Burlington Resources Oil & Gas Company Lp v. Texas Crude Energy, LLC and Amber Harvest, Llc

IN THE SUPREME COURT OF TEXAS
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No. 17-0266
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BURLINGTON RESOURCES OIL & GAS COMPANY LP, PETITIONER,
v.
TEXAS CRUDE ENERGY, LLC AND AMBER HARVEST, LLC, RESPONDENTS
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ON PETITION FOR REVIEW FROM THE
COURT OF APPEALS FOR THE THIRTEENTH DISTRICT OF TEXAS
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Argued October 9, 2018
JUSTICE BLACKLOCK delivered the opinion of the Court.
Amber Harvest, an affiliate of Texas Crude Energy, owns overriding royalty interests in
oil and gas leases operated by Burlington Resources. For several years, Burlington made royalty
payments only after charging the royalty holder its proportionate share of the post-production costs
expended to bring the products from the wells to the point of sale. Texas Crude later sued
Burlington, alleging that the parties’ contracts prohibit Burlington from charging post-production
costs to the royalty holder. Burlington contends that the contracts require the royalty holder to
bear its share of post-production costs. All parties agree that the relevant contracts are
unambiguous and therefore amenable to judicial interpretation.
The question before the Court resembles the question presented in Chesapeake
Exploration, L.L.C. v. Hyder, 483 S.W.3d 870 (Tex. 2016), another case in which the question was
whether a royalty interest bears its share of post-production costs. In Hyder, as in prior decisions,
this Court has emphasized that “the effect of a lease is governed by a fair reading of its text.” Id.
at 876 (discussing Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996)). We
interpreted the contract language at issue in Hyder to create a royalty interest free from post-
production costs. Id. Hyder and other decisions interpreting royalty agreements serve as
informative guides for today’s decision, but the decisive factor in each case is the language chosen
by the parties to express their agreement. See Heritage Res., 939 S.W.2d at 124 (Owen, J.,
concurring) (“Our task is to determine how those costs were allocated under these particular
leases.”). 1
The contractual language at issue in this case differs from the language at issue in Hyder.
The outcome also happens to be different. Construing the overlapping contractual provisions
based on the language the parties chose, we conclude that Burlington may deduct post-production
costs when calculating royalty payments. We therefore reverse the judgment of the court of
appeals and remand the case to the trial court for further proceedings.
I. Factual and Procedural Background
Petitioner is Burlington Resources Oil & Gas Co. LP (Burlington). Respondents are Texas
Crude Energy, LLC (Texas Crude) and its affiliate, Amber Harvest, LLC (Amber Harvest). In
2005, Burlington and Texas Crude executed a Prospect Development Agreement (PDA) and a
Joint Operating Agreement (JOA). The agreements applied to leases in an Area of Mutual Interest
(AMI) in the “Sugarloaf Prospect” located in parts of Live Oak, Karnes, and Bee Counties. Under
1
Justice Owen’s concurring opinion in Heritage Resources became the plurality opinion of the Court on
rehearing. See Hyder, 483 S.W.3d at 875 & n.25.
2
the PDA, Burlington would operate the entire field, and each party would receive a percentage of
the other’s working interests in leases either party had previously acquired in the AMI. Burlington
got 87.5% of the working interests, and Texas Crude got 12.5%. Each party agreed to offer the
other these same percentages if it acquired future leases in the AMI. Under the PDA and JOA,
Texas Crude received an overriding royalty interest, ranging from 0% to 6.25%, on leases within
the AMI. Texas Crude retained an overriding royalty interest on leases it originated, and it
assigned these interests to its affiliate, Amber Harvest. 2 On leases Burlington originated,
Burlington assigned an overriding royalty interest to Texas Crude, and Texas Crude later assigned
the interest to Amber Harvest. The overriding royalty interest assignments, whether from
Burlington to Texas Crude or from Texas Crude to Amber Harvest, contained substantially
identical language. Each assignment includes a clause the parties call the Granting Clause and a
clause the parties call the Valuation Clause. These clauses describe the disputed royalty interests.
The Granting Clause provides:
[Assignor] does hereby ASSIGN, TRANSFER AND CONVEY unto [Assignee],
its successors and assigns, those certain overriding royalty interests, as set out
below, in the quantity described below in all oil, gas, condensate, drip gasoline and
other hydrocarbons that may be produced and saved from those lands covered by
those certain oil, gas and mineral leases described in Exhibit “A” attached hereto
and made a part hereof for all purposes, and pursuant to the terms and conditions
of the said oil, gas and mineral leases. Said overriding royalty interests shall be
delivered to ASSIGNEE into the pipelines, tanks or other receptacles with which
the wells may be connected, free and clear of all development, operating,
production and other costs. However, ASSIGNEE shall in every case bear and pay
all windfall profits, production and severance taxes assessed against such
overriding royalty interest.
2
For simplicity we refer to the Respondents generally as Texas Crude when the difference between the two
entities is immaterial.
3
(emphasis added).
The Valuation Clause provides that the assignment “shall be subject to the following terms
and conditions”:
The overriding royalty interest share of production shall be delivered to ASSIGNEE
or to its credit into the pipeline, tank or other receptacle to which any well or wells
on such lands may be connected, free and clear of all royalties and all other burdens
and all costs and expenses except the taxes thereon or attributable thereto, or
ASSIGNOR, at ASSIGNEE’s election, shall pay to ASSIGNEE, for ASSIGNEE’s
overriding royalty oil, gas or other minerals, the applicable percentage of the value
of the oil, gas or other minerals, as applicable, produced and saved under the leases.
“Value”, as used in this Assignment, shall refer to (i) in the event of an arm’s length
sale on the leases, the amount realized from such sale of such production and any
products thereof, (ii) in the event of an arm’s length sale off of the leases, the
amount realized for the sale of such production and any products thereof, and (iii)
in all other cases, the market value at the wells.
(emphasis added).
The parties agree on two points that simplify the analysis: (1) the sales were arms-length,
and (2) Amber Harvest took its royalty payments in cash, not in kind. 3
For nine years, Amber Harvest and Texas Crude accepted royalty payments reflecting a
deduction for the royalty holder’s share of post-production costs. Disagreements later arose
regarding calculation of royalty payments and other matters. Citing the Valuation Clause’s
definition of “Value,” Texas Crude demanded a percentage of the sales price derived from arms-
length sales with no deduction for post-production costs. Under this theory, Texas Crude sought
3
Texas Crude contends that all the sales were off the leases, while Burlington contends the sales were both
on and off the leases. Because the relevant agreements establishing the royalty interest apply identical rules to arms-
length sales whether they occur on the lease or off the lease, this distinction does not affect our inquiry into whether
Burlington may deduct post-production costs when calculating royalty payments for arms-length transactions. The
location of the sales may, however, affect the amount of post-production costs expended. Off-lease sales would
presumably involve greater post-production costs than on-lease sales near the well. The record before the Court does
not establish the location of each sale. We reach no conclusions on the amount of post-production costs associated
with any given sale or on the amount Burlington must pay the royalty holder.
4
recovery of previously underpaid royalties. Burlington claimed the parties’ agreements—
including the Granting Clause, the Valuation Clause, the PDA, and the JOA—when read together
entitle it to deduct Texas Crude’s share of post-production costs from the royalty payments. On
cross-motions for partial summary judgment on this contract-interpretation question, the trial court
ruled for Texas Crude, concluding that the agreements do not permit Burlington to deduct post-
production costs. The trial court order decided only “the liability question of whether post-
production costs are deductible by Burlington when calculating overriding royalty payments to
Amber Harvest.” The trial court did not address other claims and did not address the amount of
damages owed to Texas Crude. Recognizing the existence of “substantial grounds for difference
of opinion regarding whether post-production costs are deductible by Burlington when calculating
overriding royalty payments to Amber Harvest,” the trial court authorized an interlocutory appeal
under TEX. CIV. PRAC. & REM. CODE § 51.014(d).
The court of appeals accepted the appeal, see id. § 51.014(f); TEX. R. APP. P. 28.3, and
affirmed the trial court’s judgment, Burlington Res. Oil & Gas Co. LP v. Texas Crude Energy,
LLC, 516 S.W.3d 638, 649 (Tex. App.—Corpus Christi 2017).
II. Analysis
The standard rules of contract construction apply to the overriding royalty interest
assignments 4 at issue. The Court’s task is to “ascertain the true intentions of the parties as
expressed in the writing itself.” Italian Cowboy Partners, Ltd. v. Prudential Ins. Co. of Am., 341
4
The parties executed assignments of overriding royalty interests as well as assignments of working interests
and perhaps other interests. Unless otherwise indicated, all references herein to “assignments” are references to
overriding royalty interest assignments from Burlington to Texas Crude or from Texas Crude to Amber Harvest.
5
S.W.3d 323, 333 (Tex. 2011). This analysis begins with the contract’s express language. Id. We
“examine and consider the entire writing in an effort to harmonize and give effect to all the
provisions of the contract so that none will be rendered meaningless.” Seagull Energy E & P, Inc.
v. Eland Energy, Inc., 207 S.W.3d 342, 345 (Tex. 2006) (quoting Coker v. Coker, 650 S.W.2d 391,
393 (Tex. 1983)) (emphasis omitted). We “give terms their plain, ordinary, and generally accepted
meaning unless the instrument shows that the parties used them in a technical or different sense.”
Heritage Res., 939 S.W.2d at 121. These guidelines apply to oil and gas agreements just as they
would to any other contract. See, e.g., id. (articulating rules of contract construction applicable to
a royalty agreement).
A. “Post-Production Costs”
In general, oil and gas royalty interests are free of production expenses but “usually subject
to post-production costs, including taxes . . . and transportation costs.” Hyder, 483 S.W.3d at 872
(quoting Heritage Res., 939 S.W.2d at 122). As in most situations, “the parties may modify this
general rule by agreement.” Id.; accord French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex.
2014). Before examining the parties’ arguments, we address briefly what it means for a royalty
interest to be “subject to post-production costs.”
Although parties to an agreement may define post-production costs any way they choose,
the term generally applies to processing, compression, transportation, and other costs expended to
prepare raw oil or gas for sale at a downstream location. Hyder, 483 S.W.3d at 875–76. Products
on which post-production costs have been expended are generally more valuable than products
straight out of the well. See, e.g., French, 440 S.W.3d at 3 (“[P]ostproduction processing that
makes the gas marketable enhances its value after it leaves the well.”). It follows that a royalty on
6
products at their downstream point of sale is more valuable than a royalty on the same products at
the well. See id. The crux of the parties’ dispute is whether Texas Crude holds royalties on
products at the well (Burlington’s position) or on treated and transported products at their
downstream point of sale (Texas Crude’s position).
The question of how to allocate post-production costs can arise when the sale used to
calculate the royalty payment is downstream from the point at which the royalty interest is valued.
If the royalty is valued at the well but the sale takes place after the product has been processed and
transported, the product sold is generally of greater value than the product in which the royalty
holder has an interest. See id. In this situation, the sales price must be adjusted to properly
calculate the royalty payment. See Heritage Res., 939 S.W.2d at 122–23. Courts have recognized
that one way to make this adjustment is to subtract the costs of bringing the product to the market
(the post-production costs) from the sale price obtained at the market. E.g., id. at 122 (explaining
that one method of calculating value at the well “involves subtracting reasonable post-production
marketing costs from the market value at the point of sale”); French, 440 S.W.3d at 3 (“The market
price of the processed gas reflects the value of the unprocessed gas at the well only if reasonable
postproduction processing costs are deducted.”). 5
Of course, the parties are free to contract for a royalty calculated based not on the value of
the oil and gas at the well but on its value at the point of sale. Heritage Res., 939 S.W.2d at 131
(Owen, J., concurring) (“If [the parties] had intended that the royalty owners would receive royalty
5
If the sale giving rise to the royalty payment took place at an upstream point before the expenditure of post-
production costs, then the sales price would already reflect the lower value of the product at that stage of development,
and there would be no costs to deduct. The sales price would already reflect the raw product’s lower value. See
French, 440 S.W.3d at 3; Heritage Res., 939 S.W.2d at 130 (Owen, J., concurring).
7
based on the market value at the point of delivery or sale, they could have said so.”) This is how
Texas Crude interprets its royalty interest. The holder of such a royalty would generally not be
responsible for post-production costs since those costs would have already been expended prior to
the sale. See, e.g., Hyder, 483 S.W.3d at 873.
Burlington emphasizes the oft-repeated statement that royalty interests usually bear post-
production costs. Hyder, 483 S.W.3d at 872; Heritage Res., 939 S.W.2d at 122. Texas Crude does
not quibble with this general proposition. Instead, it contends the parties contracted otherwise by
specifying that the royalty would be paid after sale of the product based on the “amount realized
from such sale,” not based on the product’s value at the well. This Court and other courts have
recognized that an agreement to value a royalty interest based on the “amount realized,” or similar
language, can grant the royalty holder the right to a percentage of the sale proceeds with no
adjustment for post-production costs. The majority opinion in Hyder stated that a royalty provision
giving lessors 25% of “the price actually received by Lessee” disallowed deduction of post-
production expenses because “it is based on the price [lessee] actually received for the gas through
its affiliate, Marketing, after postproduction costs have been paid” and because “the price-received
basis for payment in the lease is sufficient in itself to excuse the lessors from bearing
postproduction costs.” 483 S.W.3d at 871, 873. The Hyder dissent agreed with the majority that
this royalty of “25% of the price actually received . . . does not bear post-production costs.” Id. at
877 (Brown, J., dissenting). See also 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.”); Warren v.
Chesapeake Exploration, L.L.C., 759 F.3d 413, 417 (5th Cir. 2014) (Owen, J.) (explaining that,
8
under Texas law, “[h]ad the lease provided only that the [Lessors] are to receive 22.5% of the
amount realized by Lessee, there would be little question that the [Lessors] would be entitled to
22.5% of the sales contract price that the lessee received, with no deduction of post-production
costs.”).
According to Texas Crude, the “amount realized” language in the Valuation Clause creates
the kind of cost-free royalty mentioned in Hyder and Warren. First, it gives Texas Crude the
option to take its royalty in cash, which the parties agree Texas Crude has done. Next, it requires
Burlington to “pay to [Amber Harvest] . . . the value of the oil, gas or other minerals, as applicable,
produced and saved under the leases” (emphasis added). Finally, it defines “Value” as:
(i) in the event of an arm’s length sale on the leases, the amount realized from such
sale of such production and any products thereof, (ii) in the event of an arm’s length
sale off of the leases, the amount realized for the sale of such production and any
products thereof, and (iii) in all other cases, the market value at the wells.
(emphasis added). The parties agree the relevant sales were arms-length, so either (i) or (ii)
applies. Both (i) and (ii) define “value” as the “amount realized” for the sale. These subparts of
the definition make no mention of an upstream valuation point or responsibility for post-production
costs. Further, as Texas Crude argues, subparts (i) and (ii) reference “any products thereof,” and
subpart (ii) also references sales “off the leases.” As Texas Crude reads these provisions, they
necessarily refer to downstream sales since products from production at the well occur downstream
from the well, as do sales off the lease. Texas Crude is correct that for the arms-length cash sales
at issue, the provision boils down to an agreement that Burlington “shall pay to ASSIGNEE . . .
the applicable percentage of . . . the amount realized for the sale.” The court of appeals concluded
that this language creates a royalty free of post-production costs. 516 S.W.3d at 647. Viewed in
isolation, the Valuation Clause’s definition of “Value” provides considerable support for this
9
position. See, e.g., Warren, 759 F.3d at 417 (stating that an “amount realized” clause, standing
alone, would create a royalty interest free of post-production costs).
But we must examine the entire Valuation Clause in its context and in conjunction with
other clauses to which the parties agreed, including the immediately preceding Granting Clause.
Seagull Energy, 207 S.W.3d at 345; Heritage Res., 939 S.W.2d at 121 (“[W]e examine the entire
document and consider each part with every other part so that the effect and meaning of one part
on any other part may be determined.”). We have never held that an “amount realized” valuation
method frees a royalty holder from its usual obligation to share post-production costs even when
the parties have agreed to value the royalty interest at the well. The court of appeals incorrectly
suggested otherwise. It stated, “Even assuming that, under the granting clause, the [royalty] is
generally to be delivered ‘at the well,’ the parties are still free to allocate post-production costs as
they see fit.” 516 S.W.3d at 647 (citing Hyder, 483 S.W.3d at 874). This statement by the court
of appeals misunderstands our decision in Hyder. 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. E.g.,
Heritage Res., 939 S.W.2d at 123; id. at 129 (Owen, J., concurring); Judice v. Mewbourne Oil Co.,
939 S.W.2d 133, 136 (Tex. 1996); Warren, 759 F.3d at 417–18. This is generally the case even
when the agreement calls for payments based on the “amount realized” or “proceeds.” Id.
Allowing the holder of an “at the well” royalty to escape his responsibility for post-production
costs would improperly convert the royalty interest from a royalty on raw products at the well to a
royalty on refined, downstream products. Id.
10
B. The Parties’ Agreements
With these observations in mind, the dispositive question in this case is whether the parties
agreed to an “at the well” valuation point or its equivalent. If they did, Burlington is right that it
may deduct post-production costs when calculating royalty payments based on downstream sales
of treated and transported products. 6 If they did not, Texas Crude is entitled to a percentage of the
downstream sales price, without deductions, under the plain language of the Valuation Clause.
This question must be answered based on the language used in the agreements binding these
parties. See Warren, 759 F.3d at 416 (“[I]f anything is clear from the many Texas decisions dealing
with royalty provisions, it is that different royalty provisions have different meanings.”). Both
parties make plausible arguments. Ultimately, we are persuaded that Burlington’s position is more
faithful to all of the contractual language chosen by the parties and more aligned with the parties’
intent as expressed in writing. 7
As a preliminary matter, Burlington emphasizes the course of the parties’ performance of
the agreements. It alleges that Texas Crude accepted Burlington’s practice of deducting post-
production costs for years before raising an objection. But both parties moved for partial summary
judgment under the theory that the agreements are unambiguous. We agree. Where contracts are
6
For royalty payments based on sales at the well, there would presumably be little or no post-production
costs to deduct since none have been incurred.
7
Burlington suggests that it should not be bound by language in assignments between Texas Crude and its
affiliate Amber Harvest, assignments to which Burlington was not a party. As discussed above, under the various
agreements Burlington would either obtain a lease in the AMI and assign an overriding royalty interest to Amber
Harvest, or Texas Crude would originate the lease, retain a royalty interest, and assign that interest to Amber Harvest.
Burlington was not a party to assignments from Texas Crude to Amber Harvest. Texas Crude argues that the critical
language of all the assignments is identical and that Burlington drafted the language. Because we are ultimately
persuaded by Burlington’s understanding of its obligations under either set of assignments, we need not consider
whether Texas Crude’s interpretation of the assignments would bind Burlington even in assignments to which
Burlington is not a party.
11
unambiguous, we decline to consider the parties’ course of performance to determine its meaning.
Frost Nat’l Bank v. L & F Distribs., Ltd., 165 S.W.3d 310, 313 n.3 (Tex. 2005); E. Montgomery
Cty. Mun. Util. Dist. No. 1 v. Roman Forest Consol. Mun. Util. Dist., 620 S.W.2d 110, 112 (Tex.
1981) (per curiam). Burlington would need to contend the agreements are ambiguous before it
could rely on extrinsic course-of-performance evidence. It has not done so.
Burlington makes other, more persuasive arguments for its construction. Burlington points
to the Granting Clause’s provision that “overriding royalty interests shall be delivered to
ASSIGNEE into the pipelines, tanks or other receptacles with which the wells may be connected.”
Burlington argues that requiring delivery of the interest “into the pipelines, tanks, or other
receptacles” has the effect of requiring valuation of the interest “at the well.” Courts have often
interpreted the phrase “at the well” or “at the wellhead” to establish a wellhead valuation point,
which generally requires the royalty holder to bear post-production costs. See Heritage Res., 939
S.W.2d at 126–30 (Owen, J., concurring) (discussing Texas and out-of-state decisions). Texas
Crude counters that because the assignments make the Granting Clause “subject to” the Valuation
Clause, the Valuation Clause controls. According to Texas Crude, the Valuation Clause entitles it
to a percentage of the “amount realized” from the sale without deduction of post-production costs.
But even if we consider only the Valuation Clause, it too contains an “into the pipeline”
provision nearly identical to that found in the Granting Clause. The Valuation Clause provides:
“The overriding royalty interest share of production shall be delivered to ASSIGNEE or to its
credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be
connected . . . .” Burlington urges that “into the pipeline, tank or other receptacle” identifies the
valuation point for the royalty. This valuation point, according to Burlington, is essentially the
12
same as the “at the well” valuation point addressed in our previous decisions. See Hyder, 483
S.W.3d at 873 (“The oil royalty bears postproduction costs because it is paid on the market value
of the oil at the well.”); Heritage Res., 939 S.W.2d at 122–23; id. at 129 (Owen, J., concurring);
Judice, 939 S.W.2d at 135–36; Warren, 759 F.3d at 417.
The court of appeals declined to address the meaning of “into the pipeline, tank, or other
receptacle.” It reasoned that the “amount realized” calculation method forecloses deduction of
post-production costs “[e]ven assuming that, under the Granting Clause, the [royalty interest] is
generally to be delivered ‘at the well.’” 516 S.W.3d at 647. As explained above, this reasoning
misinterpreted our prior decisions involving “at the well” valuation points. See Heritage Res., 939
S.W.2d at 130 (Owen, J., concurring). A royalty on production valued at the well does not include
the value added by post-production costs. Id. 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. Id. If
Burlington is correct that the Granting Clause and the Valuation Clause establish the equivalent of
an “at the well” valuation point, then Burlington is also correct that it may subtract post-production
costs from downstream sales prices when calculating royalty payments.
The outcome of this case therefore turns on whether Burlington correctly interprets the
“into the pipeline” provisions. Textually, Burlington’s view is defensible. The agreements twice
provide that the royalty interest “shall be delivered . . . into the pipelines, tanks, or other
receptacles.” A sensible reading of this rather abstruse provision is that the “pipelines, tanks, or
other receptacles” are the physical spot at which Texas Crude’s interest in the products arises.
Moreover, several authors familiar with industry practices seem to agree with Burlington that a
13
provision for delivery “into the pipeline” contemplates valuation at the well and therefore
authorizes deduction of post-production costs. 8 One treatise states that under an agreement
“providing for delivery ‘free of cost in the pipe line to which Operator may connect his wells,’ the
expense of transportation or of treating oil or gas or of compressing gas to make it deliverable must
be shared by the owner of the nonoperating interest.” This language “suggests that the parties
assumed that a pipe line connection at the well would be available,” and the lessor’s duties “will
not include the burden of bearing the expense of treating, compressing or transporting [the
nonoperator’s] share of production.” 3 HOWARD R. WILLIAMS & CHARLES J. MYERS, OIL AND GAS
LAW § 646.2 (Patrick H. Martin & Bruce M. Kramer, eds., 2018) (footnote omitted). Another
treatise noted, as a general matter, “[i]f the royalty clause provides for delivery of royalty gas to
the lessor’s credit free of cost in the pipeline to which the well is connected, the parties contemplate
a delivery of royalty gas at the well.” 3 EUGENE KUNTZ, TREATISE ON THE LAW OF OIL AND GAS
§ 40.5(a) (1989). Another commentator similarly recognized an equivalence between “in the pipe
line” and “at the wells” clauses, noting that “some leases provide that the royalty oil may be
delivered in the pipe line to which the wells may be connected, ‘or at the wells,’ or ‘into storage
tanks.’ It would seem, under this clause, that the lessee’s obligations are at an end when he has
made a delivery at the place designated, and that the expense of storage and transportation
thenceforth must be borne by the lessor.” A. W. Walker, Jr., Nature of the Property Interests
Created by an Oil and Gas Lease in Texas, 10 TEX. L. REV. 291, 313 (1932). While the parties
8
In interpreting unambiguous mineral-interest deeds and contracts, we sometimes refer to treatises and other
scholarly sources that provide views on the meaning of technical terms or terms commonly used by the industry. E.g.,
Wenski v. Ealy, 521 S.W.3d 791, 796 (Tex. 2017); Tittizer v. Union Gas Corp., 171 S.W.3d 857, 861 (Tex. 2005) (per
curiam); Temple-Inland Forest Prods. Corp. v. Henderson Family P’ship, Ltd., 958 S.W.2d 183, 186 (Tex. 1997);
Heritage Res., 939 S.W.2d at 121–22.
14
point to no judicial decision interpreting an “into the pipeline” clause like the one at issue here,
these commentaries lend further credence to Burlington’s textually defensible understanding of
this contractual term.
Burlington finds further support for its position in the JOA, which the parties executed at
the outset of their venture. Burlington contends that the following provision in the JOA is
consistent with its interpretations of the Granting Clause and Valuation Clause:
Each party shall have the right but not the obligation to take in kind or separately
dispose of its proportionate share of the oil and gas produced from the Contract
Area . . . . In the event any party shall fail to make the arrangements necessary to
take in kind or separately dispose of its proportionate share of the oil and/or gas
produced from the Contract Area, Operator shall have the right, subject to the
revocation at will by the party owning it, but not the obligation, to purchase such
oil and/or gas or sell it to others at any time and from time to time, and shall account
to such party for the actual net proceeds received for such production if sold to a
non-affiliated third party in an arm’s length transaction, or the current market price
if purchased by Operator or an affiliate of Operator.
(emphasis added). Burlington argues that “actual net proceeds” from a sale means net of post-
production costs. We agree that this language provides additional support to Burlington’s view
that the royalty payments should be made net of post-production costs. Burlington does not argue
that the JOA would control over contrary language in the assignments. Instead, it argues that our
interpretation of the assignments should take the JOA into account and attempt to harmonize its
provisions with the assignments. This is correct. “Under generally accepted principles of contract
interpretation, all writings that pertain to the same transaction will be considered together, even if
they were executed at different times and do not expressly refer to one another.” DeWitt Cty. Elec.
Coop., Inc. v. Parks, 1 S.W.3d 96, 102 (Tex. 1999); accord Fort Worth Indep. Sch. Dist. v. City of
Fort Worth, 22 S.W.3d 831, 840 (Tex. 2000). In addition to this general principle in favor of
harmonizing related agreements, here some of the assignments are expressly made “pursuant to
15
the terms and conditions of” the JOA or the PDA. The PDA is “subject to the terms of” the JOA.
And the JOA provides that subsequent transfers and assignments of any party’s interests shall be
subject to the JOA. All this express language indicates that the parties intended their agreements
to be construed together. We should therefore consider the JOA when construing the assignments.
The JOA contemplates that each party will account to the other for the “actual net proceeds
received from such production.” We have previously interpreted a “net proceeds” royalty
provision to authorize deduction of post-production costs. Judice, 939 S.W.2d at 137. Thus, the
JOA appears to contemplate, albeit obliquely, that later-assigned royalty interests would be
calculated net of post-production costs. This lends additional support to Burlington’s view that
the assignments should be interpreted to create a royalty that bears post-production costs.
The court of appeals reasoned that the later executed assignments of royalty interests
override the JOA under the “merger doctrine.” Burlington Res., 516 S.W.3d at 646–47. The
merger doctrine provides that “[w]hen a deed is delivered and accepted as performance of a
contract to convey, the contract is merged in the deed.” Alvarado v. Bolton, 749 S.W.2d 47, 48
(Tex. 1988). Whether the parties intended the relatively brief assignment agreements to render the
JOA—and its scores of highly detailed provisions—a nullity is questionable. See Fish v. Tandy
Corp., 948 S.W.2d 886, 898 (Tex. App.—Fort Worth 1997, pet. denied) (stating that application
of merger doctrine is “largely a matter of intention of the parties”). And even if the merger doctrine
could apply to these agreements, we need not consider it here. The doctrine operates when earlier
contracts “are contradicted in the deed.” Alvarado, 749 S.W.2d at 48. Because the JOA is
consistent with our interpretation of the assignments, the merger doctrine is inapplicable.
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Texas Crude argues that the “net proceeds” language from the JOA only applies to working
interests, not overriding royalty interests. But we see no such express limitation in the JOA. To
the contrary, the JOA provides for overriding royalty interests to Texas Crude 9 and applies to
“[e]very sale, encumbrance, transfer or other disposition made by any party.” Further, the
assignments of overriding royalty interests state that they are “made pursuant to the terms and
conditions” of the JOA or the PDA. And the PDA states that “[a]ll interests acquired in the AMI
shall be subject to the terms of [the] JOA.”
Texas Crude understands the “into the pipeline” provisions in the Valuation and Granting
Clauses to apply only to in-kind transfers. Under this reading, the first portion of the Valuation
Clause applies only to in-kind transfers, while the rest of the clause applies only to cash royalties.
This reading is not absurd, but for several reasons it is less convincing than the alternative. First,
while oil and gas agreements are not known for their clarity and simplicity, the parties surely could
have used the words “in kind” or similar words if they intended to create one set of rules for in-
kind royalties and another for in-cash royalties. The JOA explicitly references in-kind transfers,
as noted above, showing that the parties were capable of using that term when needed. Second,
Texas Crude’s construction renders the second sentence of the Granting Clause—which contains
the “into the pipeline” provision—ineffective except in the unusual circumstance that the royalty
holder chooses to take delivery of the interest in kind. Texas Crude never took its overriding
royalty in kind, yet it understands the second sentence of the Granting Clause to apply only to
hypothetical in-kind transactions. But nothing in the Granting Clause’s second sentence suggests
9
For example, Article III(D) of the JOA governs the effect of creation of subsequent or undisclosed
interests—including overriding royalty interests—on the parties. Article XV(K)(4) gives Texas Crude the right to
retain or be assigned overriding royalty interests or all leasehold interests within the AMI.
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it was intended to apply only to a small subset of transactions. To the contrary, the Granting Clause
is the opening provision of the assignment and reads like a general statement of the nature of the
royalty interest conveyed. It makes no distinction between in-kind and in-cash royalties, and it
provides that the “overriding royalty interests shall be delivered to ASSIGNEE into the pipelines,
tanks or other receptacles with which the wells may be connected.” On its face, this provision
applies to “the overriding royalty interests,” not to a subset or category of them. Texas Crude’s
proposed limitation of the provision to in-kind transfers would relegate its broadly applicable
language to irrelevant surplusage in most instances. On the other hand, Burlington’s view that the
“into the pipeline” provision creates an “at the well” valuation point gives the provision the broad
effect it seems intended to have and allows the provision to be applied to the actual transactions
that occurred among these parties. 10
Another problem with Texas Crude’s interpretation is that it makes responsibility for post-
production costs—and therefore the value of the royalty—dependent on whether Burlington
conducts arms-length sales or sells to an affiliate. If Burlington makes a non-arms-length sale to
an affiliate, then under the Valuation Clause Texas Crude would only receive the “market value at
the wells.” But in the case of an arms-length sale, according to Texas Crude, Burlington cannot
deduct post-production costs and Texas Crude receives a share of the proceeds regardless of how
10
Of course, neither party advocates the most literal reading of the “into the pipeline” provision, which
mandates an absurdity. How can the royalty interest—not the oil itself but the royalty interest, an incorporeal
concept—be “delivered . . . into the pipelines, tanks, or other receptacles”? We conclude that the rules of contract
construction favor Burlington’s interpretation of this recondite clause. But the parties could have saved considerable
time, money, and heartache if their cryptic language had truly been “delivered . . . into the . . . receptacle[].” It could
then have been re-written to say exactly what the parties intend, without resort to industry jargon, outdated legalese,
or tenuous assumptions about how judges will interpret industry jargon or outdated legalese. If you can’t understand
what your contract means without asking the lawyer who wrote it, you should not be surprised later if judges—who
can’t just take your lawyer’s word for it—also have trouble understanding what it means.
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much has been expended to increase the value of the product. Texas Crude’s construction would
encourage the operator, Burlington, not to make arms-length sales, an odd result that Texas Crude
as royalty holder would not likely have bargained for ex ante.
Further, under Texas Crude’s construction, if Burlington made a sale to a third party “on
the lease,” pricing the sale at the wellhead price and leaving the third party to make post-production
enhancements, the royalty payment would be based on the wellhead price because the “amount
realized” would be based on that price. But if Burlington conducted its own post-production
enhancements, it would not be allowed to deduct the costs of these enhancements, and Texas Crude
would receive a higher royalty. We can see no reason why the parties would reward the operator
for leaving post-production efforts to a third party and penalize the operator for doing these
enhancements itself. And we can see no reason why parties would make the nature of the royalty
holder’s interest dependent on decisions by the operator over which the royalty holder has no
influence.
Yet another strange result would follow from Texas Crude’s construction. If, as Texas
Crude contends, the references in the Granting and Valuation Clauses to delivery “into the
pipelines, tanks or other receptacles” only cover in-kind transfers, then an in-kind distribution
would give Texas Crude its royalty percentage of production at the well. But an arms-length sale
off the lease would give Texas Crude a higher royalty based on the downstream price after post-
production enhancements. Under this construction, Burlington would be penalized for marketing
Texas Crude’s share of production, finding a third-party buyer, transporting the product, and
performing other post-production enhancements. It is difficult to fathom why either party would
have intended such a result.
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Of course, the parties were free to contract for these odd results, and we have recognized
“that lease drafters are not always driven by logic.” Hyder, 483 S.W.3d at 874. But these parties
did not do that. Our best reading of the contractual text supports Burlington’s position. The
implausible results that flow from Texas Crude’s position merely reinforce this result.
If, as Burlington contends, the assignments require valuation at the well in all cases, one
might question why the Valuation Clause has three subparts—two specifying valuation based on
the “amount realized” and the last based on “market value at the wells.” Burlington plausibly
argues that all subparts place the valuation point at the well, but for arms-length sales the amount
realized from actual sales must be used to calculate the value at the well. On the other hand, for
sales to an affiliate—which the royalty holder might worry do not reflect full market value—the
valuation of the royalty is not based on the actual sales price but instead requires an objective
calculation of market value. See Heritage Res., 939 S.W.2d at 122 (describing comparable sales
as the most desirable method of calculating market value at the well); id. at 130 (Owen, J.,
concurring).
Finally, Burlington’s construction mirrors the result reached by the Fifth Circuit in Warren,
a factually similar case. There, as here, the agreement provided that the royalty holder would
receive a percentage of the “amount realized” by the lessee. But this language was modified with
language that the amount realized shall be “computed at the mouth of the well,” leading the court
to conclude that “the royalty is based on net proceeds, and the physical point to be used as the basis
for calculating net proceeds is the mouth of the well.” 759 F.3d at 417. Therefore, the lessee could
“deduct from sales proceeds the reasonable cost of post-production costs incurred in delivering
marketable gas from the mouth of the well to the actual point of sale.” Id. at 418. If, as we
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conclude, these parties intended their “into the pipeline” clauses to place the royalty valuation
point at or near the well, Warren is consistent with Burlington’s interpretation of the assignments.
To sum up, the Valuation Clause specifies that the royalty payment shall be calculated
based on the “amount realized” from the sale, but the agreements also provide that the royalty
interest shall be delivered “into the pipelines, tanks, or other receptacles with which the wells may
be connected.” In the context of these agreements, this latter term fixes the royalty’s valuation
point at the physical spot where the interest must be delivered—at the wellhead or nearby. This
gives Burlington the right to subtract post-production costs from the “amount realized” in
downstream sales prices in order to calculate the product’s value as it flows “into the pipelines,
tanks or other receptacles with which the wells may be connected.” See Hyder, 483 S.W.3d at
873; French, 440 S.W.3d at 3; Heritage Res., 939 S.W.2d at 122–23.
III. Conclusion
We find ourselves once again tasked to construe an opaquely worded oil and gas
agreement. While both sides present well-reasoned arguments, we conclude that Burlington’s
construction of the royalty assignments is correct. The assignments permit Burlington to charge
Texas Crude its proportionate share of post-production expenses when calculating royalty
payments. The judgment of the court of appeals is reversed and the case is remanded to the trial
court for further proceedings consistent with this opinion.
__________________________________
James D. Blacklock
Justice
OPINION DELIVERED: March 1, 2019
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