written opinion that is as brief as practicable but
that addresses every issue raised and necessary to final disposition of the appeal.”). For
example, at the conclusion of the argument in their brief regarding their second issue,
appellants ask us to find in their favor only “[t]o the extent it is necessary to consider the
expert admissibility issues to decide this appeal . . .” (emphasis added). Elsewhere,
appellants argue: “If it is necessary to reach the expert testimony issues to decide this
appeal, the judgment cannot be upheld on the basis of the trial court’s flawed and one-
sided examination of expert testimony” (emphasis added).
The only statement in appellants’ brief which could be construed as addressing
harm resulting from the evidentiary rulings is as follows: “To the extent [the trial court]
used these irrelevant opinions to alter the meaning of unambiguous text, the ruling was
harmful.” But appellants do not allege or establish that the trial court actually or probably
did “use” Graham’s or Crain’s testimony in fashioning its ruling, and they do not provide
any argument in this regard. Moreover, to the extent this cursory statement may be
construed as addressing the reversibility standard, it pertains only to alleged harm
resulting from the trial court’s admission of appellees’ expert affidavits; it provides no
explanation for why the trial court’s exclusion of appellants’ expert affidavits would
9
constitute reversible error.
We conclude that appellants have failed to establish that any error in the trial
court’s evidentiary rulings would be reversible. See TEX. R. APP. P. 38.1(i), 44.1(a). We
therefore overrule their second issue. 6
III. SUMMARY JUDGMENT
By their first issue, appellants contend the trial court erred in granting appellees’
summary judgment motion and denying their motion. The parties agree that the royalty
provisions at issue are unambiguous, and they agree that there are no Texas cases
reviewing similar lease language. They simply disagree as to what the provisions
unambiguously require.
A. Standard of Review
A movant for traditional summary judgment has the burden to establish that no
genuine issue of a material fact exists and that it is entitled to judgment as a matter of
law. TEX. R. CIV. P. 166a(c); Amedisys, Inc. v. Kingwood Home Health Care, LLC, 437
S.W.3d 507, 511 (Tex. 2014). We review summary judgments de novo. Scripps NP
Operating, LLC v. Carter, 573 S.W.3d 781, 790 (Tex. 2019). When, as here, both parties
move for summary judgment and the trial court grants one motion and denies the other,
we review all the summary judgment evidence, determine all issues presented, and
render the judgment the trial court should have rendered. Merriman v. XTO Energy, Inc.,
6
We note that, in this case, we are not asked to determine whether there is a genuine issue of
material fact raised by the evidence. The parties agree that the leases are unambiguous and susceptible
to interpretation by the court as a matter of law, and the factual background surrounding the formation of
the leases and the transactions between producers and processors is largely undisputed. The question is
how to apply the unique lease provisions to those facts. See Jones Energy, Inc. v. Pima Oil & Gas, L.L.C.,
No. 07-17-00456-CV, 2020 WL 1869024, at *4 (Tex. App.—Amarillo Apr. 14, 2020, no pet. h.) (op. on reh’g)
(noting that “the construction of an unambiguous instrument is a matter of law determination, upon which
another’s opinion would not be binding”).
10
407 S.W.3d 244, 248 (Tex. 2013).
B. Applicable Law
As with any other unambiguous contract, we construe a mineral lease as a matter
of law, seeking to enforce the intention of the parties as expressed therein. Tittizer v.
Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005) (per curiam). We examine and
consider the entire writing in an effort to harmonize and give effect to all its provisions so
that none will be rendered meaningless. J.M. Davidson, Inc. v. Webster, 128 S.W.3d 223,
229 (Tex. 2003). No single provision taken alone will be given controlling effect; rather,
all the provisions must be considered with reference to the whole instrument. Id. 7
As a general rule, although royalty payments are not subject to the costs of
production, they are usually subject to post-production costs, including taxes, treatment
costs to render the minerals marketable, and transportation costs. Heritage Res., Inc. v.
NationsBank, 939 S.W.2d 118, 122 (Tex. 1996). But the parties to a lease may agree to
modify this general rule. Id. Whether and to what extent a lease has effectively modified
7
Courts have long held that, when an oil and gas lease is subject to two or more equally reasonable
interpretations even after rules of construction are applied, the interpretation more favorable to the lessor
will be adopted. Zeppa v. Hous. Oil Co. of Tex., 113 S.W.2d 612, 615 (Tex. App.—Texarkana 1938, writ
ref’d) (“[I]t appears to be the settled rule in this state that of two or more equally reasonable constructions
of which the language of an oil and gas lease is susceptible the one more favorable to the lessor will be
allowed to prevail.”); see Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, 291 Fed. App’x 626, 631 (5th Cir.
2008) (per curiam, not designated for publication); Champlin Petroleum Co. v. Ingram, 560 F.2d 994, 998
(10th Cir. 1977) (applying Texas law); Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 133 (Tex. 1996)
(Gonzalez, J., dissenting); Freeman v. Samedan Oil Corp., 78 S.W.3d 1, 7 (Tex. App.—Tyler 2001, judgm’t
vacated w.r.m.); see also Sirtex Oil Indus., Inc. v. Erigan, 403 S.W.2d 784, 788 & n.2 (Tex. 1966) (noting
that, ordinarily, “a lease will be most strongly construed against the lessor,” but “[t]his rule does not apply
to oil and [ga]s leases”). But the preference for the lessor’s interpretation is based at least in part on an
assumption that the lease was drafted by the lessee. See Freeman, 78 S.W.3d at 7 (noting that “[i]n
constructing an oil and gas lease, its language is generally regarded as that of the lessee” and “the language
of an oil and gas lease is to be construed against the drafting party”). Here, the Crain Lease states: “This
lease was prepared as the joint effort of the Lessor and Lessee. The rule of construction that ambiguities
in a document will be construed against the party who drafted it will not be applied in interpreting the
provisions of this lease.” The Sheppard Lease does not contain this provision. Appellees do not argue on
appeal that their interpretation of either lease should be favored merely because of their status as lessors.
11
this rule has been a recurring question for the courts. Every lease is different, and the
result in one case does not control a case where the terms involved are different. See
Warren v. Chesapeake Expl., L.L.C., 759 F.3d 413, 416 (5th Cir. 2014) (“[I]f anything is
clear from the many Texas decisions dealing with royalty provisions, it is that different
royalty provisions have different meanings.”). Still, a review of similar cases can assist in
clarifying the jurisprudence in this area. Such cases include the two specifically cited in
the Addendum L of the Sheppard and Crain Leases: Heritage Resources, Inc. v.
NationsBank and Judice v. Mewbourne Oil Co.
In Heritage, the leases granted a royalty on gas equal to one-fourth or one-fifth of
the “market value at the well,” “provided, however, that there shall be no deductions from
the value of the 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. NationsBank, the royalty owner, sued Heritage, the lessee, claiming that
Heritage improperly deducted certain transportation costs from their gas sale proceeds
before calculating the royalty. Id. at 118. The trial court and court of appeals agreed with
NationsBank that this was a violation of the no-deductions clause. Id.
On petition for review, Heritage argued that the leases “define the lessor’s royalty
as a fraction of the market value at the well” and therefore, “the clauses limiting deduction
from the value of the lessor’s royalty simply mean[] that Heritage cannot deduct an
amount from the sales price that would make the royalty paid less than the required
fraction of market value at the well.” Id. at 121. The supreme court agreed, observing that
“the Lessor’s Royalty” is “clearly” defined in the leases as a fraction “of the market value
at the well.” Id. at 122. Therefore, the lease provision stating that “there shall be no
12
deductions from the value of the Lessor’s Royalty” for certain expenses merely means
that “the lessee cannot pay the lessor less than his fractional value of the comparable
sales price (market value).” Id. It does not mean that the lessee is prohibited from
deducting post-production costs, such as expenses for transporting gas from well to
market, from the total amount the lessee realizes from a downstream sale. See id.
The lessee was permitted to deduct those costs from its gross proceeds because
the royalty was defined as a percentage of the “market value at the well.” The Heritage
Court explained that “market value at the well” has a “commonly accepted meaning in the
oil and gas industry” and may be calculated by taking the market value at the point of sale
and then subtracting reasonable post-production marketing costs. Id. at 122. “Post-
production marketing costs include transporting the gas to the market and processing the
gas to make it marketable.” Id. In light of these definitions, the Court rejected
NationsBank’s argument, which had been adopted by the court of appeals, that the no-
deductions clause evinced an intent to prohibit the deduction of post-production
transportation costs when determining “market value at the well.” See id. The Court “did
not disagree” with the court of appeals’ view that, because royalty interests are normally
subject to post-production costs anyway, Heritage’s interpretation renders the no-
deductions clause meaningless. Id. at 121. Nevertheless, the Court found that the clause
“merely restate[s] existing law”—i.e., that a royalty based on the “market value at the well”
does not bear production expenses—and constitutes “surplusage as a matter of law.” Id.
The Texas Supreme Court handed down Judice on the same day as Heritage.
There, the royalty owners argued that “Mewbourne had improperly paid royalties on gas
by deducting the Judices’ pro rata share of post-production compression costs from the
13
proceeds from the sale of the gas.” 939 S.W.2d 133, 135 (Tex. 1996). The royalties in
that case were due under two leases and three division orders. Id. at 135–36. The leases
defined the Judices’ gas royalty as a fraction of the “market value of the well”—therefore,
under the leases, Mewbourne was entitled to deduct a “proportionate share of the
reasonable cost of post-production compression” from the royalty base. Id. at 135. On the
other hand, two of the division orders stated that the Judices’ royalty on gas sold is “based
on the gross proceeds realized at the well.” Id. at 136. The Court held this was ambiguous
because, while “gross proceeds” means that the royalty is to be based on the “gross price
received by Mewbourne,” the term “at the well” “indicates just the opposite”—i.e., that the
royalty is to be based on its value “before it has been compressed and before other value
is added in preparing and transporting the gas to market.” Id. Finally, the third division
order stated that the Judices’ interest is “based on the net proceeds realized at the well
by [the Judices].” Id. The Court concluded that, due to its use of the word “net,” the third
order unambiguously permitted Mewbourne to “deduct[] post-production compression
costs from the proceeds received for the sale of the gas.” Id. (observing that the term “net
proceeds” “expressly contemplates deductions,” and “at the well” means “before value is
added by preparing the gas for market”).
Twenty years later, in Chesapeake Exploration v. Hyder, the supreme court
considered a similar question in the context of an overriding royalty interest (ORRI). See
483 S.W.3d 870, 872 (Tex. 2016) (defining an ORRI 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”). The lease at issue there contained three royalty
provisions: the first entitled the Hyders to 25% of “the market value at the well of all oil
14
and other liquid hydrocarbons” produced from the leases; the second entitled them to
25% of “the price actually received by [Chesapeake]” for all gas produced from the leases,
expressly “free and clear of all production and post-production costs and expenses”; and
the third royalty provision entitled the Hyders to “a perpetual, cost-free (except only its
portion of production taxes) overriding royalty of five percent (5.0%) of gross production
obtained” from directional wells drilled on the lease but bottomed on nearby land. Id. at
871–72.
In that case, Chesapeake sold all of the gas produced from the lease at issue to
its marketing affiliate, which in turn sold the gas to third-party purchasers in distant
markets. Id. at 872. The marketing affiliate paid Chesapeake a “gas purchase price” which
was calculated based on a weighted average of the third-party sales prices received by
the marketing affiliate (the “gas sales price”) minus post-production costs. Id. For the
Hyders’ ORRI in the gas produced from seven directional wells bottomed on adjacent
land, Chesapeake paid 5% of the “gas purchase price,” but the Hyders sued, claiming
that they were instead entitled to 5% of the “gas sales price.” Id.
The trial court, the court of appeals, and a 5–4 majority of the Texas Supreme
Court agreed with the Hyders. The Court’s majority noted that the first two royalty
provisions in the lease were clear as to post-production costs. Id. at 873. First, the 25%
oil royalty bears post-production costs because it is paid on the “market value of the oil at
the well,” which “should equal the commercial market value less the processing and
transporting expenses that must be paid before the gas reaches the commercial market.”
Id. (citing Heritage, 939 S.W.2d at 122). Second, the 25% gas royalty does not bear post-
15
production costs because it is “based on the price Chesapeake actually received from its
marketing affiliate,” without deductions for Chesapeake’s post-production costs. Id. 8
The ORRI provision, on the other hand, was not as clear. Id. The Hyders argued
that “cost-free” must refer to post-production costs, since a royalty by its nature is already
free of production costs; but Chesapeake argued that “cost-free” is “merely a synonym
for overriding royalty” and simply emphasizes that the ORRI is free of production costs.
Id. at 873–74. Chesapeake further contended that the term “gross production” refers to
“production at the wellhead,” meaning the royalty at issue would be equivalent to one
based on the “market value of production at the wellhead,” which bears post-production
costs. Id. at 874.
The Hyder majority noted that the ORRI’s exception for production taxes, which
are generally considered post-production costs, cuts against Chesapeake’s argument
because “[i]t would make no sense to state that the royalty is free of production costs,
except for post[-]production taxes (no dogs allowed, except for cats).” Id. (citing Heritage
Res., 939 S.W.2d at 122 (characterizing taxes as post-production costs)); but see id. at
878 (Brown, J., dissenting) (opining that the parties intended “production taxes” to be a
production cost). Nevertheless, the Texas Supreme Court observed that “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
8
The 25% gas royalty provision also stated that it is “free and clear of all production and post-
production costs and expenses.” Chesapeake Expl., LLC v. Hyder, 483 S.W.3d 870, 873 (Tex. 2016). But
the majority in Hyder noted that “[t]his addition has no effect on the meaning of the provision” and may be
regarded as surplusage. Id. (holding that “the price-received basis for payment in the lease is sufficient in
itself to excuse the [Hyders] from bearing post[-]production costs”).
16
interest.” Id. at 874 (observing that this suggests that “lease drafters are not always driven
by logic”).
As to the “gross production” language, the Court noted that the other two royalties
mentioned in the lease are also based on “full production” at the wellhead, and yet one
bears post-production costs and one does not. Id. at 874–75. It held that “[s]pecifying that
the volume on which a royalty is due must be determined at the wellhead says nothing
about whether the overriding royalty must bear post[-]production costs.” Id. at 874.
The Hyder majority concluded:
Chesapeake argues that the [25%] gas royalty provision shows that when
the parties wanted a post[-]production-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 post[-]production costs equal to those charged by [its marketing
affiliate]. 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 post[-]production 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 consequences, are left to the Hyders. Accordingly, we
conclude that “cost-free” in the overriding royalty provision includes
post[-]production costs.
Id. at 875.
Burlington Resources Oil & Gas Co. v. Texas Crude Energy also addressed
whether an ORRI was subject to post-production costs. The instrument at issue in that
case, an assignment, stated that the ORRI “shall be delivered to ASSIGNEE into the
17
pipelines, tanks or other receptacles with which the wells may be connected, free and
clear of all development, operating, production and other costs.” 573 S.W.3d 198, 201
(Tex. 2019). The assignment further provided that, should the assignee opt to take its
royalty in cash, the royalty would be based on the “value of the oil, gas or other minerals,
as applicable, produced and saved under the leases”—and “value” was defined as “the
amount realized from such sale of such production and any products thereof.” Id. at 201–
202. The assignee sued when it discovered that Burlington, the lessor, was deducting
post-production costs from its “amount realized” before calculating the royalty. Id. at 202;
see Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (“‘Proceeds’ or
‘amount realized’ clauses require measurement of the royalty based on the amount the
lessee in fact receives under its sales contract for the gas.”); Occidental Permian Ltd. v.
Helen Jones Found., 333 S.W.3d 392, 399 (Tex. App.—Amarillo 2011, pet. denied)
(“‘Amount realized’ means the proceeds received from the sale of gas or oil.”). The Texas
Supreme Court held that, because the assignment twice stated that the royalty “shall be
delivered . . . into the pipeline,” that meant the parties unambiguously specified a
valuation point “at the well”—i.e., before any additional value is added via post-production
expenses. Burlington, 573 S.W.3d at 209–11. Thus, notwithstanding the “amount
realized” language, the assignees were required to pay their share of post-production
costs. See id. at 205 (“We have never construed a contractual ‘amount realized’ valuation
method to trump a contractual ‘at the well’ valuation point. To the contrary, prior decisions
suggest that when the parties specify an ‘at the well’ valuation point, the royalty holder
must share in post-production costs regardless of how the royalty is calculated.”); id. at
207 (“A royalty on production valued at the well does not include the value added by post-
18
production costs. When a royalty payment is based on a downstream sales price, the
value added by post-production costs must be subtracted from the sales price or
otherwise accounted for in order to approximate the ‘at the well’ value of the products.”);
cf. Hyder, 483 S.W.3d at 874 (“Specifying that the volume on which a royalty is due must
be determined at the wellhead says nothing about whether the overriding royalty must
bear postproduction costs.”).
C. Summary Judgment Evidence
Appellees’ expert, Graham, explained in his affidavit that when raw natural gas is
produced from underground reservoirs, it is initially unsuitable for commercial use and
unsuitable for transportation in intrastate or interstate pipelines. To generate a marketable
product, the raw “wet” or “rich” natural gas must be processed to separate the liquid
hydrocarbons from the “dry” methane gas. The natural gas liquids (NGLs) then undergo
fractionation, a process under which the various NGL components—including ethane,
propane, butane, and isobutane—are separated from each other by boiling the mixture
at different temperatures.
After the methane gas is extracted, the liquid hydrocarbon mixture is known as “y-
grade.” Graham stated that the major fractionation center for producers in the Eagle Ford
Shale is located at Mont Belvieu, thirty miles east of Houston. According to Graham,
though daily market prices are published for the various components listed above, as well
as for “pipeline quality natural gas,” “[t]here have never been price postings or indices for
unfractionated y-grade at Mont Belvieu or at any other receipt points along a pipeline
system.” Accordingly, it is “common practice for purchasers of y-grade liquids at
processing plants to offer prices for y-grade based on postings for fractionated
19
products, . . . less the costs associated with transporting, fractionating, and marketing.”
Therefore, Graham stated, “the aggregate unit price for each gallon of a respective batch
of y-grade (demethanized mix of unfractionated [NGLs]) has embedded deductions for
transportation, fractionation and marketing.” The “residue gas” which remains after the
NGLs have been removed must then be processed to meet quality standards in order to
be transported via pipelines. Graham stated: “There are costs related to the production
of marketable products and the transportation of those marketable products to the
commercial market place. Furthermore, commercial markets for residue gas (pipeline
quality gas), located downstream of the gas processing plants utilized by [appellants], are
in the Houston Ship Channel area.”
In his affidavit, Crain averred that royalty clauses at issue in this case were
included in the leases “for the purpose of assuring that the intention that the Lessor not
be burdened with Lessees’ transportation and marketing decisions, costs and expenses
is clearly articulated.” He stated that, in his experience, oil and gas lessees such as
appellants “generally insist on having flexibility in their operations for marketing,
processing, transporting, fractionating, and otherwise enhancing the value of the
hydrocarbons produced from a lessor’s leased land.” Thus, a “lessor who does not want
to bear any part of the costs or expenses associated with a lessee’s marketing decisions
typically must find other ways to ensure that the reductions, expenses, charges, and costs
that may result from those decisions do not directly or indirectly reduce the lessor’s
royalty.” One way to do this, according to Crain, is to “bargain for and negotiate for a
favorable method of calculating and paying royalties, at the initial lease drafting and
negotiating phase.” Crain further opined that “lessors generally strive to ensure” that lease
20
agreements are “flexible to ever-changing industry factors,” including the development of
new technology and regulatory changes. He stated:
10. . . . The need for flexibility was particularly prevalent in the early days of
the Eagle Ford shale development around 2010. The landscape was
evolving as to whether the production would primarily yield oil or gas, how
the regulatory landscape might adjust to horizontal drilling and hydraulic
fracturing, how the industry infrastructure in the area might evolve, how the
midstream sector would adapt, and other critical commercial factors that
were out of a lessor’s control. These factors placed additional limitations on
a lessor’s ability to bargain for provisions that would influence a lessee's
marketing decisions.
11. The provisions affecting the payment of royalty that are present in the
leases in this lawsuit result from these competing lessor/lessee interests.
While lessors typically have no control over a lessee’s marketing decisions,
these unique provisions ensure that a lessor will avoid any costs or
expenses associated with a lessee’s marketing decisions. . . . There are no
exclusions in the provisions affecting the payment of royalties for
“bargained” reductions or pricing formulas. Also, there is no reference to
any point of sale, downstream or upstream, transfer of title, transfer of
possession, benefit, reasonableness, custom, or any . . . other limitation in
the royalty provisions. Rather than guess at describing the various contracts
and expenses associated with marketing, transporting, and processing
hydrocarbons produced from a lessor’s leased lands, the royalty provisions
are flexible by broadly requiring a lessee to add to the gross proceeds or
market value the amount of any reduction or charge included in any
disposition, contract or sale.
D. Analysis
Paragraph 3(c) of the leases is the starting point for all of the issues in dispute.
Appellants refer to this as an “add-back” clause and appellees refer to it as an “add-to-
proceeds” clause—a difference that echoes their respective summary judgment
positions.
Appellants argue “[t]his case involves an ordinary gross proceeds clause”—that is,
they claim the leases call for royalties “based on the gross proceeds [appellants] actually
receive at the point of sale, with no deductions.” They argue that whether or not an
adjustment to the royalty base for post-production expenses may be made is therefore
21
dependent on when and where those expenses are incurred relative to the “point of sale”
for each transaction. Thus, appellants agree that when they sell oil and gas downstream
from the well, the royalty base is equal to the gross proceeds received by the appellants
from that sale, without any downward adjustments for any post-production costs it
incurred or expended prior to the point of sale. However, according to appellants, if post-
production costs are expended after the point of sale, then downward adjustments to the
sale price to account for such anticipated costs are permissible under the leases. In such
a situation, appellants argue, the adjustments are not subject to paragraph 3(c) because
appellants never “directly or indirectly” incurred the costs at issue—instead, the
downstream purchaser incurred or anticipated incurring those costs. Appellants claim that
paragraph 3(c) “was negotiated for an economically rational purpose: to bargain around
the ‘at the well point of valuation’ rule established in Heritage and Judice regarding post-
production costs.”
On the other hand, appellees generally contend that the leases do not limit the
base to the gross proceeds received by appellants. Instead, they note that paragraph 3(c)
contemplates the addition of certain amounts to appellants’ gross proceeds before
calculating the royalty, and this necessarily means that the royalty base may end up being
larger than the proceeds received. And they emphasize that there is nothing in the leases
stating that an appellant must “incur” an expense in order for an adjustment related to
that expense to be subject to the “shall be added” clause. Appellees argue that appellants’
sales contracts “plainly include reductions or charges for expenses or costs” specified
under paragraph 3(c), and therefore, appellants were required to add all of those
“reductions or charges” to the royalty base. They contend that the leases were “intended
22
to strike an appropriate balance” in light of the “unknown and unique characteristics that
existed in the Eagle Ford in 2007.” According to appellees, the leases “allow [appellants]
wide latitude in determining whether to sell the products at the well, in the field, or take
them all the way to the target market center”; and “[a]s a tradeoff, the royalty provisions
entitled [appellees] to receive royalties that are insulated from the costs of [appellants’]
decisions.”
Under Texas law, “gross proceeds” means the amount the producer actually
receives in the sale of the minerals at issue. See Bowden, 247 S.W.3d at 699; Occidental
Permian Ltd., 333 S.W.3d at 399. This is generally consistent with paragraph 3(b) of the
leases, which defines “gross proceeds” as “total monies and other consideration accruing
to or paid the Lessee or received by Lessee for disposition or sale of all unprocessed gas
proceeds [sic], residue gas, gas plant products or other products.”
Appellants made royalty payments based on their “gross proceeds,” without
deductions for post-production expenses incurred by appellants prior to the point of sale,
but without any additions pursuant to paragraph 3(c). Appellants argue that this was
proper in part because the parties merely intended to prohibit deductions from “Lessor’s
royalty,” which they claim is defined as a percentage of gross proceeds—no more, no
less. But, when the royalty provisions are read together, they do not restrict “Lessor’s
royalty” in this manner. Though paragraphs 3(a) and 3(b) initially define the royalty at
least in part based on appellant’s gross proceeds, paragraph 3(c) expressly contemplates
the addition of certain sums to gross proceeds in order to arrive at the proper royalty base.
If the parties wished merely to prohibit deductions from gross proceeds, there would be
no reason to include paragraph 3(c). Appellants offer no other explanation for why
23
paragraph 3(c) would be included in the leases if not to allow the royalty base to exceed
gross proceeds. We will not construe the leases in such a manner as to render that unique
provision superfluous or meaningless. See J.M. Davidson, Inc., 128 S.W.3d at 229. 9
Under appellants’ interpretation, paragraph 3(c) would merely prohibit any
deductions from appellees’ royalty for costs incurred prior to the point of sale. But the
language in paragraph 3(c) is exceptionally broad, and there is nothing in the leases
suggesting that paragraph 3(c) is limited to pre-point-of-sale expenses. Further, if the
point of sale were the deciding factor in determining whether paragraph 3(c) applies,
appellants could choose to sell all of their production at the wellhead and thereby
unilaterally transform the royalty into a “market value at the well” royalty, which appellants
acknowledge would be contrary to the parties’ intent. In any event, the result of appellants’
proposed construction of paragraph 3(c)—freeing appellees of post-production, pre-point-
of-sale costs—is already achieved by paragraphs 3(a) and 3(b) of the leases, which
specify that the royalty is to be initially based on appellants’ gross proceeds (before
paragraph 3(c) is applied). See Bowden, 247 S.W.3d at 699 (stating that gross proceeds
9
We observe that, under the Sheppard and Crain Leases, the oil royalty is not the same as the gas
royalty. In particular, the oil royalty is defined as a percentage of the produced oil itself, with the lessor
having the option to take the “market value thereof” in cash, whereas the gas royalty is defined exclusively
in terms of its cash value—either “the market value at the wellhead” or gross proceeds, whichever is greater.
Therefore, at least in theory, the oil royalty may be taken in kind, but the gas royalty must be taken in cash.
Relatedly, the oil royalty, whether it is taken in kind or in cash, is to be “delivered . . . into the pipeline,”
which arguably means the valuation point for the oil royalty is necessarily “at the well” and all post-
production expenses are chargeable to the royalty owner, notwithstanding other contractual clauses hinting
otherwise. See Burlington Res. Oil & Gas Co. v. Tex. Crude Energy, 573 S.W.3d 198, 205 (Tex. 2019);
Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 135 (Tex. 1996); Heritage Res., Inc. v. NationsBank, 939
S.W.2d 118, 122 (Tex. 1996). On the other hand, as noted, the gas royalty is a percentage of either “the
market value at the wellhead” or gross proceeds, whichever is greater (though gross proceeds, as defined
by the case law, will always be greater than the market value at the well). Despite these differences, the
parties do not argue that the oil royalty should be treated any differently than the gas royalty for purposes
of the twenty-three stipulated issues. In any event, though the “into the pipeline” language controlled over
the “amount realized” provision in Burlington, the lease in that case did not involve any terms similar to
paragraph 3(c) of the Sheppard and Crain Leases.
24
means the amount the lessee actually receives, free of post-production costs). Again, if
we were to adopt appellants’ construction, paragraph 3(c) would be meaningless.
Importantly, the language of paragraph 3(c) differs significantly from the no-
deductions clause considered in Heritage. The Heritage lease defined the royalty as a
fraction of the “market value at the well” and stated that “there shall be no deductions
from the value of the Lessor’s royalty,” clearly indicating the parties’ intent to free the
lessor from any responsibility for post-production costs. 939 S.W.2d at 120. That clause,
though, gave no hint of an intent to require the addition of any sums to the market value
at the well in order to calculate the royalty. Moreover, unlike the Heritage clause,
paragraph 3(c) of the Sheppard and Crain Leases does not concern deductions made to
the royalty for post-production expenses; rather, it applies whenever a “reduction or
charge” for such expenses is “include[d]” in dispositions or sales contracts, and it imposes
an affirmative duty on appellants to add any such “reduction[s] or charge[s]” to the royalty
base.
It is true, as appellants argue, that the “Royalty Free of Costs” provision clearly
indicates the parties intended to prohibit deductions for post-production costs incurred by
appellants. The citations to Heritage and Judice in Addendum L underscore this. The
clause at issue in Heritage—which stated that there shall be no deductions from the
royalty for post-production expenses—was considered “surplusage” because it merely
restated the rule that royalties are generally not subject to production expenses. See 939
S.W.2d at 121. By citing Heritage and Judice, and by stating that the “Royalty Free of
Costs” provision is not mere surplusage, the parties exhibited their intent to allow the
royalty base to include value added by post-production costs and thereby exceed “at the
25
well” market value. But, crucially, this mere fact has no bearing on whether the base may
also exceed appellants’ gross proceeds. There is nothing about Addendum L that
modifies or contradicts paragraph 3(c), either explicitly or implicitly, nor is there anything
about it that prohibits the addition of sums to the royalty base so that the base exceeds
appellants’ gross proceeds.
Appellants emphasize the final clause of paragraph 3(c), which implies that the
purpose of the “shall be added” requirement is to ensure that “Lessor’s royalty” is
“never . . . chargeable” with post-production expenses. They argue that this language
suggests the parties merely intended to prohibit deductions from a previously-defined
royalty, as in Heritage. That may be persuasive, if the clause were viewed alone. But we
may not view these words alone. See J.M. Davidson, Inc., 128 S.W.3d at 229. Rather,
we must view them in light of the entire agreement, including the immediately preceding
“shall be added” clause, which unambiguously requires additions of certain amounts to
the royalty base, without limitation to gross proceeds or any other prescribed maximum.
The “never . . . chargeable” language in the final clause of paragraph 3(c), like the
“Royalty Free of Costs” addendum, does not modify or contradict the “shall be added”
clause. If the parties intended to limit additions so that the total royalty base could never
exceed gross proceeds, they could have easily said so in certain terms, but they did not.
Indeed, the words immediately following “never . . . chargeable” in paragraph 3(c)
suggest a contrary intent. They state the royalty is not to be chargeable either “directly or
indirectly” with post-production costs or expenses (emphasis added). Addendum L also
contains this language. A “direct” charge against the royalty would simply be a pro rata
deduction from the producer’s gross proceeds to account for the producer’s post-
26
production costs. But what is an “indirect” charge against the royalty? Appellants suggest
that an “indirect” deduction of an expense occurs whenever a producer “net[s] out any of
their post-production costs from a sales price.” This interpretation is not sensible
considering the context. Paragraph 3(c) applies whenever a “disposition, contract or sale
. . . include[s] any reduction or charge” for post-production expenses. A “disposition,
contract or sale” contemplates the conveyance of minerals from a producer to a
downstream purchaser in exchange for compensation; thus, if such a transaction
“include[s]” a “reduction or charge” for post-production expenses, that “reduction or
charge” could conceivably be either (1) an increase in the sales price to account for
expenses already incurred by the producer, or (2) a decrease in the sales price to account
for expenses incurred (or anticipated to be incurred) by the purchaser. But if “reduction
or charge” referred to an increase in the sales price, then appellants’ gross proceeds in
that situation would increase as well, and there would be no reason to add any such
amounts to gross proceeds in order to ensure the royalty is cost-free. Such a construction
would lead to a windfall for the lessor, who would be entitled to a royalty on the same
expenses twice. A logical solution to this conundrum is that appellants’ interpretation of
“indirect” is misguided and does not reflect the parties’ intent—an “indirect” charge to the
royalty has nothing to do with expenses incurred by the producer. Instead, an “indirect”
charge to the royalty must have been intended to refer to the situation when a downstream
sales price is reduced to account for costs incurred or anticipated by the purchaser. On
appeal, appellants suggest no other explanation for why this “direct or indirect” language
would have been included twice in the lease’s royalty provisions, other than to show the
parties’ intent to base the royalty on more than mere gross proceeds.
27
Appellants contend that this interpretation would not make economic sense. See
Frost Nat’l Bank v. L & F Distribs., Ltd., 165 S.W.3d 310, 312 (Tex. 2005) (per curiam)
(noting that courts construe contracts “from a utilitarian standpoint bearing in mind the
particular business activity sought to be served” and “will avoid when possible and proper
a construction which is unreasonable, inequitable, and oppressive”). We disagree. The
royalty is paid as a fraction of the value of the oil and gas produced from the leases, but
that value increases as the minerals are processed, fractionated, and transported to the
market center, where they are finally put on the open market and prices are standardized.
It is not unreasonable to construe the leases as ensuring the lessors’ royalty is based on
the standardized value of the gas at the market center, and that is effectively what the
Sheppard and Crain Leases accomplish. The value of the minerals at the market center
will likely be more than the gross proceeds received by the producer—how much more
depends on the terms of the contracts between the producers and the downstream
purchasers. But as appellees argue, the purpose of the provisions at issue in this case is
to insulate appellees from the effects of appellants’ decisions regarding when, where, and
for what price the oil and gas is sold between the time it is produced and the time it is
marketable. The unique provisions of the Sheppard and Crain Leases make economic
sense for both parties because they effectively allow appellees to collect a royalty based
on standardized market prices while appellants remain able to freely make those
decisions.
Appellees point to Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, 291 Fed. App’x
626 (5th Cir. 2008) (per curiam, not designated for publication), as an example of a case
where the parties bargained for a royalty valuation point downstream of the producer’s
28
point of sale. There, four leases required Kerr-McGee to pay a royalty on “all plant
products, or revenue derived therefrom, attributable to gas produced by [Kerr-McGee]
from the leased premises.” Id. at 628. Two of the leases at issue stated that the lessors’
royalty on NGLs “shall never bear, either directly or indirectly, any part of the costs or
expenses of production, gathering, dehydration, compression, transportation (except
transportation by truck), manufacture, processing, treatment or marketing of the oil or gas
from the leased premises . . . .” Id. Enterprise, a third-party purchaser, contracted with
Kerr-McGee to process and fractionate gas from the leases, with title transferring after
the gas was processed but before it was transported to Enterprise’s plant for fractionation.
Id. The price for the gas was set at “80% of Enterprise’s ‘Net Proceeds,’ which consist of
the total value of the fractionated [NGLs] (based on price averages) minus product
marketing, transporting, and fractionating costs.” Id. The lessors sued Kerr-McGee when
it discovered that it was calculating royalties based on the revenue it actually received
from Enterprise, which “includes deductions for Enterprise’s transportation and
fractionation costs,” rather than on the total revenue generated by the NGLs, exclusive of
costs. Id. at 629. The Fifth Circuit agreed with the lessors’ interpretation of the lease and
concluded that such deductions were impermissible. Id. at 633–35.
The Yturria court noted that the royalty provision at issue—which based the royalty
on “all . . . revenue derived” from NGLs “attributable to gas produced” on the leases—
resulted from an amendment to the lease which was negotiated following a previous
lawsuit between the parties. Id. at 633. The amended provision replaced language stating
that the royalty was based on “revenue . . . received by [Kerr-McGee].” Id. The old
language “allowed Kerr–McGee, through its affiliate processor, to receive the full benefit
29
of the [NGLs] while at the same time decreasing the amount it owed Lessors as a royalty,”
and “[t]he amendments were designed to address this problem.” Id. at 634. Although the
specific circumstances regarding the formation of the lease in Yturria are not present
here, the terms are broadly similar to those contained in the Sheppard and Crain Leases
in that they do not restrict the royalty base to amounts actually received by the producer.
Yturria demonstrates that there is nothing unreasonable, inequitable, or oppressive about
an oil and gas producer agreeing to base royalty payments on more than just the gross
proceeds it receives in a sale.
With the above considerations in mind, we conclude that the Sheppard and Crain
Leases provide generally for a “proceeds-plus” royalty, which in most circumstances is
based on an approximation of the value of production at the market center after the
individual hydrocarbons have been separated and are ready to be sold for standardized
index prices on the open market.
That said, we must still review the individual issues set forth in the stipulation to
determine whether paragraph 3(c) applies. This requires an examination of the sales
contracts which the parties have stipulated exemplify those issues. 10 The twenty-three
issues each concern a different aspect of an oil and gas sale—most of which are
enshrined in a written contract—which appellees allege represents a “reduction or
charge” that was required to be added to gross proceeds under paragraph 3(c). The
10
In contesting summary judgment, appellants enumerate only one issue with two sub-issues. And
at the summary judgment hearing, appellees’ counsel impressed upon the trial court that the case is “really
quite simple” because “[e]ach issue presents the same exact thing, does the lease require that the reduction
or charge contained in these exemplar contracts . . . be added back to the defendants' gross proceeds. . . .
So it’s not really 23 distinct issues, it’s just 23 issues asking the Court the same question.” Unfortunately,
as any reader of this opinion will attest, the case is by no means simple. The Sheppard and Crain Leases
differ slightly but significantly in their terms. The parties make varying arguments for each of the twenty-
three issues, and so each must be analyzed separately to determine whether paragraph 3(c) applies.
30
issues may be categorized as follows: (1) price adjustments of a fixed amount with a
stated purpose; (2) price adjustments of a fixed amount without a stated purpose; (3) price
adjustments based on the actual costs incurred by a third-party purchaser; (4)
adjustments for volumes of gas used by the producer for its own operations and never
sold to a third party; (5) adjustments for volumes of production deemed to be lost or
unaccounted-for by third parties; and (6) value retained by the producer as a result of the
application of contractually fixed recovery factors.
1. Adjustment of Fixed Amount With Stated Purpose
Stipulated Issues 2, 7, 8, 10, 11, and 13 concern sales contracts under which the
price for oil and gas is calculated in part by deducting a fixed sum from a published price,
and the contract states what that fixed sum is intended to account for.
One of the exemplar contracts for Issue 2 is a 2011 agreement between
GeoSouthern and Enterprise for the sale of crude oil and/or condensate. The price per
barrel is set as a weighted average of published index prices “minus $18.00 gathering
and handling, including rail car transportation” per barrel. This is the issue which was
raised in appellees’ original petition.
Issues 7 and 13 are exemplified by a 2010 “Gas Processing Agreement” under
which ETC Texas Pipeline, Ltd. (ETC) agreed to process gas produced by Petrohawk
and to purchase 100% of the resulting NGLs and 50% of any drip condensate “attributable
to [Petrohawk]’s gas.” The price for both was set as a published index price “less [ETC’s]
actual transportation and fractionation (T&F) cost, less retention gallons (if any) required
to secure T&F services, and less a marketing fee of one quarter cent ($0.0025) per
gallon.” Issue 7 concerns the marketing fee as it relates to the sale of NGLs; Issue 13
31
concerns the marketing fee as it relates to the sale of condensate.
For Issue 8, the exemplar contract is a 2012 “Gas Services Agreement” under
which Copano agreed to gather and process gas produced by GeoSouthern, to purchase
the resulting NGLs, and to return the remaining residue gas. The price for the NGLs was
set at a published index price “less” a “T&F fee” of “$0.104 per gallon.”
Stipulated Issue 10 concerns the sale of NGLs from GeoSouthern to Martin Gas
Sales under various sales orders. The orders set the price as an average of published
index prices “less” a “fixed fee” determined by a formula. The contract states: “Fixed fee
includes pipeline fee, fixed frac fee, truck transportation, terminalling fee and margins.”
In Issue 11, the exemplar contract is a 2012 “Gas Processing Agreement” between
Enterprise and Petrohawk. The contract provides that Enterprise shall pay Petrohawk on
a monthly basis “ninety-two percent (92%) of the Producer Plant Products Value,” which
is defined as the (1) the volume of the plant products attributable to Petrohawk, times (2)
a published index price “minus the T&F Fee” applicable for that month.
There is no dispute that these constitute “disposition[s], contract[s] or sale[s] of oil
or gas” under paragraph 3(c) of the leases. We agree with appellees that the fixed
deductions are properly considered “reduction[s] or charge[s]” “include[d]” in such
“contract[s] or sale[s]” because they reduce the amount that would otherwise be payable
to appellants. And the contracts expressly provide that the fixed amounts specified in
these contracts are “for the expenses or costs” of transportation, processing, and
marketing. Appellants argue that these amounts do not represent appellant’s expenses
for such post-production activities, but as noted, the leases do not specify that the
expenses or costs must necessarily be incurred or expended by appellants in order for
32
paragraph 3(c) clause to apply. Thus, we conclude appellants were required to add these
amounts to their gross proceeds in order to calculate appellees’ royalties. The trial court
did not err in granting summary judgment to appellees on these issues.
2. Adjustment of Fixed Amount Without Stated Purpose
Issues 1, 3, 6, 15, 16, 17, 18, and 19 in the stipulation concern sales contracts
under which the price for oil and gas is calculated in part by deducting a fixed sum from
a published price, but without stating what that fixed sum is intended to represent or
account for.
One of the exemplar contracts for Issue 1 is a 2013 agreement between Petrohawk
and ExxonMobil for the sale of gas condensate and crude oil. As to price, the agreement
stated that “[a] differential of -7.1500 US dollars . . . will be applied to” a formula based on
published index prices. Delivery of oil was specified to take place in Houston at the
purchaser’s designated facility, but as to condensate, the purchaser also had the option
to take delivery at Point Comfort, Texas, and if that option is taken, the differential is
increased to “-7.500 US dollars” per barrel.
The exemplar contract for Issue 3 is a 2012 agreement for the sale of crude oil and
condensate from appellant GeoSouthern to Enterprise Crude Oil LLC (Enterprise). An
exhibit to the contract indicates that the applicable price is a published index price “plus
amount shown per barrel.” The “amount shown,” which appellees contend is a deduction
which must be added to gross proceeds, is -$9.15 or -$8.15 for the leases at issue here.
Issue 6 concerns the sale of NGLs under a similar pricing scheme. The exemplar
contract is a 2012 “Gas Gathering and Processing Agreement” under which Copano
Processing, L.P. (Copano) agreed to gather and process gas produced by Petrohawk, to
33
purchase the liquefiable hydrocarbons resulting from processing, and to return residue
gas to Petrohawk. The purchase price for the NGLs was set at a published index price
“less $0.15 per gallon” for normal butane and natural gasoline and “less $0.12 per gallon”
for isobutane.
Stipulated Issue 15 concerns an arrangement under which ETC agreed to gather
and sell drip condensate delivered by Petrohawk. The exemplar contract, a 2012
“Individual Transaction Confirmation,” states that ETC will pay Petrohawk its “net cash
proceeds” from the sale of the condensate, “less any and all costs associated with
handling and transporting the Condensate to market,” including but not limited to
“trucking, stabilization, and any other transportation and fractionation fees, less a $0.03
per gallon fee.” Appellees argued that both the actual costs and the fixed fee constitute
charges to which paragraph 3(c) of the leases applies.
Issues 16 and 17 concern appellants’ sale of residue gas or “dry gas”—i.e.,
methane gas returned to the producer after all liquids have been condensed and
impurities removed by the processor. As to price, the exemplar contract provides that
Houston Pipe Line Company shall pay “ninety-eight percent (98%)” of a published index
price “LESS $0.105” per MMBtu (millions of British Thermal Units). Issue 16 is whether
the “$0.105” per MMBtu is a deduction which must be added to gross proceeds; Issue 17
is whether the two percent reduction to the index price must be added.
Issues 18 and 19 refer to a 2010 “Gas Purchase and Sale Agreement” between
Copano and GeoSouthern. The agreement contains a complicated pricing scheme which
is initially based on “ninety-eight percent (98%) of [a published index price] minus forty-
five cents ($0.45) for each MMBtu.” Issue 18 is whether the forty-five-cent deduction must
34
be added to the royalty base under paragraph 3(c) of the leases; Issue 19 is whether the
two percent reduction to the index price must be added.
With the exception of the actual-cost deduction discussed in Issue 15, there is no
dispute that all of the fixed-dollar-amount and percentage deductions from published
index prices constitute “reduction[s] or charge[s]” “include[d]” in a “disposition, contract or
sale of oil and gas.” However, unlike the contracts discussed in the previous category of
issues, these contracts do not specify the purpose for the reductions. Paragraph 3(c)
applies only if the specific charge is “for the expenses or costs of production, treatment,
transportation, manufacturing, process[ing] or marketing of the oil or gas.” Appellees have
not pointed to any evidence establishing that the purpose for these reductions is one of
those specifically identified in paragraph 3(c). Accordingly, appellants were not required
to add these amounts to their gross proceeds before calculating the royalty. The trial court
erred in granting summary judgment to appellants on Stipulated Issues 1, 3, 6, 16, 17,
18, and 19. It also erred in granting summary judgment as to the three-cent-per-gallon
fee discussed in Issue 15.
3. Adjustment Based on Processor’s Actual Costs
Issues 4, 9, 12, and 15 concern sales agreements under which the purchaser’s
actual costs for post-production expenses are deducted from a published index price in
order to determine the applicable sales price.
The exemplar contract for Issue 4 is for the 2013 sale of crude oil from
GeoSouthern to Petrohawk, to be delivered into a specific pipeline, for a price based on
a weighted average of sales “less transport, terminal and marketing costs.”
For Issues 9 and 12, the exemplar contract is the same 2010 “Gas Processing
35
Agreement” between ETC and Petrohawk considered in Issues 7 and 13. These issues
concern the deduction made to the sales price for ETC’s “actual transportation and
fractionation (T&F) cost.” Issue 9 relates to the sale of NGLs and Issue 12 relates to the
sale of drip condensate.
As noted, Issue 15 involves a contract where the processor’s actual costs for
“handling and transporting,” including “trucking, stabilization, and any other transportation
and fractionation fees,” are deducted from the sales price.
These adjustments are all deductions from the downstream sales price which are
intended to reflect the actual transportation, processing, and marketing costs of the third-
party purchaser. Thus, these costs are required to be added to gross proceeds under
paragraph 3(c) of the Sheppard and Crain Leases. Appellants contend that addition of
these sums was not required because: (1) appellants did not “directly or indirectly” incur
the costs at issue, and (2) the deduction was not made “from [appellees’] royalty.” We
reject these arguments for the reasons previously elucidated. The leases do not require
that appellants directly incur an expense in order for the “shall be added” clause to apply.
They do not merely prohibit deductions “from [appellee’s] royalty” for such costs, but also
mandate additions to the royalty base for post-production costs incurred or anticipated by
the third-party purchaser. The trial court did not err in granting summary judgment to
appellees on these issues.
4. Adjustments For Unit Fuel/Lease Fuel
The remaining stipulated issues are qualitatively different from those already
considered in that they do not involve the deduction of post-production costs (either
incurred by appellants or by third-party purchasers) from the royalty base.
36
Issues 20 and 21 concern whether appellees are entitled to royalties “on actual
volumes of gas used by [appellants] for unit fuel” or “lease fuel”—i.e, gas used by
appellants to fuel their own operations, either on the leases themselves or on other leases
within a pooled unit, and never sold to a third party. Appellees argue that the use of gas
for appellants’ own operations constitutes a “disposition” which “result[s] in a reduction or
charge” in appellants’ gross proceeds because the practice “reduce[s] the volume of
hydrocarbons that are paid for.” Appellees argue that this “reduction” is therefore subject
to the “shall be added” clause in paragraph 3(c) of the leases. 11
On the other hand, appellants note that the leases do not provide any mechanism
for valuing the gas used as unit fuel or lease fuel, and they argue this indicates the parties
did not intend to have any such values added to gross proceeds. Appellants further argue
that the leases specifically allow them to deduct volumes used for operations before
calculating the royalty. They note that paragraph 4 of the subject leases permits the
lessee to “pool or combine the acreage covered by the lease” with other land, and it
states:
For the purpose of computing the royalties to which owners . . . shall be
entitled on production of oil and gas, or either of them, from the pooled unit,
there shall be allocated to the land covered by this lease and included in
11
Appellants argue that appellees abandoned these issues. They note that appellees provided the
trial court with a proposed judgment that included rulings in favor of appellees on all other issues but did
not include any rulings on Stipulated Issues 20 or 21. (The trial court eventually signed appellees’ proposed
judgment, but only after adding handwritten rulings in appellees’ favor on Issues 20 and 21.) Appellees’
proposed judgment was accompanied by a letter from their counsel stating: “In the interests of simplifying
the issues and limiting complications in the severed damages phase of this case, Plaintiffs are withdrawing
their requests for relief on issues 20 and 21 in the [Stipulation].” Appellants neglect to mention that their
counsel replied with his own letter to the court in which he objected to appellees’ “attempt to unilaterally
withdraw these two issues from consideration” as “procedurally improper and in conflict with the parties’
joint submission of disputed issues in this case.” Appellants’ counsel requested that the court “keep all
twenty-four [sic] Disputed Issues under consideration.” Appellants cannot now complain that the trial court
granted that request. See Tittizer v. Union Gas Corp., 171 S.W.3d 857, 862 (Tex. 2005) (per curiam) (“[A]
party cannot complain on appeal that the trial court took a specific action that the complaining party
requested.”). We conclude the issues were not abandoned.
37
said unit (or to each separate tract within the unit if this lease covers
separate tracts within the unit) a pro rata portion of the oil and gas, or either
of them, produced from the pooled unit after deducting that used for
operations on the pooled unit.
(Emphasis added.) The Sheppard Lease also explicitly states, in paragraph 3(d), the
following: “Lessee shall have free use of oil, gas, and water from said land, except water
from Lessor’s wells, tanks, creeks, and watering places for all operations hereunder, and
the royalty on oil and gas shall be computed after deducting any so used.”
We cannot conclude that appellants’ retention of gas for use in their own
operations constitutes a “reduction or charge” that is “include[d]” in a “disposition” so as
to implicate paragraph 3(c). The fact that “disposition” appears in paragraph 3(c) in a list
with “contract” and “sales” signifies that “disposition” was meant to refer to a transfer to a
third party, not a unilateral disposal or use by the producer. “Disposition” is the act of
disposing; to “dispose” of something means to get rid of it or to transfer it to the control of
another. MERRIAM-WEBSTER ONLINE DICTIONARY, https://www.merriam-webster.com/
dictionary/disposition (last visited June 19, 2020); id., https://www.merriam-webster.com/
dictionary/dispose (last visited June 19, 2020). In light of this common definition as well
as the lease language cited by appellants, which indicates an intent to exclude gas used
for appellants’ operations from the royalty base, it would be unreasonable to construe the
word “disposition” as including the use of gas for fueling appellants’ operations on the
subject leases or on the pooled unit which includes those leases.
We conclude that paragraph 3(c) does not require the addition to gross proceeds
of any amounts attributable to appellants’ use of gas for unit fuel or lease fuel. Therefore,
the trial court erred in granting summary judgment to appellees on Stipulated Issues 20
and 21.
38
5. Adjustment for Production Retained or Lost by Third Parties
Stipulated Issues 14, 22, and 23 concern whether royalty is owed on gas which is
produced on the leases and sold by appellants to third parties, but then retained or lost
by the third-party purchaser.
The exemplar contracts for Issue 14 include the 2010 “Gas Processing Agreement”
between ETC and Petrohawk. Section 7.7 of that agreement states that the “quantity” of
a particular plant product is determined in part by multiplying the deemed volume of gas
attributable to that product by a “Component Recovery Factor,” ranging from 0.75 to 0.98
depending on the specific product. Essentially, the agreement provides that ETC is only
required to pay Petrohawk for a certain percentage of the products which are attributable
to Petrohawk’s gas. Appellees argue that this “volumetric reduction” constitutes a
“reduction or charge” subject to paragraph 3(c) of the leases.
Issues 22 and 23 concern lost and unaccounted-for gas. The exemplar contracts
include a 2012 “Gas Processing Agreement” under which Petrohawk agreed to sell to
Enterprise, among other things, “the right to consume” gas as “FL&U” (“flared, vented,
and/or lost and unaccounted for”). Under the agreement, title to plant products passes to
Enterprise “when the same are removed from the Gas stream and/or become identifiable
Plant Products,” whereas title to lost and unaccounted-for gas passes as soon as it is
delivered to Enterprise.
Appellees contend that, whenever a third-party processor such as Enterprise loses
gas or uses gas for its own operations in this way, that constitutes a “disposition” which
“results in a reduction or charge related to the costs and expenses of the services those
third-parties perform” because it reduces the volume of gas upon which the producer is
39
entitled to payment. Issue 22 argues that such a reduction is subject to paragraph 3(c) of
the Sheppard Lease and Issue 23 argues that it is subject to the equivalent provision in
the Crain Lease.
We disagree. Unlike Issues 20 and 21, these issues involve specific contractual
provisions which operate, ultimately, to reduce the gross proceeds to which appellants
would otherwise be entitled. And the volumetric reduction is arguably a “reduction or
charge” that is “include[d]” in a “disposition, contract or sale” under paragraph 3(c).
However, appellees’ summary judgment motion pointed to no evidence indicating that
this type of volumetric reduction is “for the expenses or costs of production, treatment,
transportation, manufacturing, process[ing] or marketing of the oil or gas” as required by
paragraph 3(c). Therefore, these volumetric reductions are not charges which must be
added to the royalty base. The trial court erred in granting summary judgment to appellees
on Stipulated Issues 14, 22, and 23.
6. Excess Value Resulting From Application of Contractually Fixed Recovery
Factors
Issue 5 as listed in the stipulation concerns a complex arrangement under which
appellants are compensated by downstream purchasers based on the gas’s heating value
rather than its volume in certain situations.
Under the exemplar 2012 “Gas Services Agreement” between GeoSouthern and
Copano, there is a provision conclusively deeming each different liquid plant product,
such as ethane or propane, to have been “recovered” by the processor at certain
percentages. According to appellants, these “contractual fixed recovery factors” are
agreed to in advance “for ease of accounting, and to provide certainty” to the parties.
Appellees claimed in their summary judgment motion that the value of the “excess
40
liquids”—i.e., the amount by which the volume of each hydrocarbon liquid actually
recovered by the processor exceeds the deemed recovery percentage—serves as a form
of “compensation to the processor for its processing services and constitutes an in-kind
payment” which should be added to the royalty base under paragraph 3(c) of the leases.
Appellants note that, according to deposition testimony from Whyburn, Devon’s
accountant, appellants are compensated by Copano and other processors for the “excess
liquids” by the processor’s increasing the amount of residue gas appellants are entitled
to receive back after the liquids have been extracted. However, the extra gas is measured
in BTUs rather than cubic feet, and the relative market price for gas fluctuates depending
on whether it is measured in heating value (BTUs) or volume (cubic feet). 12 Appellees
argue that the difference between the two measures represents additional compensation
flowing from processor to producer and must be added to gross proceeds under lease
paragraph 3(c).
We cannot conclude that paragraph 3(c) is applicable in this situation. In their
summary judgment motion, appellees did not contend that the difference between the
heating-value-based price and volume-based price is intended to represent or account
for expenses of the type listed in paragraph 3(c). Thus, even assuming that the excess
value retained by appellants as a result of applying the contractually fixed recovery factors
is a “reduction or charge,” we cannot conclude that such a “reduction or charge” is “for
the expenses or costs of production, treatment, transportation, manufacturing,
process[ing] or marketing of the oil or gas” as required by paragraph 3(c). The trial court
12
At the summary judgment hearing, appellees’ counsel also argued that BTUs in gas form are
worth less than BTUs in NGL form.
41
therefore erred by granting summary judgment to appellees on Stipulated Issue 5.
IV. CONCLUSION
The Texas Supreme Court has lamented the “considerable time, money, and
heartache” which is expended due to the use of “cryptic language” in oil and gas leases.
Burlington, 573 S.W.3d at 210 n.10. This case epitomizes the problem. Appellants urge
that the inclusion of “gross proceeds” language in the Sheppard and Crain Leases
necessarily controls over all others and mandates a result similar to that which obtained
in Hyder, but paragraph 3(c) of the leases is highly unique and sets this case apart. It
shows that the parties intended to allow the royalty base not only to exceed the market
value at the well, but also to exceed appellants’ gross proceeds. That said, it is difficult to
fathom that the parties, when executing the leases, shared a mutual common conception
of what was to be covered by paragraph 3(c). We can only speculate as to how many
dollars and hours would have been saved had the parties drafted the leases, in Justice
Blacklock’s words, “to say exactly what [they] intend[ed], without resort to industry jargon,
outdated legalese, or tenuous assumptions about how judges will interpret industry jargon
or outdated legalese.” Id.
For the reasons set forth herein, we reverse the trial court’s judgment on Stipulated
Issues 1, 3, 5, 6, 14, 16, 17, 18, 19, 20, 21, 22, and 23. We also reverse the trial court’s
judgment on Stipulated Issue 15 insofar as it concerns the fixed fee of three cents per
gallon on the sale of drip condensate. We render judgment in favor of appellants on these
42
issues. The remainder of the trial court’s judgment is affirmed.
DORI CONTRERAS
Chief Justice
Delivered and filed the
22nd day of October, 2020.
43
APPENDIX
1. Where dispositions, contracts, or sales of oil provide for payment to
Lessee based upon a Published Price[ 13] per barrel minus a fixed dollar
amount, whether such fixed dollar amount constitutes a Contractual
Charge.[ 14]
Example Contracts: Petrohawk/ExxonMobil oil sales contract;
Petrohawk/Exxon amendment; GeoSouthern/Flint Hills oil
purchase agreement; GeoSouthern/Genesis Crude Oil
agreement; Petrohawk/Shell oil purchase contract;
Petrohawk/Shell oil purchase contract.
2. Plaintiffs’ version: Where dispositions, contracts, or sales of oil
provide for payment to Lessee based upon a Published Price per barrel
minus a fixed dollar amount for the cost of production, treatment,
processing, transportation, manufacturing, marketing, or terminalling,
whether such fixed dollar amount constitutes a Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of oil provide
for payment to Lessee based upon a Published Price per barrel minus a
fixed dollar amount for the cost of production, treatment, processing,
transportation, manufacturing, marketing, or terminalling downstream of
the Lessee’s point of sale, whether such fixed dollar amount constitutes a
Contractual Charge.
Example Contracts: GeoSouthern/Enterprise oil sales
contract; GeoSouthern/Enterprise oil sales contract and
amendments; Petrohawk/Shell oil sales agreement.
3. Under the following contracts, which provide for payment to Lessee
based upon a Published Price per barrel minus a dollar amount, whether
such dollar amount constitutes a Contractual Charge.
Example Contracts: GeoSouthern/Enterprise oil amended
sales contract; Enterprise contract amendments.
4. Plaintiffs’ version: Where dispositions, contracts, or sales of oil
provide for payment to Lessee based upon a weighted average sales price
per barrel minus the actual cost of production, treatment, processing,
transportation, terminalling, or marketing, whether such fixed dollar amount
13
The stipulation defined “Published Price” as “prices generally published by commercial market
services providers relative to sales of hydrocarbons at identified industry or market centers (i.e., OPIS Mont
Belvieu. Platts’ Inside FERC’s Gas Market Report, Houston Ship Channel, etc.).”
14
A “Contractual Charge” is defined in the stipulation as one that appellants were required to add
to gross proceeds in order to calculate the royalty under paragraph 3(c) of the leases.
44
constitutes a Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of oil provide
for payment to Lessee based upon a Published Price per barrel minus a
fixed dollar amount for the cost of production, treatment, processing,
transportation, manufacturing, marketing, or terminalling downstream of
the Lessee’s point of sale, whether such fixed dollar amount constitutes a
Contractual Charge.
Example Contract: GeoSouthern/Petrohawk oil sales
contract.
5. Where a Lessee sells natural gas liquids to a processor and the
volume of each natural gas liquid component on which Lessee is paid is
calculated using contractually fixed plant recovery factors, whether the
value of the Excess Liquids[ 15] constitutes a Contractual Charge.
Example Contract: Copano 2012 Gas Services Agreement.
6. Where dispositions, contracts, or sales of natural gas liquids to a
processor provide for payment to Lessee based upon a Published Price per
gallon minus a fixed dollar amount, whether such fixed dollar amount
constitutes a Contractual Charge.
Example Contract: Petrohawk/Copano Gas Gathering &
Processing Agreement.
7. Plaintiffs’ version: Where dispositions, contracts, or sales of natural
gas liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus a fixed dollar amount for marketing,
whether such fixed dollar amount constitutes a Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of natural gas
liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus a fixed dollar amount for marketing
downstream of the Lessee’s point of sale, whether such fixed dollar
amount constitutes a Contractual Charge.
Example Contract: Petrohawk/ETC Gas Processing
Agreement.
15
“Excess liquids” is defined in the stipulation as:
the difference between (a) the natural gas liquids actually recovered by a processor from
the gas delivered to the plant by Lessee, and (b) the sum of the contractually fixed
component recoveries of natural gas liquids attributed to the gas delivered to the plant by
Lessee and the MMBtus of residue gas credited to Lessee in place of the natural gas liquids
recovered by the processor in excess of the fixed recovery factors.
45
8. Plaintiffs’ version: Where dispositions, contracts, or sales of natural
gas liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus a fixed dollar amount for transportation
and fractionation (“T&F”), whether such fixed dollar amount constitutes a
Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of natural gas
liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus a fixed dollar amount for transportation
and fractionation (“T&F”) downstream of the Lessee’s point of sale,
whether such fixed dollar amount constitutes a Contractual Charge.
Example Contracts: GeoSouthern/Copano Gas Gathering &
Processing Agreement; GeoSouthern/Enterprise Gas
Processing Agreement.
9. Plaintiffs’ version: Where dispositions, contracts, or sales of natural
gas liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus the actual cost of transportation and
fractionation (“T&F”), whether such fixed dollar amount constitutes a
Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of natural gas
liquids to a processor provide for payment to Lessee based upon a
Published Price per gallon minus the actual cost of transportation and
fractionation (“T&F”) downstream of the Lessee’s point of sale, whether
such fixed dollar amount constitutes a Contractual Charge.
Example Contract: Petrohawk/ETC Gas Processing
Agreement.
10. Plaintiffs’ version: Where dispositions, contracts, or sales of natural
gas liquid hydrocarbons at central delivery points provide for payment to
Lessee based upon a Published Price per gallon minus a fixed dollar
amount identified as being for the cost of production, treatment, processing,
transportation, manufacturing, marketing, or terminalling, whether such
fixed dollar amount constitutes a Contractual Charge.
Defendants’ version: Where dispositions, contracts, or sales of natural gas
liquid hydrocarbons at central delivery points provide for payment to Lessee
based upon a Published Price per gallon minus a fixed dollar amount
identified as being for the cost of production, treatment, processing,
transportation, manufacturing, marketing, or terminalling downstream of
the Lessee’s point of sale, whether such fixed dollar amount constitutes a
Contractual Charge.
Example Contracts: GeoSouthern/Martin contract;
GeoSouthern/Texon Purchase Agreement
46
11. Plaintiffs’ version: Where a Lessee sells natural gas liquids to a
processor who pays Lessee less than 100% of the calculated natural gas
liquids’ value, whether the value retained by the processor constitutes a
Contractual Charge.
Defendants’ version: Where a Lessee sells natural gas liquids at the point
specified in the contract to a processor who pays Lessee a price based
upon less than 100% of a calculated natural gas liquids’ value (i.e., 92% of
such calculated natural gas liquids value), whether the percentage retained
by the processor (i.e., 8%) constitutes a Contractual Charge.
Example Contract: GeoSouthern/Enterprise Gas Processing
Agreement.
12. Plaintiffs’ version: Where a Lessee sells drip condensate to a
processor based upon a weighted average sales price minus a dollar
amount for the actual cost of transportation and fractionation (“T&F”),
whether such dollar amount constitutes a Contractual Charge.
Defendants’ version: Where a Lessee sells drip condensate to a
processor based upon a weighted average sales price minus a dollar
amount for the processor’s actual cost of transportation and fractionation
(“T&F”) downstream of the Lessee’s point of sale, whether such dollar
amount constitutes a Contractual Charge.
Example Contracts: Petrohawk/ETC 2010 Gas Processing
Agreement, §7.7; Petrohawk/ETC 2010 Gathering & Natural
Gas Services Agreement and ITC.
13. Plaintiffs’ version: Where a Lessee sells drip condensate to a
processor based upon a weighted average sales price minus a fixed dollar
amount for marketing, whether such dollar amount constitutes a Contractual
Charge.
Defendants’ version: Where a Lessee sells drip condensate to a
processor based upon a weighted average sales price minus a dollar
amount for the actual cost of transportation and fractionation (“T&F”)
downstream of the Lessee’s point of sale, whether such dollar amount
constitutes a Contractual Charge.
Example Contracts: Petrohawk/ETC 2010 Gas Processing
Agreement, §7.7; Petrohawk/ETC 2010 Gathering & Natural
Gas Services Agreement and ITC.
14. Where a natural gas transportation or processing agreement allows
a transporter or processor to retain some or all drip condensate without
purchasing it from the Lessee, whether the volume of drip condensate
retained by the transporter or processor constitutes a Contractual Charge.
47
Example Contracts: ETC 2010 Gas Processing Agreement,
§7.7; Petrohawk/ETC 2010 Gathering & Natural Gas Services
Agreement and ITC; Geo/ETC Gath. & Proc. Agmt.; Geo/ETC
Gath. & Proc. Agmt. ITC.
15. Plaintiffs’ version: Where a Gatherer pays Lessee the cash
proceeds received from the sale of Lessee’s drip condensate minus a dollar
amount for the actual costs associated with handling and transporting the
condensate to market and a fixed fee per gallon, whether such dollar
amount and fixed fee constitute a Contractual Charge.
Defendants’ version: Where a Lessee sells drip condensate to a gatherer
and receives the cash proceeds from the gatherer’s downstream sale of the
condensate minus a dollar amount for the gatherer’s actual costs
associated with handling and transporting the condensate and a fixed fee
per gallon, whether such dollar amount and fixed fee constitute a
Contractual Charge.
Example Contracts: 2012 Individual Transaction Confirmation
to Petrohawk-ETC 2010 Gas Gathering Agreement 9116-102,
Condensate, “Net Cash Proceeds”.
16. Where residue gas is sold by a Lessee for a stated percentage that
is less than 100% of a Published Price minus a fixed dollar amount (i.e.,
98% of HSC Gas Daily Midpoint Price less $0.105 per MMBtu), whether that
fixed dollar amount constitutes a Contractual Charge.
Example Contract: Houston Pipeline/Petrohawk Energy Corp.
Contract
17. Where residue gas is sold by a Lessee for a stated percentage that
is less than 100% of a Published Price minus a fixed dollar amount (i.e.,
98% of HSC Gas Daily Midpoint Price less $0.105 per MMBtu), whether the
percentage adjustment to the Published Price constitutes a Contractual
Charge.
Example Contract: Houston Pipeline/Petrohawk Energy Corp.
Contract
18. Under the 2010 Copano Gas Purchase And Sale Agreement, where
gas is sold by the Lessee at specified Point(s) of Delivery (i.e., at the tailgate
of the Central Delivery Point) for a calculated value for the constituent
natural gas liquids plus less than 100% of a Published Price minus a fixed
dollar amount (i.e., 98% IF HSC Index minus $0.45 per MMBtu) for the
anticipated residue gas, whether such fixed dollar amount constitutes a
Contractual Charge.
Example Contract: 2010 Copano Gas Purchase and Sale
48
Agreement
19. Under the 2010 Copano Gas Purchase And Sale Agreement, where
gas is sold by the Lessee at specified Point(s) of Delivery (i.e., at the tailgate
of the Central Delivery Point) for a calculated value for the constituent
natural gas liquids plus less than 100% of a Published Price minus a fixed
dollar amount (i.e., 98% IF HSC Index minus $0.45 per MMBtu) for the
anticipated residue gas, whether the percentage adjustment to the
Published Price constitutes a Contractual Charge.
Example Contract: 2010 Copano Gas Purchase and Sale
Agreement
20. Whether Lessors are owed royalties on actual volumes of gas used
by Lessee for unit fuel under the Lessors’ Leases.
Example Contract: None needed.
21. Whether Lessors are owed royalties on actual volumes of gas used
by Lessee for Lease Fuel:
i. Under the Sheppard Lease;
ii. Under the Crain Lease
Example Contract: None needed.
22. Whether the following volumes of actual and/or contractually fixed
percentages of gas used/retained as fuel or deemed to be lost and
unaccounted for gas by third-party processing plants, gatherers, or
transporters constitute a Contractual Charge under the Sheppard Lease:
i. Actual gas used by a third-party processor, gatherer, or
transporter for fuel in providing services to Lessee;
Example Contracts: Hawk Field Services Firm Gas Gathering
Agreement. Ex. C; Petrohawk/Enterprise Gas Processing
Agreement.
ii. Contractually fixed percentages of gas retained by a third-
party processor, gatherer, or transporter for fuel in providing services
to Lessee; and
Example Contracts: Individual Transaction Confirmation to
Gathering and Natural Gas Services Agreement, ETC and
Petrohawk. No. 9116-103; Petrohawk/Oasis Intrastate
Transp. Agmt; Petrohawk/Oasis ITC; GeoSouthern/Copano
2012 Gas Services Agreement; 2012 ITC to Petrohawk-ETC
49
2010 Gas Gathering Agreement, 9116-102.
iii. Contractually fixed percentages of gas deemed to be lost and
unaccounted for gas in a processing, gathering, or transportation
agreement.
Example Contracts: Individual Transaction Confirmation to
Gathering and Natural Gas Services Agreement. ETC and
Petrohawk. No. 9116-103; 2012 ITC to Petrohawk-ETC 2010
Gas Gathering Agreement. 9116-102
23. Whether the following volumes of actual and/or contractually fixed
percentages of gas used/retained as fuel or deemed to be lost and
unaccounted for gas by third-party processing plants, gatherers, or
transporters constitute a Contractual Charge under the Crain Lease:
i. Actual gas used by a third-party processor. gatherer, or
transporter for fuel in providing services to Lessee;
Example Contract: same as 22.i
ii. Contractually fixed percentages of gas retained by a third-
party processor, gatherer, or transporter for fuel in providing services
to Lessee; and
Example Contract: same as 22.ii
iii. Contractually fixed percentages of gas deemed to be lost and
unaccounted for gas in a processing, gathering, or transportation
agreement.
Example Contract: same as 22.iii
50