Court Opinion

ID: 9378687
Source: CourtListenerOpinion
Date Created: 2023-03-12 14:05:49.685482+00
Date Added: 2024-06-11T17:15:38.830210
License: Public Domain

Supreme Court of Texas
                           ══════════
                            No. 20-0904
                           ══════════

  Devon Energy Production Company, L.P., f/k/a GeoSouthern
 DeWitt Properties, LLC, BPX Properties (NA) LP, GeoSouthern
     Energy Corporation, and BPX Production Company,
                             Petitioners,

                                  v.

                    Michael A. Sheppard, et al.,
                            Respondents

   ═══════════════════════════════════════
               On Petition for Review from the
     Court of Appeals for the Thirteenth District of Texas
   ═══════════════════════════════════════

                      Argued October 5, 2022

      JUSTICE DEVINE delivered the opinion of the Court, in which Chief
Justice Hecht, Justice Lehrmann, Justice Boyd, Justice Busby, Justice
Bland, and Justice Huddle joined.

      JUSTICE BLACKLOCK filed a dissenting opinion.

      Justice Young did not participate in the decision.

      This oil-and-gas dispute presents a new wrinkle to a perennial
problem: how to calculate the landowners’ royalty under the terms of a
mineral lease. The landowners and producers are characteristically at
odds over the allocation of postproduction costs. But unlike the typical
case, the parties agree that (1) the landowners’ royalty is free of costs
between the wellhead and the point of sale; and (2) the producers
cannot—and do not—directly or indirectly charge the royalty holders
with a proportionate share of those expenses. At issue here is whether
a bespoke lease provision also makes the landowners’ royalty free of
post-sale postproduction costs that add value after the point of sale but
are not part of the producers’ “gross proceeds.”
      The subject leases expressly mandate that in determining the
royalties to be paid by the producers, if “any reduction or charge for
[postproduction] expenses or costs” has been “include[d]” in “any
disposition, contract or sale” of production, those amounts “shall be
added to the . . . gross proceeds so that [the landowners’] royalty shall
never be chargeable directly or indirectly with any costs or expenses other
than its pro rata share of severance or production taxes.” 1          In a
declaratory-judgment action, the lower courts held that, based on this
language, the landowners’ royalty is payable not only on gross proceeds
but also on an unaffiliated buyer’s post-sale postproduction costs if the
producers’ sales contracts state that the sales price has been derived by
deducting such costs from published index prices downstream from the
point of sale. We agree and therefore affirm summary judgment for the
landowners as to those types of marketing arrangements. This broad
lease language unambiguously contemplates a royalty base that may

      1   Emphases added.

                                    2
exceed gross proceeds and plainly requires the producers to pay royalties
on the gross proceeds of the sale plus sums identified in the producers’
sales contracts as accounting for actual or anticipated postproduction
costs, even if such expenses are incurred only by the buyer after or
downstream from the point of sale.
                              I. Background
       Although mineral leases operate against a backdrop of
oil-and-gas jurisprudence that states the “usual” rules, we have
consistently recognized that parties are free to make their own
bargains. 2 Usually, the landowners’ royalty is free of the expenses
incurred to bring minerals to the surface (production costs) but not
expenses    incurred    thereafter    to   make     production     marketable
(postproduction costs). 3 After production, costs are incurred to remove
impurities, to transport production from the wellhead, and to otherwise

       2E.g., Nettye Engler Energy, LP v. BlueStone Nat. Res. II, LLC, 639
S.W.3d 682, 696 (Tex. 2022).
       3 BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 387 (Tex.
2021); see French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex. 2014)
(“Generally speaking, a royalty is free of the expenses of production [but]
subject to postproduction costs . . . to render [production] marketable, but the
parties may modify this general rule by agreement.” (alterations in original)
(internal quotations omitted)).

                                       3
ready it for sale to a downstream market or the public. 4                These
investments generally make production more valuable. 5
       Landowners and producers can “agree on what royalty is due, the
basis on which it is to be calculated, and how expenses are to be
allocated.” 6 A landowner’s royalty free of postproduction costs is more
valuable to the royalty holder—and more costly to the producer—
because it means the landowner will share in the enhanced value of
production but not the expenses incurred to make it so. For this reason,
litigation over the construction of mineral leases and the allocation of
postproduction costs is common. We have grappled with these issues
many times, but the variation presented in this appeal is one of first
impression.
       The mineral leases at issue convey interests in the Eagle Ford
Shale. 7 The Sheppard leases were executed in 2007, before the shale’s
viability was established with the first successfully drilled well, and the

       4Byron C. Keeling, In the New Era of Oil & Gas Royalty Accounting:
Drafting a Royalty Clause That Actually Says What the Parties Intend It to
Mean, 69 BAYLOR L. REV. 516, 524-25 (2017).
       5Id. at 525 (“Oil and gas production is less valuable at the wellhead
because any arm’s length purchaser will assume that it will have to incur the
cost to remove impurities from the production, to transport it from the
wellhead, or otherwise to get it ready for sale to a downstream market or the
general public.”).
       6French, 440 S.W.3d at 8; see Burlington Res. Oil & Gas Co. v. Tex.
Crude Energy, LLC, 573 S.W.3d 198, 203 (Tex. 2019) (the contracting parties
may “define post-production costs any way they choose”).
       7Only five mineral leases are involved in this case, but the parties have
described the litigation as a bellwether for as many as 200 other leases
employing the same language.

                                       4
Crain leases were executed in 2010 and 2011 amid the rising boom. 8
The producers are original and successor lessees. 9
       The following royalty provisions are relatively standard fare in
the industry: 10
       3. The royalties to be paid by Lessee are:

       (a) on oil, [1/5th of production for the Sheppard or 1/4th of
       production for the Crain leases] 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 . . . the gross proceeds of the sale
       thereof . . . ;

       (b) on gas . . . [1/5th for the Sheppard or 1/4th for the Crain
       leases of] . . . 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

       8See Petty Bus. Enters. v. Chesapeake Expl., L.L.C. (In re Chesapeake
Energy Corp.), Nos. 20-33233, 20-3433, 2021 WL 4190266, at *1 (Bankr. S.D.
Tex. Sept. 14, 2021) (noting the first successful horizontal well in the Eagle
Ford Shale was completed in 2008); Bret Wells, Please Give Us One More Oil
Boom—I Promise Not to Screw It Up This Time: The Broken Promise of
Casinghead Gas Flaring in the Eagle Ford Shale, 9 TEX. J. OIL GAS & ENERGY
L. 319, 348 (2013–2014) (“The Eagle Ford shale was not even shown to be
viable until 2008[.]”).
       9 The producers/lessees are petitioners Devon Energy Production Co.,
L.P., f/k/a GeoSouthern DeWitt Properties, LLC; BPX Properties (NA) LP;
GeoSouthern Energy Corp.; and BPX Production Co.
       10 Paragraph numbering differs slightly between the Sheppard and
Crain leases, but for consistency with the parties’ briefing and the court of
appeals’ opinion, we follow the numbering scheme in the Sheppard leases.

                                      5
      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. 11

The conflict here centers on more unconventional language found in
Paragraph 3(c) and Addendum L, which provide:
      (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[ing] or marketing of the oil or gas, then such
      deduction, expense or cost shall be added to . . . 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.

      ....

      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[ 12] of this

      11   Emphases added.
      12The Crain leases make Addendum L controlling over the corollaries
to Paragraphs 3(a) and 3(b) but do not reference the corollary to
Paragraph 3(c).

                                     6
       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 [133,] 135-36 (Tex. 1996). 13

The interpretive question is whether this unusual lease language
manifests contractual intent to include in the royalty base post-sale
postproduction costs that are not part of the producers’ gross sales
proceeds.
       As authorized by the Sheppard and Crain leases, the producers
sell oil-and-gas production to unaffiliated third parties at various points
downstream from the wellhead and pay royalty to the landowners on the
gross proceeds “paid to” or “received by” the producers for those sales. 14
Consistent with both the contractual definition of “gross proceeds” and
the ordinary meaning of that term, 15 the producers do not deduct—
directly or indirectly—any expenses they incur to ready production for
sale. Along these lines, when unaffiliated third-party processors have
purchased production at the tailgate of the processing plant, and they
have paid a lower price as a cost adjustment for having transported and

       13   Emphases added. Underlining in original.
       14The landowners are respondents Michael A. Sheppard, Constance S.
Kirk, Jennifer S. Badger, Frank B. Sheppard, James K. Crain, Christopher M.
Crain, James K. Crain III, Patrick G. Crain, and Shirley R. Crain.
       15 Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 873-74 (Tex.
2016) (observing that “gross” means without deductions and that, when a lease
provides for royalty to be paid on the producer’s sales proceeds, “the
price-received basis for payment . . . is sufficient in itself to excuse the lessors
from bearing postproduction costs”); Judice v. Mewbourne Oil Co., 939 S.W.2d
133, 136 (Tex. 1996) (“The term ‘gross proceeds’ means that the royalty is to be
based on the gross price received by [the lessee].”).

                                         7
processed gas on the producers’ behalf, the producers have added the
pre-sale transportation and processing expenses to the stated sales price
before computing the landowners’ royalty payment. Both sides agree
this addition (or “add back”) to the price the producers actually received
is required and proper under the lease terms because those
transportation and processing expenses are consideration accruing to
the producers’ benefit and, therefore, part of the producers’ “gross
proceeds.”
       The producers do not, however, include in the royalty calculation
any post-sale costs to be incurred by unaffiliated third-party buyers
after the point of sale. Although everyone agrees those costs are not part
of the producers’ gross proceeds, the exclusion of such costs from the
royalty base is at the heart of the landowners’ allegation that the
producers have been underpaying royalties.
       The royalty dispute arose when the landowners discovered that
the producers sold oil under contracts setting the sales price—and thus
the gross sales proceeds—by using published index prices 16 at market
centers downstream from the point of sale and then subtracting $18 per
barrel for the buyer’s anticipated post-sale costs for “gathering and
handling, including rail car transportation.” The producers did not add
the $18 adjustment to the royalty base and, instead, paid royalty only
on their gross sales proceeds. As the landowners later learned, the

       16 Neither the producers nor the buyers set the index price. Rather,
“[i]ndex prices are published by major industry publications and are based on
actual, arms-length transactions in the geographic locations covered by the
particular indices.” Union Pac. Res. Grp., Inc. v. Neinast, 67 S.W.3d 275, 279
(Tex. App.—Houston [1st Dist.] 2001, no pet.).

                                      8
producers also engaged in other transactions with complicated pricing
formulas that similarly employed market-center index prices that were
adjusted downward by flat, percentage, or volume amounts that the
sales contracts sometimes—but not always—identified as accounting for
the buyer’s actual or anticipated post-sale postproduction costs. 17 The
producers have never included any of those cost adjustments in the
royalty calculation because they read the leases as requiring payment of
royalties only on their gross sales proceeds. 18
      The landowners have no quarrel with how the producers have
calculated gross proceeds, but they read the leases as requiring royalty
to be paid on additional sums that are not gross proceeds and that do
not inure to the producers’ benefit: the buyer’s actual or anticipated
costs to enhance the value of production after the point of sale. In
alleging royalties have been underpaid, the landowners cite the
specially written language in Paragraph 3(c) and Addendum L as
obligating the producers to pay royalty on those expenses by adding the
deducted amounts to the producers’ gross sales proceeds before
calculating the royalty payment.
      The landowners’ sued for a declaration to that effect and sought
damages for breach of contract. In teeing up the interpretive divide, the

      17  See 643 S.W.3d 186, 205-08 (Tex. App.—Corpus Christi–Edinburg
2020) (discussing and quoting the terms of various sales agreements the
parties offered as exemplars of disputed issues).
      18 The leases provide two valuation options for oil-and-gas production,
with gross proceeds as the required option for both if it produces a higher
royalty payment. The parties agree that royalty has been properly paid on
gross proceeds rather than on the leases’ alternative valuation options.

                                     9
landowners described Paragraph 3(c) as an “add-to-proceeds” clause
that expressly contemplates royalty payments on sums exceeding gross
proceeds while the producers dubbed it an “add back” clause that applies
only to pre-sale expenses that have been deducted, directly or indirectly,
from gross proceeds. Both sides interpreted Addendum L as supporting
their conflicting constructions of Paragraph 3(c).
      The landowners argued that the downward adjustments in the
producers’ sales contracts—whether labeled as accounting for post-sale
postproduction costs or not—are, in the words of Paragraph 3(c),
“reduction[s] or charge[s]” the producers are required to “add[] to” “gross
proceeds” so that the landowners’ royalty is “never” burdened by
postproduction costs even “indirectly.” According to the landowners,
Paragraph 3(c)’s specially written language unburdens the royalty
interest from postproduction costs irrespective of the producers’
unilateral choices about where and in what condition to sell production
and, in that way, affords the producers latitude in structuring their sales
transactions without impacting the royalties payable to the landowners.
As they explained it, if the producers had incurred those same costs to
take production to market, there would be no dispute that the
landowners’ royalty would be calculated on the downstream value
without reduction for those expenditures.            In their estimation,
Paragraph 3(c) makes the royalty calculation consistent no matter
where the producers choose to sell production. This construction, they
said, was supported by Addendum L’s repetition of the mandate that
royalty payments “shall never bear or be charged with” postproduction
expenses “either directly or indirectly.”

                                    10
      Seeing things quite differently, the producers characterized
Paragraph 3(c) as mere surplusage that emphasizes the cost-free nature
of a “gross proceeds” royalty by requiring them to “add back” only
pre-sale postproduction costs that may have diminished the sales price.
Although the producers have never disputed that parties to a mineral
lease are free to allocate expenses in any way they see fit, they urged
that the landowners’ construction of Paragraph 3(c) is untenably
contrary to the industry’s expectation that a royalty free of
postproduction costs means only those costs incurred up to the point of
sale. In their view, nothing in the leases contemplates payment of a
royalty on expenses to enhance the value of production after the point of
sale to the first unaffiliated buyer.         To the contrary, because
Addendum L cites this Court’s opinions in Heritage Resources, Inc. v.
NationsBank 19 and Judice v. Mewbourne Oil Co., 20 the producers
understand that provision as emphasizing that the landowners’ royalty
is free of postproduction costs only between the well and the point of sale
because both cases involved disputes about postproduction costs of that
nature.
      At the parties’ request, the trial court severed and abated the
breach-of-contract action. Then, in the declaratory-judgment action, the
parties filed cross-motions for summary judgment on 23 “Stipulated
Disputed Issues” involving, among other things, post-sale costs under a
variety of pricing and marketing formulas set forth in the producers’

      19   939 S.W.2d 118 (Tex. 1996).
      20   939 S.W.2d 133 (Tex. 1996).

                                         11
contracts with third-party buyers.               For most issues, the parties
submitted exemplar transactions for which the landowners claim
additional royalties are owed.                 Some disputed issues involved
agreements stating the purpose for a downward adjustment, while
others did not. Some disputed issues involved adjustments based on the
buyer’s actual post-sale expenditures, while other adjustments were
based on anticipated post-sale expenditures. The trial court ruled in the
landowners’ favor across the board.
      The court of appeals affirmed in part and reversed and rendered
in part. 21 Before considering the individual issues, the appellate court
determined that the “highly unique” lease terms provide for a
“proceeds-plus”          royalty   that   “expressly    [and   unambiguously]
contemplates the addition of certain sums to gross proceeds in order to
arrive at the proper royalty base.” 22              The court explained that
Paragraph 3(c)’s “exceptionally broad” language—which is not limited
to pre-sale costs or only those expenses incurred by the producers—could
be enforced as written without rendering it surplusage. 23 To that end,
the court concluded that the royalties payable by the producers under
the Sheppard and Crain leases are, “in most circumstances,” “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.” 24

      21   643 S.W.3d at 211.
      22   Id. at 189, 201, 205, & 211.
      23   Id. at 201-02.
      24   Id. at 205.

                                          12
      With the leases so construed, the court turned to the disputed
issues, which it grouped into six broad categories: (1) price adjustments
of a fixed amount with a stated purpose corresponding to “production,
treatment, transportation, manufacturing, process[ing] or marketing”
expenses; (2) price adjustments of a fixed amount without a stated
purpose; (3) price adjustments based on the actual costs incurred by
third-party purchasers for “production, treatment, transportation,
manufacturing, process[ing] or marketing” expenses; (4) adjustments
for volumes of gas used by the producers for their own operations and
never sold to third parties; (5) adjustments for volumes of production
deemed to be lost or unaccounted-for by third parties; and (6) value
retained by the producers as a result of the application of contractually
fixed recovery factors. 25       All of the disputed issues are set out
individually in an appendix to the court of appeals’ opinion. 26
      The court reversed and rendered summary judgment in the
producers’ favor on the 13 disputed issues comprising categories (2), (4),
(5), and (6). 27 Because the landowners have not appealed the adverse
judgment on those issues, we express no opinion as to their disposition.
The only matters before this Court are the 10 disputed issues
encompassed by categories (1) and (3)—price adjustments for a stated
purpose—as to which the court of appeals affirmed summary judgment

      25   Id. at 205-10.
      26   Id. at 211-16 (omitting only the record citations).
      27   Id. at 206-11.

                                        13
for the landowners. 28         The parties have agreed that all of the
arrangements at issue involved costs incurred or to be incurred after the
point of sale to an unaffiliated buyer.

       28Id. at 205-08. Exemplar contracts the parties cited in relation to the
disputed issues comprising those categories include:
       •    Disputed Issue 2: A 2011 agreement for the sale of crude oil
            and condensate with the price per barrel set as a weighted
            average of published index prices “minus $18.00 gathering
            and handling, including rail car transportation” per barrel.
       •    Disputed Issue 4: A 2013 sale of crude oil from one producer
            to an unaffiliated producer, to be delivered into a specific
            pipeline, for a price based on a weighted average of sales “less
            transport, terminal and marketing costs.”
       •    Disputed Issues 7 and 13: A 2010 “Gas Processing
            Agreement” under which a third-party processor agreed to
            process gas and to purchase 100% of the resulting natural
            gas liquids and 50% of any drip condensate “attributable to
            [the producer]’s gas.” The price for both was set as a
            published index price “less [the processor’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.”
       •    Disputed Issue 8: A 2012 “Gas Services Agreement” under
            which a third party agreed to gather and process gas
            production, purchase the resulting natural gas liquids, and
            return the remaining residue gas to the producer. The price
            for the natural gas liquids was set at a published index price
            “less” a “T&F fee” of “$0.104 per gallon.”
       •    Disputed Issues 9 and 12: A 2010 “Gas Processing
            Agreement” between a third-party processor and a producer
            that includes reductions based on the processor’s actual T&F
            cost.
       •    Disputed Issue 10: Various sales orders for natural gas
            liquids that set the purchase price as an average of published
            index prices “less” a “fixed fee” determined by a formula that

                                        14
       In affirming summary judgment as to these types of transactions,
the court of appeals concluded that, unlike the category (2) issues in
which contractual reductions had not been attributed to any of the types
of costs specifically enumerated in Paragraph 3(c), the category (1) and
(3) sales contracts involved downward adjustments specifically labeled
as    accounting      for    “production,      treatment,     transportation,
manufacturing, process[ing] or marketing” expenses.                The court
concluded that summary judgment for the landowners was proper on
the category (1) and (3) issues because the specified deductions fall

           “includes pipeline fee, fixed frac fee, truck transportation,
           terminalling fee and margins.”
       •   Disputed Issue 11: A 2012 “Gas Processing Agreement”
           under which the buyer agreed to pay the producer on a
           monthly basis “ninety-two percent (92%) of the Producer
           Plant Products Value,” which the contract defined as the
           volume of the plant products attributable to the producer
           times a published index price “minus the [T&F] Fee”
           applicable for that month.
       •   Disputed Issue 15: An arrangement under which a
           third-party processor agreed to gather and sell drip
           condensate delivered by the producer under a 2012
           “Individual Transaction Confirmation” stating the processor
           would pay the producer 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 the processor’s actual costs for
           “trucking, stabilization, and any other [T&F] fees.”
The transaction referenced in Disputed Issue 15 also included a deduction for
a flat-rate fee of $0.03 per gallon, and the court of appeals reversed the
summary judgment as to that portion of the transaction because the agreement
did not state that the fee corresponded to any category of postproduction costs,
as contemplated by Paragraph 3(c). See id. at 207.

                                      15
squarely within Paragraph 3(c)’s “added to . . . gross proceeds”
requirement. 29
         In their petition for review, the producers contend they are
entitled to judgment as a matter of law because the Sheppard and Crain
leases are gross-proceeds leases that do not “plainly and in a formal way
express a clear intent to create an exception to the basic principle [of oil-
and-gas law] that royalties are not paid on post-sale expenses that may
be incurred to resell production at market centers after oil and gas is
sold by the lessee to generate the ‘gross proceeds’ from which royalties
are paid.” 30 In an alternative issue not presented to the court of appeals,
the producers assert that, even if the appellate court’s construction of
the leases is otherwise correct, the court improperly held that
Paragraph 3(c) requires them to include expenses for a specific type of
processing—“transportation and fractionation”—in the royalty base.
                                 II. Discussion
         On cross-motions for summary judgment, each party bears the
burden of proving its entitlement to judgment as a matter of law. 31
When the trial court grants one motion and denies the other, as in this
case, we “determine all questions presented” and render the judgment

         29   Id. at 205-08.
        On this issue, SM Energy Company and Texas Oil & Gas Association
         30

have submitted amicus briefs supporting the producers, and Texas Land and
Mineral Owners Association has submitted an amicus brief supporting the
landowners.
         31   City of Garland v. Dall. Morning News, 22 S.W.3d 351, 356 (Tex.
2000).

                                       16
the trial court should have rendered. 32 Whether any party is entitled to
summary judgment here turns on the proper construction of the mineral
leases. 33 Interpretation of a mineral lease involves questions of law we
consider de novo. 34
         As with any other contract, our fundamental objective is to
ascertain the parties’ intent as expressed in the leases. 35 In doing so,
we construe the instruments as a whole, giving the language its plain,
ordinary, and generally accepted meaning unless the context indicates
the parties used terms in a technical or different sense. 36 To the extent
possible, we strive to harmonize and give effect to all the lease provisions
so that none will be rendered meaningless. 37              In doing so, we are
cognizant that contracts should be construed “from a utilitarian
standpoint” that is mindful of “the particular business activity sought to
be served.” 38
         When, as here, a contract can be given a definite and certain
meaning, it is not ambiguous even though the parties advance

         32   Id.
         33   See BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 387 (Tex.
2021).
         34   Id.
         35   Murphy Expl. & Prod. Co.–USA v. Adams, 560 S.W.3d 105, 108 (Tex.
2018).
         36   Id.
         37   Id.
          Kachina Pipeline Co. v. Lillis, 471 S.W.3d 445, 450 (Tex. 2015)
         38

(quoting Lenape Res. Corp. v. Tenn. Gas Pipeline Co., 925 S.W.2d 565, 574 (Tex.
1996)).

                                          17
competing constructions. 39 Unambiguous contracts must be enforced as
written without considering extrinsic evidence bearing on the parties’
subjective intent. 40 In keeping with our commitment to freedom of
contract, we will not rewrite the leases to “add to or subtract from [their]
language” or to “interpolate constraints” not found in the unambiguous
language. 41
       Applying these well-settled principles to the Sheppard and Crain
leases, we agree with the lower courts that when the producers’
dispositions of production include price adjustments with a stated
purpose corresponding to “production, treatment, transportation,
manufacturing, process[ing] or marketing” expenses, those amounts
must be “added to” “gross proceeds” before calculating the landowners’
royalty payments.
                                        A.
       The Sheppard and Crain leases are, to an extent, “gross proceeds”
leases, so everyone agrees that the leases have departed from the usual
rules by freeing the landowners’ royalty from at least some
postproduction costs. Concordant with the common understanding of
the term, the Sheppard and Crain leases define “[g]ross proceeds (for
royalty purposes)” as “the total monies and other consideration accruing
to or paid the Lessee or received by Lessee for disposition or sale[.]” As

       39   URI, Inc. v. Kleberg County, 543 S.W.3d 755, 764-65 (Tex. 2018).
       40   Id.
       41Id. at 758, 769-70; see Tenneco Inc. v. Enter. Prods. Co., 925 S.W.2d
640, 646 (Tex. 1996) (“We have long held that courts will not rewrite
agreements to insert provisions parties could have included or to imply
restraints for which they have not bargained.”).

                                        18
we have explained, “royalties computed on gross amounts received
means royalties are paid based on point-of-sale proceeds without
deduction of postproduction costs.” 42 And when a lease provides for
royalty to be paid on the producer’s gross sales proceeds, “the
price-received basis for payment . . . is sufficient in itself to excuse the
lessors from bearing postproduction costs.” 43 There is no dispute in this
case that the producers have properly calculated their gross proceeds,
including by increasing the amount received under a sales contract by
“other consideration accruing to” the producers, such as pre-sale
processing and transportation costs incurred by buyers on the producers’
behalf.
         But the leases also plainly require certain sums to be “added to”
gross proceeds. The question is not whether an unaffiliated buyer’s
postproduction costs are gross proceeds under the leases or under the
law.     Of course, they are not.      The question is whether the leases
nonetheless require the producers to pay royalty on those costs.
         The landowners cite no precedent requiring producers to pay
royalty on postproduction costs incurred downstream from the point of
sale. But the parties to a mineral lease could unquestionably make that
agreement. 44 Indeed, absent an agreement to the contrary, a minority

         42   BlueStone Nat. Res. II, LLC v. Randle, 620 S.W.3d 380, 391 (Tex.
2021).
          Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 873-74 (Tex.
         43

2016); see BlueStone, 620 S.W.3d at 389-91 (explaining the difference between
gross-proceeds leases and net-proceeds leases).
        See, e.g., Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, 291 F. App’x
         44

626, 627, 633-34 (5th Cir. 2008) (holding, in a dispute about whether the

                                        19
of jurisdictions charge producers with paying royalties on a “marketable
product”—meaning one that is both in a commercially useable condition
and sold in a commercial marketplace—regardless of where and in what
condition the product is actually sold. 45        Considering the obvious
economic advantage such an arrangement provides to the royalty
holder, it would not be unreasonable for Texas landowners to negotiate
lease terms that provide for something similar. 46          Nor would it be

lessor’s royalty was burdened by post-sale postproduction costs, that the
parties had agreed to base royalty not only on the lessee’s revenue from gas
production but on “all” revenue under “uniquely worded natural gas liquid
royalty provisions” that had been modified as part of a settlement to delete
language limiting the calculation of royalties to only the lessee’s revenue).
       45 See, e.g., Wellman v. Energy Res., Inc., 557 S.E.2d 254, 264 (W. Va.
2001) (“[T]he duty to market embraces the responsibility to get the oil or gas
in marketable condition and actually transport it to market.”); Rogers v.
Westerman Farm Co., 29 P.3d 887, 906 (Colo. 2001) (under the marketable
product rule “the expense of getting the product to a marketable condition and
location are borne by the lessee”); accord 30 C.F.R. §§ 1206.20, .55 (requiring
lessees on federal or Native American lands to place oil-and-gas production in
marketable form, defined as “lease products which are sufficiently free from
impurities and otherwise in a condition that they will be accepted by a
purchaser under a [typical] sales contract”); Amoco Prod. Co. v. Watson, 410
F.3d 722, 725 (D.C. Cir. 2005) (noting that the federal Mineral Leasing Act and
the rules adopted pursuant to the Act obligate lessees to put gas production in
marketable condition at no cost to the federal lessor, so “[i]f a lessee sells
‘unmarketable’ gas at lower cost, the gross proceeds for purposes of royalty
calculation must be increased to the extent that gross proceeds have been
reduced because the purchaser, or any other person, is providing certain
services to place the gas in marketable condition” (internal quotations
omitted)).
       46See Petty Bus. Enters. v. Chesapeake Expl., L.L.C. (In re Chesapeake
Energy Corp.), Nos. 20-33233, 20-3433, 2021 WL 4190266, at *6 (Bankr. S.D.
Tex. Sept. 14, 2021) (construing an Eagle Ford Shale lease specifically
requiring the lessee to add to the royalty base “any adjustment or reduction”
for postproduction expenses that are “deducted by . . . the purchaser for
purposes of arriving at a price or value for Minerals” (emphasis added)).

                                      20
unreasonable for landowners to bargain for a fraction of the value at
market rather than at the wellhead to avoid disputes about whether
shared postproduction costs are reasonable. As in any contract dispute,
our task is to determine how postproduction costs were allocated under
these particular leases. 47
       The inescapably broad language in Paragraph 3(c) is clear in that
regard. It requires “any reduction or charge” for postproduction costs
that have been included in the producer’s disposition of production to be
“added to” gross proceeds so that the landowners’ royalty “never” bears
those costs even “indirectly.” Paragraph 3(c) is not textually constrained
to the expenses incurred by the seller or prior to the point of sale. 48
Rather, those costs are encompassed by Paragraphs 3(a) and 3(b), which
require royalty to be paid on the producers’ gross proceeds. A plain and
natural reading of Paragraph 3(c) unambiguously contemplates royalty
payable on an amount that may exceed the consideration accruing to the

       47 Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 124 (Tex. 1996)
(“[W]e are construing specific language in specific oil and gas leases. Parties
to a lease may allocate costs, including post-production or marketing costs, as
they choose. Our task is to determine how those costs were allocated under
these particular leases.” (internal citation omitted)).
       48  Compare with 6 WEST’S TEX. FORMS, Minerals, Oil & Gas § 3:26 (4th
ed.) (“[L]essor’s royalty share of oil and gas shall not bear any portion of the
costs of producing, treating, processing, compressing, gathering, transporting
or marketing lessor’s share of production incurred prior to the point of sale
thereof. Regardless of whether [the lease] calls for lessor’s royalty to be
calculated on the basis of the market price, the amount realized by lessee or
the market value, or otherwise, and whether calculated at the well, at the point
of sale or elsewhere, if such value would otherwise have any of such costs
incurred by lessee deducted before such calculation is made, the amount of any
such deduction shall be added to and included in such value before calculation
of lessor’s royalty share thereof.” (emphases added)).

                                      21
producers. Furthermore, because Paragraphs 3(a) and 3(b) alone suffice
to free the royalty from all pre-sale costs, Paragraph 3(c) serves no
purpose at all if not to allow the amount on which the royalty payment
is calculated to exceed gross proceeds. As the court of appeals explained,
Paragraph 3(c)’s prohibition on “indirectly” charging the royalty with
postproduction costs could only refer to the buyer’s post-sale
expenditures       because    all   other    pre-sale   expenditures—whether
incurred directly or indirectly by the producers—are already included in
gross proceeds. 49 An obvious and reasonable purpose for a provision like
Paragraph 3(c) is to provide the producer with the flexibility to sell
production at any point downstream of the well while discharging the
landowners from the usual burden to share the costs of rendering
production marketable—whether through direct expenditures or
indirectly through a lower valuation at the producer’s chosen point of
sale.
        Unable to avoid the breadth of the negotiated lease language, the
producers argue that we must construe Paragraph 3(c) as mere
surplusage because (1) payment of royalty on non-proceeds is so at odds
with the usual expectations that it cannot be required when the leases
do not state such an intent “plainly and in a formal way”; 50 (2) the leases

        49   643 S.W.3d 186, 203 (Tex. App.—Corpus Christi–Edinburg 2020).
        50Wenske v. Ealy, 521 S.W.3d 791, 797 (Tex. 2017) (“Parties are free to
contract for whatever division of the interests suits them. Their intent, as
expressed in the deed, controls. [But i]f they want their agreement to operate
differently from this basic principle of mineral conveyance, . . . they should
‘plainly and in a formal way express that intention.’” (quoting Benge v.
Scharbauer, 259 S.W.2d 166, 169 (Tex. 1953))).

                                        22
are replete with surplusage emphasizing that “gross” really means
“gross,” so the rule against avoiding surplusage holds no purchase; and
(3) Addendum L, by citing the Heritage Resources, Inc. v. NationsBank 51
and Judice v. Mewbourne Oil Co. 52 opinions, demonstrates that the
parties were concerned only with prohibiting deductions for the
producer’s postproduction costs, not the buyer’s. These contentions do
not withstand examination.
       To assure “continuity and predictability” in oil-and-gas law, 53 it
is incumbent on the courts to construe commonly used terms in a
uniform and predictable way. 54            Lease agreements often “contain
provisions that are standard throughout the oil and gas industry [that]
have been judicially interpreted many times over many years.” 55
“Careful adherence to those interpretations, and consistent application
of them, is important to industry stability.” 56 But there is nothing
common, usual, or standard about the language in Paragraph 3(c),
which is quite clear in expressing the intent to deviate from the usual

       51   939 S.W.2d 118 (Tex. 1996).
       52   939 S.W.2d 133 (Tex. 1996).
       53See Wenske, 521 S.W.3d at 798 (“Yet we are acutely aware that parties
who draft agreements rely on the principles and definitions pronounced by this
Court. They rightly depend on us for continuity and predictability in the law,
especially in the oil-and-gas field.”).
       54See Heritage Res. Inc. v. NationsBank, 939 S.W.2d 118, 129 (Tex.
1996) (Owen, J.) (plurality op.) (“In construing language commonly used in oil
and gas leases, we must keep in mind that there is a need for predictability
and uniformity as to what the language used means.”).
       55   French v. Occidental Permian Ltd., 440 S.W.3d 1, 8 (Tex. 2014).
       56   Id.

                                          23
expectations regarding the allocation of postproduction costs.               The
parties “plainly and in a formal way” expressed their intent for the
agreement to “operate differently” in two ways: first by requiring that
royalties be paid on gross proceeds and then by requiring an addition to
gross proceeds for the stated purpose of freeing the landowners’ royalty
from “any costs or expenses other than its pro rata share of severance or
production taxes.” 57       Contrary to the uniform and predictable
understanding of these terms, the producers would have us construe
“added to . . . gross proceeds” as the equivalent of “gross proceeds.” A
reasonable person would not read those words in the way the producers
suggest.
       As for avoiding surplusage, our construction of the leases does not
rely on that construction canon and, instead, is only confirmed by it. We
are enforcing the leases exactly as they are written, according to their
plain language, which also happens to avoid giving rise to a redundancy.
As we have said time and again, courts should avoid rendering contract
language meaningless if possible, and it is possible and reasonable to
construe    the    Sheppard     and    Crain     leases    without    rendering

       57 See Wenske, 521 S.W.3d at 798 (observing that parties who want their
agreement to “operate differently” from basic principles of mineral
conveyances should “plainly and in a formal way” express the intent to make
a different agreement). In a post-submission letter, the producers contend that
this Court’s opinions have applied an “industry-accepted meaning” of “costs
and expenses” that refers only to the lessees’ postproduction costs. While it is
true that our precedent has involved disputes about allocation of the
lessee/seller’s postproduction costs, the producers cite no authority limiting the
term in that way, and in any event, the meaning of these terms ultimately
depends on how the parties used them in these leases. See Burlington Res. Oil
& Gas Co. v. Tex. Crude Energy, LLC, 573 S.W.3d 198, 203 (Tex. 2019) (the
contracting parties “may define post-production costs any way they choose”).

                                       24
Paragraph 3(c) nugatory. Parties may, of course, repeat themselves for
emphasis or out of an abundance of caution, and the leases’ lengthy
definition of “gross proceeds” is a good example. But Paragraph 3(c) goes
far beyond mere emphasis or repetition. It serves the distinct purpose
of defining not what gross proceeds are but what must be added to that
already defined term.
       Finally, by citing and disclaiming the holdings in Heritage
Resources and Judice, Addendum L—which the parties made controlling
in the event of a conflict with Paragraph 3—does indeed manifest an
intent to prohibit deductions for postproduction costs incurred by the
producers, but it conveys no intent to override the “added to” language
in Paragraph 3(c). Those contemporaneously issued opinions involved
disputes about costs incurred between the well and the point of sale
under leases or division orders providing for a royalty to be calculated
on the value of production “at the well.” 58
       In Heritage Resources, a plurality of the Court concluded that
lease language purporting to prohibit “deductions” from royalties based
on production valued “at the well” was ineffective to relieve the royalty
interest of its usual obligation to share postproduction costs for the
simple—and       mathematical—reason           that   there    aren’t    any

       58 See Heritage Res., 939 S.W.2d at 121-23 (considering a clause
prohibiting deductions of postproduction costs on a royalty based on “market
value at the well”); Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 135-36 (Tex.
1996) (construing a lease with an unambiguous “market value at the well”
royalty clause and a division order with contradictory language requiring
“[s]ettlement for gas sold” to be based on “the gross proceeds realized at the
well”).

                                     25
postproduction costs to “deduct” when value is determined at the well. 59
The Heritage Resources lease required royalty to be valued at the well,
and by merely prohibiting deduction of postproduction costs, the
provision under consideration there had done nothing to change the
valuation point.
       While neither Heritage Resources nor Judice involved a dispute
about costs or expenses incurred by buyers after or downstream from
the point of sale, that circumstance does not produce any inconsistency
with Paragraph 3(c) and, thus, does not preclude enforcing that
subsection as allowing the royalty base to exceed the producers’ gross
proceeds—exactly as it is written. 60 Notably, Justice Owen’s concurring
opinion in Heritage Resources (which became the plurality opinion on
rehearing) explained that, to make a royalty free of postproduction costs,
a lease could change the point at which it was valued or specify that
something would be added to the royalty base. 61 The Sheppard and
Crain leases do both.

       59 Heritage Res., 939 S.W.2d at 121-23 (Baker, J.); id. at 130-31 (Owen,
J.) (plurality op.) (observing that “logic and economics tell us there are no
marketing costs to ‘deduct’ from value at the wellhead” and “[a]ll costs would
already be borne by the lessee”); see BlueStone Nat. Res. II, LLC v. Randle, 620
S.W.3d 380, 388 n.29 (Tex. 2021) (explaining how Justice Owen’s concurring
opinion became the plurality opinion on rehearing); see also Judice, 939 S.W.2d
at 136.
       60   See 643 S.W.3d 186, 202 (Tex. App.—Corpus Christi–Edinburg 2020).
       61 Heritage Res., 939 S.W.2d at 131 (Owen, J.) (plurality op.) (“There are
any number of ways the parties could have provided that the lessee was to bear
all costs of marketing the gas. If they had intended that the royalty owners
would receive royalty based on the market value at the point of delivery or sale,
they could have said so. If they had intended that in addition to the payment

                                       26
       We thus agree with the landowners that the Sheppard and Crain
leases are “proceeds plus” leases that employ a two-prong calculation of
the royalty base. First, the producers must properly determine their
gross proceeds from selling the production, which by definition must be
free of postproduction costs. Second, when the producers’ contracts,
sales, or dispositions state that enumerated postproduction costs or
expenses have been deducted in setting the sales prices, those costs and
expenses “shall be added to the . . . gross proceeds.” The words chosen
by the parties in these unique provisions demonstrate an intent and
expectation that some amount may be added to the producers’ gross
proceeds when calculating royalties.         This does not mean that any
“reduction or charge” for postproduction costs in the buyers’ subsequent
dispositions must be included in the royalty base ad infinitum. To the
contrary, Paragraphs 3(a), (b), and (c) contractually tether the royalty
obligation to the time and place where gross proceeds are realized.
       In so holding, we once again caution that, “[i]f anything is clear
from the many Texas decisions dealing with royalty provisions, it is that
different royalty provisions have different meanings,” 62 and the
construction of an oil-and-gas lease must ultimately be based
predominantly on the particular clause at issue construed within the

of market value at the well, the lessee would pay all post-production costs, they
could have said so. They did not. There is no direct statement in the leases
that the royalty owners are to receive anything in addition to the value of their
royalty, which is based on value at the well.”).
       62 Burlington Res., 573 S.W.3d at 206 (quoting Warren v. Chesapeake
Expl., L.L.C., 759 F.3d 413, 416 (5th Cir. 2014)).

                                       27
context of the lease as a whole. 63 Today, we address only the specific
language of the provisions before us as applied to the disputed issues on
appeal.
                                        B.
       In their final issue, the producers contend that even if some
post-sale postproduction costs must be included in determining the
royalties payable to the landowners, the court of appeals improperly
held that expenses for “transportation and fractionation” (T&F) are
among them. The appellate court did not address this issue because the
producers never argued that T&F costs should be treated differently
than other post-sale postproduction costs. Issues not briefed in the
appellate court are waived. 64
       Even if the issue were properly before us, it would fail on the
merits.        As    the   producers     concede    and    their     filings   and
summary-judgment evidence confirm, T&F is a “term of art” that refers
to transporting raw gas products to a downstream location for
fractionation, which is a type of processing to separate raw gas into
purer natural gas liquids like ethane, butane, propane, isobutane, and
natural gasoline. 65 Expenditures to “process” production are among the

       63Endeavor Energy Res., L.P. v. Energen Res. Corp., 615 S.W.3d 144,
155 (Tex. 2020).
       64   See Nall v. Plunkett, 404 S.W.3d 552, 556 (Tex. 2013).
       65  See Patrick H. Martin & Bruce M. Kramer, WILLIAMS & MEYERS,
MANUAL OF OIL AND GAS TERMS § 410.3 (Matthew Bender 2021) (defining
“[f]ractionation” as “[a] process of separating various hydrocarbons from
natural gas or oil as produced from the ground”); see also Petty Bus. Enters.,
L.P. v. Chesapeake Expl., L.L.C. (In re Chesapeake Energy Corp.), Nos.
20-33233, 20-3433, 2021 WL 4190266, at *7 (Bankr. S.D. Tex. Sept. 14, 2021)

                                        28
expressly enumerated postproduction costs that must be “added to”
“gross proceeds” under Paragraph 3(c). Even so, the producers maintain
that the failure to separately enumerate T&F as an expenditure
encompassed by Paragraph 3(c) evinces the contracting parties’ intent
to exempt it from the obligation to add those costs to gross proceeds
because other unique processes, like “treatment” and “manufacturing,”
are separately and expressly enumerated. This argument is fatally
flawed because Paragraph 3(c) is exhaustive and unmistakably clear
that the landowners’ royalty is to be free of “any costs or expenses” in
the producers’ sales contracts, with the only exception being the
landowners’ “pro rata share of severance or production taxes.” Because
T&F charges are processing costs and not severance or production taxes,
they are not excluded from Paragraph 3(c)’s ambit.
                             III. Conclusion
      The Sheppard and Crain leases employ atypical lease language to
unburden the landowners’ royalty from “any costs or expenses” by
requiring the producers to “add[] to . . . gross proceeds” all reductions or
charges for the “expenses or costs of production, treatment,
transportation, manufacturing, process[ing] or marketing” included in
the producers’ sales and marketing arrangements. The lease language
is broad and without limitation to only those costs incurred up to the
point of sale or by the producers. Because we must give effect to the
language the parties chose, we affirm summary judgment for the

(holding it “indisputable” that “the T&F Fee is a ‘reduction for any cost or
expense, including the cost or expense of producing, gathering, dehydrating,
compressing, transporting, manufacturing, processing, treating or
marketing’”).

                                    29
landowners on the disputed issues brought forward on appeal to this
Court.

                                     John P. Devine
                                     Justice

OPINION DELIVERED: March 10, 2023

                                30