ConocoPhillips Co. v. Lyons , 3 N.M. 700 ( 2012 )

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integrity of this document
New Mexico Compilation
Commission, Santa Fe, NM
'00'04- 16:49:19 2013.04.29
IN THE SUPREME COURT OF THE STATE OF NEW MEXICO
Opinion Number: 2013-NMSC-009
Filing Date: August 24, 2012
Docket No. 32,624
CONOCOPHILLIPS COMPANY and
BURLINGTON RESOURCES OIL & GAS COMPANY, L.P.,
Plaintiffs-Appellees,
v.
PATRICK H. LYONS, Commissioner of
Public Lands of the State of New Mexico,
Defendant-Appellant.
CERTIFICATION FROM THE NEW MEXICO COURT OF APPEALS
Gary L. Clingman, District Judge
The Branch Law Firm
Turner W. Branch
Albuquerque, NM
Gary K. King, Attorney General
Santa Fe, NM
Law Offices of Brian K. Branch
Brian K. Branch
Albuquerque, NM
Robert Allen Stranahan, IV
Katherine Mary Moss
Santa Fe, NM
Susman Godfrey, L.L.P.
Thomas Wallace Patterson
Houston, TX
for Appellant
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Campbell Trial Law, L.L.C.
Michael Campbell
Santa Fe, NM
Holland & Hart, L.L.P.
Mark F. Sheridan
Robert Jackson Sutphin, Jr.
Santa Fe, NM
Rothstein, Donatelli, Hughes, Dahlstrom, Schoenburg & Bienvenu, L.L.P.
Kristina Elena Martinez
Santa Fe, NM
for Appellee
OPINION
MAES, Chief Justice.
{1} This litigation stems from a dispute over the proper calculation of royalty payments
on state oil and gas leases. In New Mexico, the Commissioner of Public Lands
(Commissioner) “is hereby authorized to execute and issue in the name of the state of New
Mexico, as lessor, leases for the exploration, development and production of oil and natural
gas, from any lands belonging to the state of New Mexico, or held in trust by the state under
grants from the United States of America.” NMSA 1978, § 19-10-1 (1953). In a typical oil
and gas lease, lessees are granted the right to extract and sell oil and gas derived from State
lands; in return, lessees pay the State a royalty. Oil and gas leases may specify payment of
royalty upon a number of different measures; among them are net proceeds, gross proceeds
and market value. See Brian S. Wheeler, Deducting Post-Production Costs When
Calculating Royalty: What Does the Lease Provide?, 8 Appalachian J.L. 1, 6 (2008).
{2} In New Mexico the language of the State oil and gas leases is prescribed by statute.
Over the years, the Legislature has enacted several versions of the statutory oil and gas lease,
and Lessees have entered into “hundreds” of oil and gas leases with the State. Specifically,
the New Mexico Legislature enacted statutory oil and gas leases in 1919, 1925, 1927, 1929,
1931, 1945, 1947, and 1984. See 1919 N.M. Laws, ch. 98, § 1; 1925 N.M. Laws, ch.137,
§§ 1-13; 1927 N.M. Laws, ch. 46, §§ 1-4; 1929 N.M. Laws, ch.125, § 1; 1931 N.M. Laws,
ch. 18, § 2; 1945 N.M. Laws, ch. 111, § 1; 1947 N.M. Laws, ch. 200, § 1; 1985 N.M. Laws,
ch.195, § 3.
{3} The present appeal concerns the royalty clauses contained in the 1931 and the 1947
statutory lease forms. 1931 N.M. Laws, ch. 18, § 2 (1931 lease) and 1947 N.M. Laws, ch.
200, § 1 (1947 lease). The royalty clause of the 1931 lease states, in relevant part:
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2. The lessee agrees to pay the lessor the one-eighth of the net
proceeds derived from the sale of gas from each well. If casing-head gas
produced from said land is sold by the lessee, the lessee shall pay the lessor
as royalty one-eighth of the net proceeds of said sale; if casing-head gas
produced from said lands is utilized by the lessee otherwise than for carrying
on the lessee’s operations for producing oil or gas from said lands, then the
lessee shall pay the lessor the market value in the field of the equal one-
eighth part of the casing-head gas so utilized at the time of such utilization.
1931 N.M. Laws, ch. 18, § 2. The royalty clause of the 1947 statutory lease form provides,
in relevant part:
2. Subject to free use without royalty, as hereinbefore provided, the
lessee shall pay the lessor as royalty one-eighth of the cash value of the gas,
including casinghead gas, produced and saved from the leased premises and
marketed or utilized, such value to be equal to the greater of the following
amounts:
(a) the net proceeds derived from the sale of such gas in the field, or
(b) five cents ($.05) per thousand cubic feet (m.c.f.) . . . ;
Provided, however, the cash value for the royalty purposes of carbon dioxide
gas and of hydrocarbon gas delivered to a gasoline plant for extraction of
liquid hydrocarbons shall be equal to the net proceeds derived from the sale
of such gas, including any liquid hydrocarbons recovered therefrom.
1947 N.M. Laws, ch. 200, § 1. Both the 1931 lease and 1947 lease specify that the payment
of royalty is to be calculated as a percentage of the “net proceeds” resulting from the sale of
gas. By definition, “net proceeds” constitutes “the sum remaining from gross proceeds of
sale minus payment of expenses.” Wheeler, supra, at 6. Therefore, it is clear that the
statutory lease forms contemplate the deduction of certain costs.
{4} During 2005 and 2006, Commissioner audited ConocoPhillips Company’s
(ConocoPhillips) and Burlington Resources Oil & Gas Company’s (Burlington) (together,
Lessees) royalty payments. Following the Audit, Commissioner notified Lessees that they
had been underpaying their royalty obligations and issued them assessments for the
underpayment.
{5} Commissioner claimed that pursuant to the terms of the statutory lease forms Lessees
could not deduct the post-production costs necessary to prepare the gas for the commercial
market when calculating their royalty payments. Commissioner claimed that the improper
deductions for post-production costs resulted in ConocoPhillips underpaying royalties by
approximately $18.9 million and Burlington underpaying by approximately $5.6 million.
In response to Commissioner’s audit and assessments, Lessees filed a complaint in the
district court seeking a declaration that Commissioner’s assessment of additional royalty
constituted a deprivation of due process, an unconstitutional impairment of contract, and
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breach of contract. In addition, Lessees claimed that Commissioner had exceeded his
constitutional and statutory powers by issuing the assessments and had effectively usurped
legislative power by seeking royalty payments under calculation methods not approved by
the Legislature. In response, Commissioner alleged a host of counterclaims for breach of
contract, breach of the implied covenant of good faith and fair dealing, and breach of the
implied covenant to market. In addition, Commissioner sought a declaratory judgment, an
accounting, an injunction, and the cancellation of leases. Lessees sought, and the district
court granted, summary judgment on several matters.
{6} This appeal centers around three orders granting summary judgment on behalf of
Lessees and a fourth order denying Commissioner’s motion for reconsideration of the district
court’s previous dismissal of his counterclaim for breach of the implied covenant to market.
The district court certified these orders for interlocutory appeal pursuant to NMSA 1978,
Section 39-3-4 (1999). The Court of Appeals then certified this appeal as a matter of
“substantial public interest” to this Court pursuant to NMSA 1978, Section 34-5-14(C)(2)
(1972) and Rule 12-606 NMRA. We accepted certification, and we now address the district
court’s four certified orders.
{7} In the first order, the district court granted Lessees’ motion for summary judgment
on the meaning of three provisions in the 1931 and 1947 leases: the “net proceeds” royalty
obligation, the “free use” clause, and Lessees’ obligation to pay royalty on drip condensate.
In the second order, the district court granted Lessees’ motion for summary judgment on the
meaning of the maximum price clause found in the 1947 lease form. In the third order, the
district court denied Commissioner’s motion for reconsideration of the district court’s
previous dismissal of Commissioner’s claim for breach of the implied covenant to market.
In the last order, the district court granted Lessees’ motion for summary judgment on the
deduction of reasonable costs of affiliated transactions in calculating royalty in State oil and
gas leases, finding that the cost of post-production services provided by Lessees’ affiliates
is deductible to the extent it is “reasonable.”
STANDARD OF REVIEW
{8} Because three of the certified orders deal with motions for summary judgment, we
first address the standard of review applicable to those motions. This Court reviews “a
district court’s decision to grant summary judgment de novo.” Maralex Res., Inc. v.
Gilbreath, 2003-NMSC-023, ¶ 8, 134 N.M. 308, 76 P.3d 626. Summary judgment is proper
when “there are no genuine issues of material fact and the movant is entitled to judgment as
a matter of law.” Self v. United Parcel Serv., Inc., 1998-NMSC-046, ¶ 6, 126 N.M. 396, 970
P.2d 582. We review “the pleadings, affidavits, and depositions presented for and against
a motion for summary judgment in a light most favorable to the nonmoving party.” Deaton
v. Gutierrez, 2004-NMCA-043, ¶ 12, 135 N.M. 423, 89 P.3d 672.
{9} The district court found certain disputed contractual language contained in the 1931
and 1947 lease forms to be “unambiguous.” Whether contractual terms are ambiguous is
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a question of law, subject to de novo review. Envtl. Control, Inc. v. City of Santa Fe, 2002-
NMCA-003, ¶ 14, 131 N.M. 450, 38 P.3d 891. “The standard to be applied in determining
whether a contract [term is ambiguous and] is subject to equally logical but conflicting
interpretations is the same standard applied in a motion for summary judgment.” Randles
v. Hanson, 2011-NMCA-059, ¶ 26, 150 N.M. 362, 258 P.3d 1154 (internal citation omitted).
Courts will grant summary judgment and “interpret the meaning as a matter of law” when
the “evidence presented is so plain” that it is only reasonably open to one interpretation. Id.
¶ 26. If, however, a court determines that the contract is “reasonably and fairly” open to
multiple constructions, then “an ambiguity exists,” summary judgment should be denied, and
the jury should resolve all “factual issues presented by the ambiguity.” Id.
{10} In making the threshold determination regarding ambiguity, courts may consider
“evidence of the circumstances surrounding the making of the contract and of any relevant
usage of trade, course of dealing, and course of performance.” C.R. Anthony Co. v. Loretto
Mall Partners, 112 N.M. 504, 508-09, 817 P.2d 238, 242-43 (1991). “[I]f the proffered
evidence of surrounding facts and circumstances is in dispute, turns on witness credibility,
or is susceptible of conflicting inferences, the meaning must be resolved by the appropriate
fact-finder . . . .” Mark V, Inc. v. Mellekas, 114 N.M. 778, 781, 845 P.2d 1232, 1235 (1993).
DISCUSSION
{11} Before we begin our review of the district court’s findings we will briefly discuss the
natural gas production process. When gas is extracted from a well, it is in a form that is not
commercially merchantable. In order to be sold on the commercial market, the gas must be
processed. The processing of natural gas begins at the wellhead. See Natural Gas
Processing: The Crucial Link Between Natural Gas Production and Its Transportation to
Market, Energy Information Administration, Office of Oil and Gas, January 2006, 2,
available at http://www.arcticgas.gov/sites/default/files/documents/
2006-eia-ng-processing.pdf. The wellhead is the location at which the gas is extracted from
the ground. See 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law, at 1143
(2011) (defining wellhead as “where the mineral product is severed or removed from the
ground”). Once the gas is extracted from the ground, several processes may be necessary
to transform the gas into a merchantable product. These processes include: gathering,
compressing, dehydrating, and treating the gas. The expenses associated with these
processes are referred to as “post-production costs.” See 8 Williams & Meyers, supra, at
787 (citing Schroeder v. Terra Energy, Ltd., 565 N.W.2d 887, 890 (Mich. Ct. App. 1997),
which defined post-production costs as “costs associated with making the natural gas
marketable after the gas is severed or removed from the ground”).
{12} Oil and gas wells produce various types of gas: casinghead gas, conventional gas,
and coalbed methane gas. Gas that is produced from an oil well is casinghead gas. 8
Williams & Meyers, supra, at 132. In processing casinghead gas, the oil and gas are
separated and the gas stream is measured by a meter near the wellhead. The meter measures
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the volume of the gas stream and its heat content. The heat content provides information
regarding how much natural gas liquids (NGLs) are present in the gas stream. The gas is
then transported from the meter to a processing plant or treatment facility via pipelines or
gathering lines. In order for the gas to move through the gathering lines to the processing
plants, the gas must be compressed at compression stations along the pipelines. When the
gas reaches the processing or treatment facility the NGLs are extracted. The NGLs are then
sent further downstream for fractionation. See 8 Williams & Meyers, supra, at 405 (defining
fractionation as “[a] process of separating various hydrocarbons from natural gas or oil as
produced from the ground”). During fractionation the NGLs are segregated into their
individual components, which are then sold. After the NGLs are extracted, the remaining
gas, or the residue gas, is pure methane gas, which is then sent through different pipelines
to various places throughout the country.
{13} Conventional gas is similar to casinghead gas, except that conventional gas is
produced from a gas well, whereas casinghead gas is produced from an oil well. This gas
moves through a separator during which some hydrocarbon liquids drip out. These
hydrocarbon liquids, or drop out liquids, are sold as oil with royalties then paid on the drop
out liquids as oil. After the separation, the gas is then processed in the same manner as
casinghead gas.
{14} Coalbed methane gas is gas produced from coal seams and contains carbon dioxide.
8 Williams & Meyers, supra, at 152. This gas is gathered, compressed, and transported to
the treatment plant where the carbon dioxide is removed from the methane. After the carbon
dioxide is separated, the methane is sent down stream via the pipelines. Coalbed methane
gas does not contain any NGLs.
Order 1: Summary Judgment on the Meaning of Net Proceeds Royalty Obligation, the
Free Use Clause, and the Drip Condensate Royalty Obligation
{15} The district court’s order granting summary judgment determining the meaning of
the free use clause and the extent of the Lessees’ obligation to pay royalties on drip
condensate was based on its interpretation of the net proceeds language. We, therefore,
begin our review with the district court’s findings regarding the meaning of the net proceeds
royalty obligation.
1. Net Proceeds
{16} “Net proceeds” is defined as “the sum remaining from gross proceeds of [a] sale
minus [the] payment of expenses” and “expressly contemplates deductions.” Wheeler,
supra, at 6; see also Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 445 (Tex. App.
2006) (stating net proceeds “expressly contemplates deductions”). Here, the parties do not
dispute that the term net proceeds contemplates deductions. Instead, the parties’
disagreement regarding the net proceeds language centers around what costs may be taken
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into account when calculating Lessees’ royalty obligations and the point in time at which the
value of the gas is fixed for the purpose of calculating the royalty obligation.
{17} In oil and gas leases it is typical for the royalty clause to specify the calculation of
net proceeds “at the well.” Scott Lansdown, The Marketable Condition Rule, 44 S. Tex. L.
Rev. 667, 671 (2002-2003) (emphasis added) (internal citation omitted). When the well is
specified as the point of valuation, it is generally understood that the “lessee is entitled to
deduct all costs that are incurred subsequent to production, including those necessary to
transport the gas to a downstream market and those costs, such as dehydrating, treating, and
processing the gas, that are either necessary to make the gas saleable in that market or that
increase the value of the gas.” Lansdown, supra, at 672 (footnote omitted). In Ramming v.
Natural Gas Pipeline Co. of America, the Fifth Circuit interpreted a 1930 and a 1937 lease
form which specified for royalty to be calculated based on “net proceeds from sales at the
mouth of the well.” 390 F.3d 366, 369 (5th Cir. 2004). The court concluded that such
language prohibited lessees from deducting costs incurred prior to production (i.e., those
costs necessary to extract the gas from the land), but permitted the deduction of post-
production costs (i.e., those costs incurred following extraction of the gas from the ground).
Id.
{18} New Mexico courts have also endorsed this approach to interpreting a royalty
obligation when the language provides that such payments are to be payable on net proceeds
at the well. See Creson v. Amoco Prod. Co., 2000-NMCA-081, ¶¶ 11-12, 129 N.M. 529, 10
P.3d 853. In Creson, the lease specified for the payment of royalties on “net proceeds
derived from the sale of Carbon Dioxide Gas at the well.” Id. ¶ 6. The Court of Appeals
held that the language was “unambiguous,” id. ¶ 15, and permitted lessees to deduct the costs
of post-production expenses incurred after the gas exited the wellhead, id. ¶ 24.
{19} Thus, if the 1931 and 1947 statutory lease forms provided for royalty on net proceeds
at the well, there would be little controversy because such language typically entitles the
lessee to deduct all post-production expenses. See Lansdown, supra, at 671. However, the
lease forms at issue here provide for royalty to be paid on net proceeds “from the sale of
such gas in the field” (1947 lease) and “from the sale of gas from each gas well” (1931
lease). Thus, the key question is whether a lease which provides for royalty payable upon
“net proceeds . . . in the field” or “from the sale of gas from each gas well” compels a
different royalty calculation than a lease which provides for “net proceeds . . . at the well.”
{20} The district court determined that the net proceeds royalty obligation contained in the
1931 and 1947 lease forms was unambiguous and found that Lessees may “net (deduct) from
their gross sales price any post-production costs they reasonably and necessarily incur in
selling the gas . . . whether the gas sold is casinghead gas, conventional gas or coalbed
methane gas, and whether the sale occurs at the wellhead, the plant tailgate or farther
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downstream.”1 The district court found that its interpretation was confirmed by the
circumstances contemporaneous to the enactment of the 1931 and 1947 leases, subsequent
lease forms enacted by the Legislature, subsequent regulatory policy, and the course of
performance and dealing between Lessees and Commissioner. Furthermore, the district
court found it could not follow Commissioner’s interpretation of the statutory lease forms
because such an interpretation imposed an additional royalty obligation on Lessees, an action
which can only be taken by the Legislature.
{21} Commissioner asserts that the district court’s interpretation of the net proceeds
royalty obligations is erroneous as the express language of the lease forms sets the valuation
point “in the field” and prevents Lessees from deducting any post-production expenses
incurred between the wellhead and the field, i.e., plant tailgate, when calculating royalty
payments. Commissioner submits that the “in the field” language requires the use of a net-
back methodology, with the “field,” or plant tailgate, as the valuation point, before which
deductions cannot be taken. See Wheeler, supra, at 5 (providing that under the work-back
or net-back method, “the costs of transportation, processing and treatment are deducted from
the ultimate proceeds of sale of the oil or gas and any extracted or processed products to
ascertain wellhead value”). Commissioner contends that because the lease forms place the
valuation point “in the field,” Lessees are not allowed to deduct any post-production costs
that are incurred between the wellhead and the plant tailgate when calculating their royalty
payments. Commissioner’s main contention, therefore, centers around the valuation point
and the district court’s conclusion that the net proceeds language allows for Lessees to
deduct post-production costs that are incurred beyond the wellhead when calculating
Lessees’ royalty obligation.
{22} Lessees contend that the net proceeds language indicates that the Legislature
intended the valuation point to be at the wellhead. Lessees argue that by using the term “net
proceeds” in both the 1931 and 1947 lease forms, the Legislature intended to permit lessees
to deduct the post-production costs incurred in connection with the sale of their gas.
Lessees, therefore, assert that the lease forms require royalty payments to be based simply
on the “net proceeds” from the gas that is sold, whether it is conventional gas from a gas well
or casinghead gas from an oil well. Lessees assert that the “in the field” language has no
bearing on the interpretation of the 1931 lease, and does not limit their ability to deduct post-
production costs from the gross sales price under the 1947 lease. Lessees, therefore, submit
that the lease forms require royalty payments to be based simply on the “net proceeds” from
1
Because the district court’s order did not address whether or not Lessees’ deductions
were proper, our review centered only on whether the district court was correct in
concluding that the “net proceeds” language of the 1931 and 1947 lease forms was
unambiguous as a matter of law. Therefore, like the district court, we make no determination
regarding the appropriateness of Lessees’ deductions, a factual question that must be
resolved by the fact finder at trial.
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the gas that is sold, regardless of where the sale occurred and regardless of whether it is
conventional gas from a gas well or casinghead gas from an oil well.
{23} As discussed above, whether a contract contains an ambiguity is a matter of law that
is reviewed de novo; therefore, we review the district court’s conclusions regarding the
language contained in the 1931 and 1947 lease forms de novo. See Envtl. Control, Inc.,
2002-NMCA-003, ¶ 14. In interpreting oil and gas leases, courts have generally applied the
rules governing contract interpretation. Leonard v. Barnes, 75 N.M. 331, 345, 404 P.2d 292,
302 (1965). “The purpose, meaning and intent of the parties to a contract is to be deduced
from the language employed by them; and where such language is not ambiguous, it is
conclusive.” Cont’l Potash, Inc. v. Freeport-McMoran Inc., 115 N.M. 690, 704, 858 P.2d
66, 80 (1993) (internal quotation marks and citation omitted). A contract term may be
ambiguous if it is “reasonably and fairly susceptible [to] different constructions.” Mark V,
Inc., 114 N.M. at 781, 845 P.2d at 1235. In evaluating whether a term is ambiguous, “a
court may hear evidence of the circumstances surrounding the making of the contract and
of any relevant usage of trade, course of dealing, and course of performance.” C.R. Anthony
Co.. 112 N.M. at 508-09, 817 P.2d at 242-43 (1991). If a court concludes that there is no
ambiguity, “[t]he words of the contract are to be given their ordinary and usual meaning.”
Rust Tractor Co. v. S. Union Gas Co., 85 N.M. 323, 324, 512 P.2d 83, 84 (1973). When
interpreting an unambiguous contract, a court is limited to interpreting “the contract which
the parties made for themselves [as a court] may not alter or make a new agreement for the
parties.” Davies v. Boyd, 73 N.M. 85, 87-88, 385 P.2d 905, 951 (1963). Therefore, when
parties have entered into a valid lease of land for oil and gas purposes, and the terms
contained therein are “plain and unmistakable,” a court does not have the power to place a
different interpretation upon such terms. 2 W.L. Summers, The Law of Oil and Gas § 16:3,
at 505 (3rd ed. 2006).
{24} The term net proceeds refers to the “amount received in a transaction minus the costs
of the transaction.” Black’s Law Dictionary 1325 (9th ed. 2009). Under a net proceeds
royalty clause, royalties are to be paid based on the amount actually received by the lessee
from the sale of the product less post-production costs. See Frederick R. Parker, Jr., Costs
Deductible by the Lessee in Accounting to Royalty Owners for Production of Oil or Gas, 46
La. L. Rev. 895, 897 (1985-1986). The costs associated with production generally burden
only operating interests and, absent an express contractual provision to the contrary, are not
chargeable against the royalty interest. 3 Williams & Meyers, supra, § 645.1, at 598; 8
Williams & Meyers, supra, at 823 (providing production is “the act of bringing forth gas
from the earth”). Even though royalty interest holders are not generally subject to the costs
of production, they are usually subject to the costs that are incurred subsequent to
production. Id. at 920. The costs incurred subsequent to production are considered post-
production costs and are generally deducted from the sale of the product regardless of where
the sale takes place. See Bice v. Petro-Hunt L.L.C., 2009 ND 124, ¶ 19, 768 N.W.2d 496,
502 (discussing that in North Dakota the royalty owed is calculated by deducting processing
costs from the gross sales revenue, a method known as the work-back method); 8 Williams
& Meyers, supra, at 826; 3 Williams & Meyers, supra, § 645.2, at 598-99 (providing post-
9
production costs are costs other than “production costs” and may include the cost of
compressing, gathering, processing, treating, dehydrating, storing . . . , or transporting”).
Therefore, the plain meaning of the net proceeds royalty obligations confirms the district
court’s conclusion that the net proceeds royalty obligations are unambiguous as a matter of
law.
{25} The extrinsic evidence considered by the district court also supports the district
court’s interpretation of the net proceeds royalty obligation. In 1959, the then sitting
commissioner of public lands sent a letter to state lessees directing them to remit royalty
payments in the same manner in which they were to remit their state taxes in New Mexico.
In New Mexico, taxes on oil and gas were to be paid based on the value of the gas at the
production unit, i.e., the wellhead. See 1959 N.M. Laws, ch. 51, § 1. Thus, the
commissioner directed state lessees to remit royalties based on a value at the wellhead.
{26} The passage of NMSA 1978, Section 19-10-61 (1972), also sheds light on how the
post-production costs are to be allocated between the state and state lessees. Section 19-10-
61 requires the state to bear the post-production costs when the commissioner elects to take
royalty payments in kind. Section 19-10-61 provides that
[t]he commissioner of public lands shall have the authority to negotiate and
enter into agreements for the sale or exchange of royalty gas taken in kind
under oil and gas leases issued by the state. Provided, however, he shall not
dispose of said gas for a net consideration of less than that being received at
the time of exercising the option. In selling or exchanging the gas, the
commissioner of public lands shall be entitled to use the lessee’s gathering,
processing and compression facilities provided that reasonable compensation
is made to the lessee for such use.
Id. The district court found that requiring the state to pay reasonable compensation to state
lessees for the use of their post-production facilities indicated that the Legislature was aware
of the reality that was occurring in the field with respect to post-production costs. Therefore,
Section 19-10-61’s requirement that the state pay reasonable compensation to state lessees
for the use of their post-production facilities further supports the district court’s
determination that post-production costs may be netted from the gross sales price when
calculating royalty payments.
{27} After reviewing the statutory lease forms, the parties’ interpretations of the net
proceeds language, the plain meaning, and the extrinsic evidence presented to the district
court, we hold that the district court was correct in finding that the net proceeds royalty
obligations are unambiguous as a matter of law.
{28} We now turn to Commissioner’s contention that the district court relied on
inappropriate sources to guide its interpretation of the net proceeds royalty obligation.
Commissioner contends that: (1) the district court could not rely on the parties’ course of
10
dealing and course of performance because estoppel does not apply against the state; (2) the
district court could not rely on extrinsic factual evidence because under the bifurcation order,
the court was only to consider legal issues in the first phase of the case; and (3) the district
court’s reliance on factual circumstances to interpret the lease was erroneous in light of its
decision not to permit full discovery on how Lessees calculated their royalty obligations.
{29} Commissioner contends that the district court erred in its interpretation of net
proceeds royalty obligations to the extent it relied on course of dealing and course of
performance evidence because relying on such evidence contravenes New Mexico law
prohibiting the use of equitable estoppel against the State and its agencies. Generally
equitable estoppel will only be an effective defense against the state when there is a
“shocking degree of aggravated or overreaching conduct or where right and justice demand
it.” Waters-Haskins v. N.M. Human Servs. Dep’t, 2009-NMSC-031, ¶ 16, 146 N.M. 391,
210 P.3d 817 (quoting Wisznia v. State Human Servs. Dep’t, 1998-NMSC-011, ¶ 17, 125
N.M. 140, 958 P.2d 98). Therefore, Commissioner is correct in his assertion that New
Mexico law disfavors the defense of equitable estoppel when asserted against the state or a
state agency. See Lopez v. State, 1996-NMSC-071, ¶ 19, 122 N.M. 611, 930 P.2d 146
(“New Mexico courts have been reluctant to apply estoppel against the state and its
agencies.”). However, it does not follow that the district court necessarily relied on an
equitable estoppel defense when it relied on course of dealing and course of performance
evidence in interpreting the meaning of net proceeds. The summary judgment order in
question did not address whether Lessees can present an equitable estoppel defense; it
explicitly only addressed the meaning of the net proceeds royalty obligations. Therefore,
because New Mexico law clearly permits courts to consider course of dealing and course of
performance evidence when determining whether a contractual term is ambiguous, Mark V,
Inc., 114 N.M. at 781, 845 P.2d at 1235, the district court’s reliance on course of dealing and
course of performance evidence was proper.
{30} Commissioner also contends that the district court’s bifurcation of the legal and
factual questions precluded it from considering extrinsic evidence in making the legal
determination that the net proceeds language was unambiguous as a matter of law. Even
though a district court may consider evidence of course of dealing and course of
performance in determining the initial question regarding whether a contractual term is
ambiguous, the question regarding whether a contract contains an ambiguity remains a
question of law to be decided by the district court. See id. at 781, 845 P.2d at 1235 (“The
question whether an agreement contains an ambiguity is a matter of law to be decided by the
trial court. The court may consider collateral evidence of the circumstances surrounding the
execution of the agreement in determining whether the language of the agreement is
unclear.” (internal citation omitted)). Because New Mexico law permits courts to consider
extrinsic evidence when making the legal determination regarding whether a contract term
is ambiguous, we disagree with Commissioner’s argument that the district court’s reliance
on extrinsic factual evidence in finding the net proceeds language was unambiguous as a
matter of law was improper.
11
{31} We refrain from addressing Commissioner’s contention regarding the propriety of
the district court’s discovery ruling because that order was not certified for our review.
Orders entered on procedural motions that do not practically dispose of the case on the
merits are not final orders and therefore are generally not appealable. Griego v. Grieco, 90
N.M. 174, 176, 561 P.2d 36, 38 (Ct. App. 1977); see In re Estate of Pino, III, 115 N.M. 759,
760, 858 P.2d 426, 427 (Ct. App. 1993) (providing “orders requiring or denying discovery
. . . generally do not constitute a final disposition of the proceedings . . . [and t]herefore are
not normally appealable, except upon the granting of an interlocutory appeal”). “[A]ppellate
review of non-final orders is allowed only in limited circumstances” when the district court
certifies the order pursuant to Section 39-3-4. Candelaria v. Middle Rio Grande
Conservancy Dist., 107 N.M. 579, 581, 761 P.2d 457, 459 (Ct. App. 1988). Therefore,
because the district court’s discovery order is not certified for our review, we refrain from
conducting such a review.
{32} Accordingly, we conclude that the district court’s reliance on extrinsic evidence was
proper, and the district court was correct in its determination that the net proceeds language
of the 1931 and 1947 lease forms was unambiguous as a matter of law.
2. Free Use Clause
{33} A free use clause is an express provision that appears in most oil and gas leases and
governs the right of a lessee to use products derived from the leased premises in the
operation of said lease. 3 Williams & Meyers, supra, § 644.5, at 573-574.1. Both the 1931
and 1947 statutory lease forms contain such a provision. The relevant language of the free
use clauses contained in the 1931 and 1947 statutory lease forms provides:
[T]he said lessor has granted and demised, leased and let, and by these
presents does grant, demise, lease and let unto the said lessee, exclusively,
for the sole and only purpose of exploration, development and production of
oil and/or gas thereon and therefrom with the right to own all oil and gas so
produced and saved therefrom and not reserved as royalty by the lessor under
the terms of this lease, together with rights of way, easements and servitudes
for pipe lines, telephone and telegraph lines, tanks, power houses, stations,
gasoline plants, and fixtures for producing, treating and caring for such
products, and . . . any and all rights and privileges necessary, incident to or
convenient for the economical operation of said land, for oil and gas, with
right for such purposes to the free use of oil, gas, casing-head gas, or water
from said lands, but not from lessor’s water wells . . . .
1931 N.M. Laws, ch. 18, § 2; 1947 N.M. Laws, ch. 200, § 1 (emphasis added). The parties’
dispute surrounding the free use clause centers on the scope of the clause and whether it
grants Lessees the free use of plant and field fuel. Plant fuel is the “[f]uel employed by a
lessee in operating a plan . . . to remove sulfur from oil or gas [that is] produced by the
lessee.” 8 Williams & Myers, supra, at 775. Field fuel is consumed in powering
12
compressors located on the field gathering system. The district court found that field fuel
and plant fuel are costs that Lessees remit to post-production service providers, do not
amount to proceeds, and are not subject to royalties.
{34} Commissioner has previously conceded that plant fuel can be netted in computing
Lessees’ royalty. However, before this Court, Commissioner argues that the free use clause
does not encompass Lessees’ use of field or plant fuel. Additionally, Commissioner asserts
that the free use clause restricts Lessees’ use of oil and gas without the payment of royalty
to the leased premises and should not be read as allowing the unlimited use of gas for
gathering, processing, or other operations that occur off the leased premises. Commissioner
relies on Roberts Ranch Co. v. Exxon Corp., 43 F. Supp. 2d 1252 (W.D. Okla. 1997), to
support this assertion.
{35} In Roberts Ranch, the lessees claimed that they had a right to the free use of gas in
the post-production treatments that were required to make gas marketable and which
occurred off the leased premises. Id. at 1257. The lessors asserted that the gas used by
lessees at a treatment plant located off the leased premises was subject to royalties. Id. at
1256. The court concluded that because lessees were obligated to bear all costs associated
with making gas marketable, a free use clause should not be read as passing the post-
production costs on to the lessors. Id. at 1257. The court based its decision on the
marketable condition rule, which requires lessees to bear all costs associated with placing
the gas in marketable condition.
{36} Lessees assert that Commissioner’s reliance on Roberts Ranch is misplaced. Lessees
contend that requiring royalties to be paid on the use of field and plant fuel would contradict
both the free use clause and net proceeds language of the lease forms and would transform
a permissive benefit into an affirmative obligation.
{37} Lessees point out that in the standard form field service contracts, the service-
provider bargains to retain a small percentage of the gas produced from the leases for use as
field and plant fuel. This fuel is used as partial compensation for post-production service
providers. Lessees contend that because field and plant fuel is used as partial compensation
for post-production service providers and because they do not derive proceeds from such
use, they do not have to pay royalties on such fuel. We agree.
{38} A royalty clause that provides that the “lessee may use oil [or gas] in operating the
premises . . . is not under a duty to pay royalty on the amount so used.” 3A Summers, supra,
§ 33:7, at 153 (footnote omitted). When a royalty clause provides that the lessee is
privileged to use gas in operating the lease, it is generally held that the gas used for these
purposes should be excluded in the calculation of the lessor’s royalty. Id. § 33:12, at 160.
However, a lessee’s right to use gas in the operations of the leased premises is not without
limits and is generally interpreted as being limited to the leased premises unless the clause
expressly states otherwise. See 3 Williams & Meyers, supra, § 661.4, at 763 (providing
13
“parties are free to authorize the provision of free gas without geographic limitation if their
intent is expressed in the lease”).
{39} In Bice v. Petro-Hunt L.L.C., the North Dakota Supreme Court examined free use
clauses similar to the free use clause contained in the 1931 and 1947 statutory lease forms.
2009 ND 124, ¶ 22, 768 N.W.2d 496, 502-03. One of the free use clauses provided that the
lessees “shall have the right to use, free of cost, gas, oil and water produced on said land for
its operation thereon.” Id. The court concluded that because the lessees were using the gas
in furtherance of the lease operations, the free use clause did not limit the lessees’ free use
of the gas to the leased premises. Id. ¶¶ 22, 27, 768 N.W.2d at 503-04.
{40} In this case, the free use clauses contained in the 1931 and 1947 lease forms granted
Lessees “any and all rights and privileges necessary, incident to or convenient for the
economical operation of said land, for oil and gas, with [the] right for such purposes to the
free use of oil, gas casing-head gas, or water from said lands . . . .” (Emphasis added.) These
rights were granted to Lessee “for the sole and only purpose of exploration, development and
production of oil and gas thereon and therefrom with the right to own all oil and gas so
produced and saved therefrom and not reserved as royalty by the lessor . . . .” This language
granted Lessees the right to own all oil and gas so produced and saved from the leased
premises that was not otherwise reserved as royalty by the lessor. Furthermore, it entitled
Lessees to the free use of oil and gas produced from the leased premises, regardless of where
the use occurred, so long as the oil and gas was being used to further the economical
operations of said land. In reading the free use clause in conjunction with the net proceeds
language, we conclude that Lessees are entitled to the free use of both plant and field fuel
so long as it was used in the operation of the lease.
{41} Accordingly, we affirm the district court’s findings and hold field and plant fuel are
post-production costs that Lessees remit to post-production service providers for the
development and production of the leased premises; they are neither sold nor saved by
Lessees and therefore are not subject to royalty payments.
3. Drip Condensate
{42} The district court found that the relevant provisions of the 1931 and 1947 lease
forms require Lessees to pay royalties on their use of drip condensate to the extent that they
derive profits from such use. Drip condensate is “the portion of a gas stream that becomes
liquid during the transmission of the gas from [the leased premises] to a processing plant.”
8 Williams & Myers, supra, at 296.1. Within the oil and gas industry, condensate is also
referred to as casinghead gas and liquid hydrocarbon. Ken Anderson, Oklahoma Historical
Society’s Encyclopedia of Oklahoma History and Culture,
http://digital.library.okstate.edu/encyclopedia/entries/N/NA017.html (last visited July 11,
2012); see 8 Williams & Myers, supra, at 184.
14
{43} Commissioner asserts that the language of the lease forms provides him with the
power to require payment of royalty for all or any part of the gas produced, and therefore
provide him with the power to demand royalties on drip condensate. Commissioner,
therefore, contends that the district court was correct in finding that the lease provisions
require Lessees to pay royalties on drip condensate, but erred in finding that Lessees only
had to pay royalties on drip condensate to the extent they derived profits from such use.
Lessees assert that the lease provisions do not require royalties to be paid on drip condensate
as drip condensate is provided to gathering companies as part of the compensation for the
gathering services, and amounts to a post-production cost. Therefore, Lessees claim that
because they do not receive any proceeds from the use of the drip condensate, they are not
obligated to pay royalties on such use.
{44} An oil and gas lease is to be construed in the same manner as a contract. See Pub.
Serv. Co. Of N. M. v. Diamond D Constr. Co., Inc., 2001-NMCA-082, ¶ 19, 131 N.M. 100,
33 P.3d 651. It is to be viewed as a harmonious whole so as to give meaning to every
provision and accord each part of the lease its significance in light of other provisions. Id.
A lease should not be interpreted in a manner in which one clause or provision annuls
another. Id.
{45} The 1931 royalty obligations provide that “[s]ubject to the free use without royalty,
as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth part of the oil
produced and saved from the leased premises . . .” and
lessee agrees to pay lessor the one-eighth of the net proceeds derived from
the sale of gas from each gas well. If casing-head gas produced from said
land is sold by the lessee, the lessee shall pay the lessor as royalty one-eighth
of the net proceeds of said sale; if casing-head gas produced from said lands
is utilized by lessee otherwise than for carrying on the lessee’s operations for
producing oil or gas from said lands, then the lessee shall pay the lessor the
market value in the field of the equal one-eighth part of the casing-head gas
so utilized at the time of such utilization.
(Emphasis added.)
{46} The 1947 royalty obligations provide that “[s]ubject to the free use without royalty,
as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth of the oil
produced and saved from the leased premises . . .” and “[s]ubject to the free use without
royalty, as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth of the
cash value of gas, including casinghead gas, produced and saved from the leased premises
and marketed or utilized . . . .”
{47} The royalty provisions contained in the 1931 and 1947 lease forms reserve for royalty
all oil, gas, and casinghead gas that is not otherwise provided for under the free use clause.
The free use clauses grant Lessees “any and all rights and privileges necessary, incident to
15
or convenient for the economical operation of said land,” and allow for the free use of oil,
gas, and casinghead gas for the “purpose of exploration, development, and production of oil
and/or gas thereon and therefrom with the right to own all oil and gas so produced and saved
therefrom and not reserved as royalty by lessor under the terms of this lease . . . .”
Furthermore, the 1947 lease provides that “the cash value for royalty purposes of carbon
dioxide gas and of hydrocarbon gas delivered to a gasoline plant for extraction of liquid
hydrocarbons shall be equal to the net proceeds derived from the sale of such gas, including
any liquid hydrocarbons recovered therefrom.” This clause indicates that payment of
royalties on drip condensate, which is a liquid hydrocarbon, is to be based on net proceeds
“derived from the sale of . . . liquid hydrocarbons recovered therefrom.”
{48} Lessees’ use of drip condensate amounts to a post-production cost that is remitted
to post-production service providers. Construing the leases so as to give effect to every
provision, we conclude that the royalty obligations contained in the 1931 and 1947 lease
forms are limited by their respective free use clauses and do not require royalties to be paid
on Lessees’ use of drip condensate to the extent that Lessees do not derive proceeds from
such use. We affirm the district court’s finding that Lessees are only obligated to pay
royalties on the use of drip condensate to the extent that they receive proceeds from such use.
Order 2: Summary Judgment on the Meaning of the Maximum Price Provision
{49} In the second certified order, the district court addressed the meaning of the
“maximum price” provision. This issue pertains only to the construction of the 1947 lease
form as there is no maximum price clause in the 1931 lease. The maximum price provision
of the 1947 lease provides:
Notwithstanding the foregoing provisions, the lessor, acting by its
commissioner of public lands, may require the payment of royalty for all or
any part of the gas produced and saved under this lease and marketed or
utilized at a price per m.c.f. equal to the maximum price being paid for gas
of like kind and quality and under like conditions in the same field or area or
may reduce the royalty value of any such gas (to any amount not less than the
net proceeds of sale thereof in the field) if the commissioner of public lands
shall determine such action to be necessary to the successful operation of the
lands for oil or gas purposes or to encouragement of the greatest ultimate
recovery of oil or gas or to the promotion of conservation of oil or gas.
{50} The district court found the maximum price provision to be “plain, clear and
unambiguous” and entitled Commissioner to identify a “maximum price being paid for gas
of like kind and quality and sold under like conditions in the same field or area, and to utilize
that price as the starting point in calculating net proceeds.” Thus, the district court found
that the maximum price clause does not require Lessees to pay a royalty based on the
16
“highest gross price in the field or area, without netting (deducting) costs incurred by
[Lessees] in selling the gas.”
{51} Commissioner asserts that the district court’s interpretation of the maximum price
clause renders the clause meaningless. Commissioner claims that the clause grants the
Commissioner of Public Lands the discretion to require payment of a royalty value equal to
the maximum price being paid for natural gas in the same field or area. Commissioner
asserts that because the clause provides him with the discretion to reduce the maximum price
royalty payment to a net value, the maximum price clause must be based on a gross value,
and not a net value. Commissioner, therefore, interprets the maximum price clause as
providing him with the authority to prohibit Lessees from deducting field-related expenses
when calculating their royalty payments.
{52} Lessees assert that Commissioner’s interpretation of the maximum price clause of
the 1947 lease attempts to convert the “net proceeds” royalty obligation to a “gross
proceeds” royalty obligation. Lessees further argue that Commissioner’s interpretation
confuses the concept of “payment of royalty” and “price,” and assert that the maximum price
provision allows for Commissioner to require the royalty payments to be calculated based
on the “maximum price being paid for gas of like kind and quality and under like conditions
in the same field or area” if he determines such action is necessary to the successful
operations of the lands.
{53} In oil and gas leases the price, or market price, is considered to be the price that
would be paid by a willing buyer to a willing seller in a free market. 3 Eugene Kuntz, A
Treatise on the Law of Oil and Gas § 40.4(d), at 329 (1989). Market price is determined by
looking to comparable sales, which “are those [sales] that are comparable in time, quality,
quantity, and availability of marketing outlets.” Id. at 335. The language of the 1947
maximum price clause allows Commissioner to, in his discretion, require Lessees to
calculate their royalty obligations based on the maximum market price being paid for similar
gas in the same field or area. The clause also provides Commissioner with the discretion to
reduce the royalty payments to an amount not less than the royalty value of the net proceeds
in the field. This clause, therefore, does not affect Lessees’ ability to deduct post-production
costs. Instead it provides Commissioner with the authority to require that Lessees deduct
their post-production expenses from the maximum price being paid for gas of like kind and
quality in the same field or area.
{54} Accordingly, we affirm the district court and hold that the maximum price clause of
the 1947 statutory lease form grants Commissioner the authority to require royalty payments
based on the maximum market price in the field or area if “such action [is] necessary to the
successful operation[s] of the lands for oil or gas purposes.”
Order 3: Denying Commissioner’s Motion for Reconsideration of Dismissal of
Commissioner’s Breach of the Implied Covenant to Market Claim
17
{55} Commissioner filed a counterclaim against Lessees for breach of the implied
covenant to market. In that counterclaim, he alleged that the implied covenant to market
requires Lessees to place the gas in a marketable condition and requires that the expenses
incurred in obtaining a marketable product, such as gathering, dehydrating, and treating, be
born by Lessees.
{56} Lessees moved for judgment on the pleadings on Commissioner’s breach of the
implied covenant to market claim. The district court granted Lessees’ motion, and dismissed
the claim. Subsequently, Commissioner moved for reconsideration in light of this Court’s
opinion in Davis v. Devon Energy Corp., 2009-NMSC-048, 147 N.M. 157, 218 P.3d 75. In
Davis we considered whether certification of a class action was appropriate where a group
of royalty owners claimed that the defendant gas producers breached an implied covenant
to market; however, Davis expressly avoided establishing the existence or scope of a
marketable condition rule under New Mexico law. Id. ¶¶ 3, 14-15.
{57} The district court denied Commissioner’s motion for reconsideration of its previous
dismissal of Commissioner’s implied covenant to market claim. The district court reasoned
that to imply a covenant which forces Lessees to bear the costs of placing the gas in a
marketable condition would require the district court to alter the express terms of the lease,
and it ruled it had no power to so alter the lease. Accordingly, the district court found that
because the statutory royalty obligation is based on “net proceeds,” Lessees are permitted
to net the costs associated with placing the gas in a marketable condition.
{58} Ordinarily “[w]e review judgments on the pleadings made pursuant to Rule 1-012(C)
NMRA according to the same standard as motions for failure to state a claim under Rule
1-012(B)(6) NMRA.” Vill. of Angel Fire v. Bd. of Cnty. Comm’rs of Colfax Cnty.,
2010-NMCA-038, ¶ 5, 148 N.M. 804, 242 P.3d 371. However, “[i]f, on a motion for
judgment on the pleadings, matters outside the pleadings are presented to and not excluded
by the court, the motion shall be treated as one for summary judgment.” Rule 1-012(C).
Therefore, because the district court conducted a full review of the record, Lessees’ motion
for judgment on the pleadings will be treated as a motion for summary judgment and
reviewed accordingly.
{59} On appeal, Commissioner claims that “under New Mexico law, the [s]tate leases
inherently include a duty to market gas.” Therefore, he maintains that because Lessees have
an implied duty to place the gas in a marketable condition Lessees are prohibited from
deducting post-production costs when calculating their royalty obligations. Although
Commissioner’s counterclaim is couched in terms of a breach of the implied covenant to
market, the substance of the counterclaim relies upon an offshoot to the implied covenant
to market, termed the “marketable condition rule.” See Davis, 2009-NMSC-048, ¶ 6
(internal quotation marks and citation omitted).
{60} Lessees assert that the district court’s dismissal of Commissioner’s claim was correct
because New Mexico law does not recognize “any variant of . . . the marketable condition
18
rule.” Lessees further contend that because the statutory lease provisions expressly and
unambiguously allow for the deduction of post-production costs, it is improper for courts to
imply duties.
{61} In Davis, we recognized that “whether a covenant may be implied in a given contract,
[depends upon] the legal theory supporting the implication of that promise.” Id. ¶ 32. The
legal theory supporting the implication of a promise determines the court’s analysis and
whether a covenant is to be implied in fact or at law. Id.; see 5 Williams & Meyers, supra,
§ 803, at 18.2 (discussing implied covenants as being divided into two categories, implied
covenants in fact and implied covenants at law).
{62} An implied covenant in fact springs from the language of the parties’ agreement.
Davis, 2009-NMSC-048, ¶ 32. Thus, by implying a covenant in fact, a court is “effectuating
the parties’ intentions by interpreting the written terms of an agreement and analyzing the
parties’ conduct.” Id. An implied covenant at law, however, has its origins not in the
parties’ agreement, but rather in law. Id. ¶¶ 32-33. Thus, by implying a covenant at law, a
court is “stating that a duty imposed by law creates an obligation on one or more of the
parties to the agreement.” Id. ¶ 32.
{63} In Davis, we noted that an implied covenant in fact “requires an analysis of the
parties’ intentions,” as expressed in the agreement, while an implied covenant at law “is
merely a judicial determination of the duties the law imposes on the parties” and does not
require analysis of the agreement. Id. ¶¶ 32-33. In so doing, we held that the implied
covenant to market is an implied covenant at law and does not require an analysis of the
parties’ agreement. Id. ¶ 35. This holding was consistent with our previous cases, namely
Darr v. Eldridge, 66 N.M. 260, 346 P.2d 1041 (1959) and Libby v. De Baca, 51 N.M. 95,
179 P.2d 263 (1947), where we implied the covenant to market “in equity, without looking
to the language of the agreements or other evidence of the parties’ intentions.” Davis, 2009-
NMSC-048, ¶ 35. Davis, therefore, makes clear that the implied covenant to market “applies
in equity irrespective of the parties’ intentions.” Id.
{64} However, in Davis we declined to address whether the marketable condition rule is
inherent in the implied covenant to market, Davis, 2009-NMSC-048, ¶ 35, and whether, if
recognized in New Mexico, the marketable condition rule would be implied in fact or at law.
We do not need to reach the issue in this case. When the Legislature adopted the statutory
oil and gas leases that we have referenced in this opinion, the Legislature expressed the
policy decision that lessees under such leases are entitled to recover some post-production
costs associated with making the gas marketable. How much and what kinds of post-
production costs remain at issue in this case. However, because of this legislative policy
decision we do not need to decide whether the marketable condition rule is inherent in the
implied covenant to market. As we indicated in Davis, whether the marketable condition
rule applies in New Mexico is not yet ripe for review. 2009-NMSC-048, ¶ 15. This opinion
should not be interpreted as affecting private oil and gas lease agreements. Accordingly, we
19
affirm the district court’s dismissal of Commissioner’s counterclaim for the breach of the
implied covenant to market.
Order 4: Allowing the Deduction of the Cost of Post-Production Services Provided by
Lessees’ Affiliates to the Extent it Is Reasonable
{65} The parties submitted corresponding motions for summary judgment to the district
court regarding the amount Lessees are entitled to deduct for post-production services when
such services are provided by one of Lessees’ affiliate entities. The district court found that
Lessees’ deductions for post-production services must be reasonable.
{66} Commissioner argues that the district court erred in finding that Lessees’ deductions
must only be reasonable and asserts that deductions for post-production services performed
by Lessees’ affiliated entities must be both actual and reasonable. Lessees counter that the
Legislature intended for the post-production costs incurred from transactions with affiliated
and non-affiliated third-party processors to be treated the same.
{67} Neither the 1931 nor the 1947 statutory lease forms contain an express clause
governing affiliate transactions. When a contract is clear as written, a court “must give
effect to the contract and enforce it as written.” Ponder v. State Farm Mut. Auto. Ins. Co.,
2000-NMSC-033, ¶ 11, 129 N.M. 698, 12 P.3d 960. Courts “cannot create a new agreement
for the parties,” Montoya v. Villa Linda Mall, Ltd., 110 N.M. 128, 129, 793 P.2d 258, 259
(1990), and “will not give effect to a party’s undisclosed intentions,” Ponder, 2000-NMSC-
033, ¶ 14. When a contract is silent regarding the subject matter at issue, “[e]vidence of
custom and usage may be used to ascertain the intention in reference to matters about which
the contract is silent.” 21A Am. Jur. 2d Customs and Usages, § 25 (2012). Moreover, when
“a contract is silent on an issue, the law implies a reasonable term to cover that issue.”
Melvin Aron Eisenberg, Probability and Chance in Contract Law, 45 UCLA L. Rev. 1005,
1027 (1998); see, e.g., Castle v. McKnight, 116 N.M. 595, 598, 866 P.2d 323, 326 (1993)
(providing that when a contract is silent as to the time of performance a reasonable time will
be implied).
{68} The district court found that based on the statutory and regulatory history, the New
Mexico Legislature and the Commissioner of Public Lands intended both affiliated and non-
affiliated transactions to be treated the same. Therefore, Lessees were permitted to deduct
reasonable costs incurred for post-production services. We agree with the district court’s
finding that there was no support for Commissioner’s contention that deductions for
affiliated transactions must be limited to actual costs. Accordingly, because there is nothing
in the 1931 or 1947 statutory lease forms to indicate that the Legislature intended to treat
affiliated and non-affiliated transactions differently when deducting post-production costs,
we affirm the district court’s finding that deductions used in calculating Lessees’ royalty
obligations must be reasonable.
CONCLUSION
20
{69} For the foregoing reasons, we affirm the district court’s orders.
{70} IT IS SO ORDERED.
____________________________________
PETRA JIMENEZ MAES, Chief Justice
WE CONCUR:
____________________________________
PATRICIO M. SERNA, Justice
____________________________________
RICHARD C. BOSSON, Justice
____________________________________
EDWARD L. CHÁVEZ, Justice
____________________________________
CHARLES W. DANIELS, Justice
Topic Index for ConocoPhillips Co. v. Lyons, No. 32,624
APPEAL AND ERROR
Certification
Interlocutory Appeal
Standard of Review
CIVIL PROCEDURE
Counterclaim
Equitable Claims or Defenses
Estoppel
Summary Judgment
CONTRACTS
Ambiguous Contracts
Breach
Implied Contract
Leases
GOVERNMENT
Public Lands
JUDGMENT
Declaratory Judgment
21
NATURAL RESOURCES
Leases
Oil and Gas
Royalties
STATUTES
Interpretation
Legislative Intent
22