Defendant's Attorney: Christopher A. Chrisman, Bradford Berge, Jessica M. Schmidt
Description: Fossil fuels are the decomposed remains of pre-historic flora (coal) and fauna (oil
and gas). They have driven the world’s economy (particularly that of the United States)
for over a century. Discovering marketable deposits, extracting them from the ground,
refining them, and delivering them to consumers in useful form is big business, on one
hand fraught with risk and on the other richly rewarding. That being so, it has attracted
the attention of governments as a lucrative source of tax revenue as well as royalties,
bonuses, etc., derived from government-owned reserves and as a way of directing public
policy. Since oil and gas are the most energy dense1 and convenient of the fossil fuels,
litigation and regulation abound with respect to them. But, in large measure mineral
owners (private and public) and those involved with mineral producers have been free to
contractually “strike their own deals.” Myriad matters are involved; here we are
principally concerned with construing the language of leases in accordance with
prevailing law—both statutes and case law. Statutes, of course, properly direct policy.
So do cases, more covertly, but no less dramatically.
Oil and gas law is rife with duties owed by the lessee to the lessor. Some of those
1 For a comparison of the energy density of many combustibles, visit:
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duties are expressed in an agreement (the lease). Others duties are imposed by the courts
as implied covenants. See generally, 6 Peter Linzer, Corbin on Contracts § 26.1 (Joseph
M. Perillo ed. 2010). This case involves the implied covenant to market gas. It benefits
the lessor, in particular, by insuring that the lessee uses reasonable efforts to market
potential production. That way the lessor can enjoy the benefits the lease provides. This
case deals with that implied covenant, but more particularly with what has come to be
known as the marketable condition rule. In its purest form, that advocated by appellants,
it not only requires the lessor to market the gas, but to do so solely at its expense.
Colorado has adopted a version of the marketable condition rule, which applies only
when the lease does not provide otherwise. Years ago we predicted New Mexico would
not adopt the marketable condition rule and so far neither the legislature nor the New
Mexico Supreme Court has done so. Accordingly, our decision rests on the terms of the
leases involved. We rely on the text of the leases and the meaning commonly ascribed to
the language used (the essence of the common law, which reflects the practices of the
community, rather than dictates practices to the community).
The San Juan Basin, located in northwestern New Mexico and southern Colorado,
is a rich source of oil and natural gas. Energen owns and operates oil and gas wells in the
Basin.2 Its wells are subject to leases and other agreements (many of which are quite old)
2 Energen has since sold most of its interests in the wells to Southland Royalty
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requiring it to pay a monthly royalty or overriding royalty3 on production to the Anderson
Living Trust, the Pritchett Living Trust, the Neely-Robertson Revocable Family Trust
(N-R Trust), and the Tatum Living Trust. The royalty interests of the Anderson,
Pritchett, and N-R Trusts (collectively the New Mexico Trusts) derive from wells located
in New Mexico, the Tatum Trust’s royalty interest from wells located in Colorado.
Believing Energen was systematically underpaying royalties, all of the Trusts filed
a putative class action complaint against it.4 The New Mexico Trusts claimed Energen
was improperly deducting from their royalties their proportionate share of (1) the costs it
incurs to place the gas produced from the wells in a marketable condition (postproduction
costs) and (2) a privilege tax the State of New Mexico imposes on natural gas
processors (the natural gas processors tax). They also alleged Energen had not timely
paid royalties or interest thereon, as required by the New Mexico Oil and Gas Proceeds
Payments Act. Both the New Mexico Trusts and the Tatum Trust further claimed
Energen was wrongfully failing to pay royalty on the gas it used as fuel.
3 The term “overriding royalty” is used to describe a royalty carved out of a
working interest created by an oil, gas, or mining lease. Usually, the reservation
of an override involves the transfer of a lease in which the lessee-assignor . . .
retains an interest in production in the form of an overriding royalty. The
overriding royalty interest is an interest free of the expenses of production. It is a
nonpossessory interest in land.
Cont’l Potash, Inc. v. Freeport-McMoran, Inc., 858 P.2d 66, 69 n.2 (N.M. 1993)
4 The district judge stayed the Trusts’ motion for class certification pending this
appeal, which deals only with the interests of the named parties.
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The district judge dismissed the New Mexico Trusts’ marketable condition rule
claim for failure to state a claim under Fed. R. Civ. P. 12(b)(6) and entered summary
judgment in favor of Energen on the remaining claims. All of the Trusts appeal from
those judgments.5 Our review is de novo. Birch v. Polaris Indus., Inc., 812 F.3d 1238,
1251 (10th Cir. 2015) (grant of summary judgment is reviewed de novo); Thomas v.
Kaven, 765 F.3d 1183, 1190 (10th Cir. 2014) (grant of motion to dismiss under Fed. R.
Civ. P. 12(b)(6) is reviewed de novo).
For the most part we agree with the district judge, particularly in the following
First, under New Mexico law, Energen had the duty to diligently market the gas
for the benefit of the New Mexico Trusts but that duty did not prohibit it from deducting
from their royalty payments their proportionate share of post-production costs—those
costs necessary to make the gas marketable (i.e., the marketable condition rule does not
apply in New Mexico).
Second, nothing in the New Mexico Natural Gas Processors Tax Act or other New
Mexico law prohibited Energen from deducting the Trusts’ proportionate share of the tax
from their royalties.
Finally, the Anderson and Pritchett Trusts’ lease allows Energen to use produced
5 The judgments did not dispose of all of the Tatum Trust’s claims; some remain
pending in the district court. However, the judge certified his judgments under Fed. R.
Civ. P. 54(b). Upon independent review, we deem the certification proper. We have
jurisdiction over all issues presented for review.
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gas as fuel without paying royalty on it.
In some respects, we part ways with him. They relate to: (1) the fuel gas claims
made by the N-R Trust and Tatum Trust and (2) the New Mexico Trusts’ claim under the
New Mexico Oil and Gas Proceeds Payments Act. As to the former, the N-R Trust’s
overriding royalty agreement requires royalty to be paid on all gas produced, including
that gas used as fuel. And the Tatum Trust’s leases explicitly prohibit Energen from
deducting post-production costs (Energen treats its use of the fuel gas as an in-kind postproduction
cost). Moreover, the “free use” clauses and royalty provisions in the Tatum
Trust’s leases limit the free use of gas to that occurring on the leased premises. Because
use of the fuel gas occurs off the leased premises, Energen owes royalty on that gas.
With regard to the latter, the judge was right in permitting Energen to hold funds owed to
the N-R Trust in a suspense account until a title issue concerning a well was resolved in
favor of that Trust. However, he did not address whether the N-R Trust was entitled to
statutory interest on those funds. It was so entitled, yet the current record (at least as we
read it) does not show interest to have been paid on the funds.
We now explain. Because all claims do not apply to all appellants, we discuss the
issues separately, providing a brief background of the facts relevant to each.6
6 In the district court, all of the Trusts alleged Energen breached their royalty
agreements by failing to pay royalty on “drip condensate,” “‘the portion of a gas stream
that becomes liquid during the transmission of the gas from the leased premises to a
processing plant.’” ConocoPhillips Co. v. Lyons, 299 P.3d 844, 856 (N.M. 2012)
(quoting 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law, at 296.1 (2011)).
The judge entered summary judgment in Energen’s favor on the New Mexico Trusts’
(Continued . . .)
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I. Marketable Condition Rule—New Mexico Trusts
There is no market at the wellhead on the leased properties for the gas produced
from Energen’s wells. See 8 Howard R. Williams & Charles J. Meyers, Oil and Gas
Law, at 830 (2011) (defining “[p]roduction of gas” as “[t]he act of bringing forth gas
from the earth”). The gas must first be gathered, compressed, dehydrated, and treated.7
Energen contracts with third-party companies to perform these services. It then sells the
processed gas at the tailgate of the third-party processing plants to various energy
Energen pays the New Mexico Trusts, as royalty, a portion of the downstream
sales price. However, it deducts from that price each Trust’s proportionate share of the
drip condensate claim; Energen did not seek summary judgment on the Tatum Trust’s
drip condensate claim, which remains pending in the district court. The New Mexico
Trusts identify their drip condensate claim as an issue in their opening brief but otherwise
fail to develop it, providing no argument or legal authority to support it. They have
waived the issue and we do not consider it. Garrett v. Selby Connor Maddux & Janer,
425 F.3d 836, 841 (10th Cir. 2005) (“merely including an issue within a list [of issues is
not considered] adequate briefing”; issues that are not adequately briefed will be deemed
waived (quotation marks omitted)).
7 The processing of natural gas into a marketable condition is complicated and
depends on whether the gas comes from an oil well (casinghead gas), gas well
(conventional natural gas), or from coal seams (coalbed methane gas). The intricate
details are not relevant to our resolution of this appeal so we decline to outline them here.
For a detailed discussion of the process, see ConocoPhillips Co. v. Lyons, 299 P.3d 844,
849-50 (N.M. 2012). For the intensely interested, Wikipedia provides a primer, including
a discussion of drip condensate, which is not at issue in this appeal (see supra note 6).
https://en.wikipedia.org/wiki/Natural-gas_condensate. Since Wikipedia can be edited by
any user, its accuracy is uneven. Nevertheless, when carefully considered, it can be
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fees it pays to third-party companies to make the gas marketable (post-production costs).
The New Mexico Trusts claim this deduction is improper because, in their words,
New Mexico law imposes an implied duty on Energen to market the gas for the benefit of
the royalty owners and that duty necessarily prohibits Energen from deducting postproduction
costs from their royalty payments (generally referred to as the marketable
The New Mexico Trusts’ leases set the basis for royalty payments as the “market
value at the well” or the “prevailing field market price.” (Appellants’ App’x at 342 (N-R
Trust), 338 (Anderson and Pritchett Trusts).) Determining those amounts, however, is
not straightforward, because there is no market “at the well” for gas produced in the San
Juan Basin. As we explained in Abraham v. BP America Production Co.:
In order to determine the market value of the unprocessed gas at the well,
producers sell refined natural gas and NGLs [natural gas liquids] at the tailgate of
the processing plant (i.e., after processing) to establish a base sales amount, and
deduct from that amount costs for transportation, processing, etc. This is called a
“netback” or “workback” method, and it is widely accepted as the best means for
estimating the market value of gas at the well where no such market exists.
685 F.3d 1196, 1200 (10th Cir. 2012).
Properly understood, the netback method is not a means of cost-shifting; it is a
means of determining the net profit on the oil and gas by “netting” the gross profit. The
post-production expenses are not subtracted from the sales amount because the royalty
8 The New Mexico Trusts do not claim any of these costs do not qualify as “postproduction”
costs or are otherwise unreasonable. Their argument is limited solely to
applicability of the marketable condition rule in New Mexico.
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owners are responsible for post-production expenses; they are subtracted as an
accounting mechanism to determine the market value at the wellhead. Stated differently,
“value added” to the gas produced at the wellhead solely through the effort and expense
of the lessee must be deducted from an established market price of the improved product
in order to make an accurate estimate of the value of the gas at the wellhead. In simple
terms, if [A] the market value at the wellhead + [B] the value added in the production
process (post-production costs)9 = [C] the value of the processed natural gas (the sales
price of the processed gas), then [C] – [B] = [A]. Subtracting [B] does not shift some of
the costs of production to the lessors; it is an accounting adjustment designed to
effectuate the intention of the parties as it is expressed in the parties’ agreement—the
lease. The Fifth Circuit explained this rationale years ago:
[I]n the analytical process of reconstructing a market value where none otherwise
exists with sufficient definiteness, all increase in the ultimate sales value
attributable to the expenses incurred in transporting and processing the commodity
must be deducted. The royalty owner shares only in what is left over, whether
stated in terms of cash or an end product. In this sense he bears his proportionate
part of that cost, but not because the obligation (or expense) of production rests
on him. Rather, it is because that is the way in which [one] arrives at the value of
the gas at the moment it seeks to escape from the wellhead.
Freeland v. Sun Oil Co., 277 F.2d 154, 159 (5th Cir. 1960).
To recap: It is incorrect to assert, as the Trusts do, that royalty owners are “bearing
9 These post-production costs are similar to the accounting term, Cost of Goods
Sold (COGS). See https://www.investopedia.com/terms/c/cogs.asp (“Cost of goods sold
(COGS) is the direct costs attributable to the production of the goods sold in a company.
This amount includes the cost of the materials used in creating the good along with the
direct labor costs used to produce the good.”).
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post-production costs.” They are not.10 With that matter now settled, we press on to the
marketable condition rule.
B. New Mexico Has Not Adopted the Marketable Condition Rule
As we will explain, the New Mexico Supreme Court has decided oil and gas well
operators have a duty to market the gas for the benefit of the royalty owners and that duty
is one implied as a matter of law (irrespective of the parties’ agreement). See Davis v.
Devon Energy Corp., 218 P.3d 75, 86 (N.M. 2009). However, it has yet to decide
whether that duty includes the marketable condition rule.11 Normally, in such
circumstances, we would attempt to predict what that Court would do. Coll v. First Am.
10 The following example may help. Suppose a car salesman has a contract giving
him a 10% commission per car, based on the price the dealership paid to acquire the car.
Whether the car is marked up $5,000 or $10,000, his commission does not change, since
it is based on what the dealership paid to acquire the car. One day he sells a car at a
$5,000 mark-up for a gross profit of $25,000. When it is time to pay his commission, no
one can find the bill giving the price the dealership paid for that car. But they all agree it
was sold for $25,000 at a mark-up of $5,000. Of course, that is all they need. By
subtracting the mark-up from the gross price, they figure out the dealership must have
paid $20,000 for the car. The salesman gets his $2,000 commission. In that context, we
see how little sense it would make to say that the salesman is “bearing the cost” of the
dealership’s mark-up, because we subtracted the mark-up from the gross profit. We only
subtracted the mark-up to figure out what the dealership paid for the car, which is the
contracted-for basis of the salesman’s commission. This is also how the netback
calculation works, and it makes just as little sense to say that the royalty owners are
bearing the post-production costs. The point is to calculate the royalty payments based
on the market value at the wellhead—the price that would have been paid at the wellhead
if there were a market there.
11 Colorado, on the other hand, appears to abide by what the parties’ agreement
says on the matter. See Garman v. Conoco, Inc., 886 P.2d 652, 653-54, 659-60 (Colo.
1994) (en banc) (when a royalty agreement is silent with respect to allocation of postproduction
costs, the implied duty to market prevents the lessee from deducting those
costs from the royalty payment).
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Title Ins. Co., 642 F.3d 876, 886 (10th Cir. 2011). However, “when a panel of this Court
has rendered a decision interpreting state law, that interpretation is binding on district
courts in this circuit, and on subsequent panels of this Court, unless an intervening
decision of the state’s highest court has resolved the issue.” Wankier v. Crown Equip.
Corp., 353 F.3d 862, 866 (10th Cir. 2003) (emphasis added).
The district judge decided the issue was put to rest in Elliott Indus. Ltd. P’ship v.
BP Am. Prod. Co., 407 F.3d 1091 (10th Cir. 2005). Energen argues we are obligated to
honor Elliott’s holding. We agree.
C. Elliott Decides the Issue
In Elliott, the royalty agreement required the well operators to pay Elliott
Industries a royalty on the “‘market value of the gas at the well.’” 407 F.3d at 1100. To
establish that value, the operators deducted their post-production costs from the
downstream sales price, including 39% of the natural gas liquids, which the operators
retained as an in-kind fee for their processing services (i.e., the netback or workback
method, see supra at 8-10). Id. Elliott objected to the 39% in-kind deduction, arguing,
among other things, it was not a legitimate post-production cost and its deduction results
in an underpayment of royalty. Id. at 1100, 1107. It claimed the operators had an
implied duty to market the gas, which also prohibited them from deducting postproduction
costs from the royalty payment. Id. at 1113. We concluded the operators had
complied with the implied duty to market under New Mexico law—they were actively
producing gas, processing it, and selling the refined natural gas and natural gas liquids.
Id. (citing Darr v. Eldridge, 346 P.2d 1041, 1044 (N.M. 1959) (the implied duty to
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market requires oil and gas well operators/lessees “to make diligent efforts to market the
production in order that the lessor may realize on his royalty interest.”) (quotation marks
Elliott (like the New Mexico Trusts here) claimed the implied duty to market
included the marketable condition rule, which prohibited the operators from deducting
the costs necessary to make the product marketable, including the cost of removing the
natural gas liquids from the gas, in calculating the value of the gas at the wellhead under
the netback method. Id. at 1113-14. Not so, we said: “This conception of the implied
duty to market finds no support within New Mexico case law.” Id. at 1114 (emphasis
Although the New Mexico Trusts acknowledge Elliott, they provide a host of
technical reasons why we should ignore it. Energen, of course, presents contrary
arguments. That particular debate may seem arcane and the arguments tedious, but the
discussion is necessary. So, as some residents of the Tenth Circuit might say: Saddle up!
The New Mexico Trusts tell us Elliott’s discussion of the marketable condition
rule is dicta. According to them, the panel had already decided the implied duty to
market claim failed because Elliott had dismissed its claim for breach of the royalty
agreement. They are incorrect, both factually and legally.
Elliott did not dismiss its breach of contract claim; it never brought one. 407 F.3d
at 1107 (“Elliott . . . has never asserted an unequivocal and straight-forward contract
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claim alleging a breach of [the operators’] express obligations to pay royalties. In fact,
Elliott steadfastly disclaims any cause of action for breach of an express contract.”). Our
discussion of the marketable condition rule was not dicta.
In lieu of raising a breach of contract claim, Elliott relied on the implied duty to
market, claiming that duty should govern because the contract did not specifically
address the 39% in-kind processing fee. Id. at 1111. According to Elliott, that duty
prohibited the operators from deducting from the royalty payment the cost of removing
the natural gas liquids from the gas. Id. at 1107-08, 1113. We rejected that argument on
First, Elliott could not show that an implied duty to market existed in that case
because other than asserting that the royalty agreement did not address the 39%
processing charge, it did not otherwise rely on the agreement. Id. at 1113. Without the
agreement, we could not determine “whether any implied duty to market was intended by
the parties or would contradict the express provisions of that agreement . . . . This court
cannot speculate as to what [the agreement] contain[s] or how to construe the scope of
any implied covenant to market that may exist.” Id. (citing Cont’l Potash, Inc. v.
Freeport-McMoran, Inc., 858 P.2d 66, 80 (N.M. 1993)).
Second, even ignoring Elliott’s “strategic choice” not to rely on the express terms
of the royalty agreement, the implied duty to market claim “still fail[ed].” Id. Elliott
tried to use the implied duty to supplement the express provisions of the agreement,
including the “at the well” language. Id. Doing so was improper, we said, because
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“under New Mexico law, covenants are not implied for subjects that are treated in
express provisions.” Id. (citing Cont’l Potash, Inc., 858 P.2d at 80). Moreover, the
operators were actively marketing the gas and New Mexico law did not support the
applicability of the marketable condition rule. Id. at 1113-14.
Our rejection of the marketable condition rule constituted an alternative rationale
for rejecting Elliott’s implied duty to market claim. “Alternative rationales, . . . providing
as they do further grounds for the Court’s disposition, ordinarily cannot be written off as
dicta.” See Surefoot LC v. Sure Foot Corp., 531 F.3d 1236, 1243 (10th Cir. 2008); see
also United States v. Rohde, 159 F.3d 1298, 1302 (10th Cir. 1998) (alternative holdings
are not dicta).
Admittedly, we could have resolved Elliott’s implied duty to market claim without
reaching the applicability of the marketable condition rule. However, we could have also
decided the claim solely by rejecting the marketable condition rule. The New Mexico
Trusts have not explained why we ought label the latter dicta, but not the former. See
Rohde, 159 F.3d at 1302 n.5 (10th Cir. 1998) (“Were this panel inclined to engage in the
business of labeling as dicta one of the two alternative grounds . . . , it would then
confront defendant’s failure to demonstrate why that label ought not adhere to the
alternative which is innocuous to her theory, rather than to the alternative which
E. Reliance on Continental Potash
The New Mexico Trusts also attack Elliott for relying on Continental Potash, Inc.
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v. Freeport-McMoran, Inc., 858 P.2d 66 (N.M. 1993), which they say was subsequently
limited by Davis, 218 P.3d 75. For what it’s worth, we agree with their reading of Davis;
but it doesn’t help them.
In Continental Potash, the New Mexico Supreme Court said covenants will not be
implied on contracting parties when the issue is expressly covered in the parties’
agreement. 858 P.2d at 80 (“The general rule is that an implied covenant cannot co-exist
with express covenants that specifically cover the same subject matter”; “when the
contract between the parties speaks to the obligation sought to be implied, courts will not
write that implied obligation into the contract.”). However, in Davis, the Court clarified
that Continental Potash was speaking only to those covenants “implied in fact,” i.e.,
those implied based on the language of the parties’ agreements. 218 P.3d at 85. Not
surprisingly, covenants implied in fact require analyzing the parties’ intentions as
expressed in their agreement. Id. But, as Davis makes clear, there are also covenants
implied as a matter of law. Id. Duties implied by law apply to the parties irrespective of
the language of their agreement. Id. Davis said the implied duty to market falls in the
latter category. Id. at 86. It thus undermines Elliott, but only in part.
The Elliott panel relied on Continental Potash as one basis for rejecting Elliott’s
implied duty to market claim—it could not determine whether an implied duty to market
existed without knowing from the royalty agreement whether such duty was intended, nor
could Elliott use the duty to supplement the royalty agreement’s terms because covenants
are not implied for subjects expressly treated in an agreement. Elliott, 407 F.3d at 1113.
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Davis, however, said the implied duty to market is one implied by law, which does not
require analysis of the parties’ agreement and applies notwithstanding that agreement.12
But Davis does not undermine Elliott’s decision that the marketable condition rule
finds no support in New Mexico law because, semantics aside, the Davis Court explicitly
declined to decide that issue, finding it not ripe for review. Id. at 80-81 (“[W]e do not
12 Energen argues: “[E]ven duties implied by law in New Mexico cannot be used to
overcome or negate an express term contained within a contract.” (Appellee’s Answer
Br. at 21 (quotation marks omitted).) Therefore, as it would have it, even assuming the
marketable condition rule applied in New Mexico and it was a duty implied by law, it
could not be used to overcome the express terms of the royalty agreements, which it
claims direct it to pay royalty on the value of the gas at the wellhead and thereby allow it
to deduct its post-production costs. See Creson v. Amoco Prod. Co., 10 P.3d 853, 857-59
(N.M. Ct. App. 2000) (agreement calling for payment of royalties based on the “net
proceeds derived from the sale of . . . [g]as at the well” is unambiguous and means the
royalties are to be paid “based on the value of the . . . gas as it emerges at the well head”
and allows for deductions of post-production costs); see also Abraham, 685 F.3d at 1200
(“In order to determine the market value of the unprocessed gas at the well, producers sell
refined natural gas . . . at the tailgate of the processing plant (i.e., after processing) to
establish a base sales amount, and deduct from that amount costs for transportation,
processing, etc. This is called a ‘netback’ or ‘workback’ method, and it is widely
accepted as the best means for estimating the market value of gas at the well where no
such market exists.”). In support of this proposition, it cites Sanders v. FedEx Ground
Package Sys., Inc., 188 P.3d 1200, 1203 (N.M. 2008).
But Sanders involved the implied covenant of good faith and fair dealing. Id.
Moreover, it relied, in part, on Continental Potash, before it was clarified by Davis.
Energen also ignores Davis, which said the implied duty to market is one implied by law
and therefore applies regardless of what the parties’ contract says on the issue. 218 P.3d
at 86. We therefore decline to resolve this issue based on the language of the parties’
royalty agreements, even though (1) other jurisdictions which have adopted the
marketable condition rule do not apply it if the royalty agreement says otherwise, see
infra note 16, and (2) the New Mexico Trusts concede in their reply brief that they have
never “argued . . . that the marketable condition rule, and the implied duty to market to
which the marketable condition rule attaches, trumps express contractual language.”
(Appellants’ Reply Br. at 3.)
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address the existence of the marketable condition rule in New Mexico . . . . [N]othing in
this opinion should be construed as either the recognition or disapproval of the
marketable condition rule, its scope, or its applicability.”). It assumed the marketable
condition rule applied in New Mexico only because the trial judge concluded it did. Id. at
80. Even more to the point, the New Mexico Supreme Court subsequently clarified: “[I]n
Davis we declined to address whether the marketable condition rule is inherent in the
implied covenant to market, and whether, if recognized in New Mexico, the marketable
condition rule would be implied in fact or at law.” ConocoPhillips Co. v. Lyons (Lyons),
299 P.3d 844, 860 (N.M. 2012) (citation omitted).
Notwithstanding that fairly clear statement, the New Mexico Trusts nevertheless
tell us the Davis Court implicitly imposed the marketable condition rule on New Mexico.
According to the Trusts, the Davis Court surely would have recognized the extreme waste
of judicial resources that would occur for it to grant class certification in that appeal
based on the trial judge’s adoption of the marketable condition rule only to later say in a
second appeal that the marketable condition rule does not exist in New Mexico, thereby
requiring decertification. As they would have it, this shows the Davis Court intended to
affirm the judge’s adoption of the rule.
We reject the argument because it flies in the face of the Court’s explicit statement
that it was not deciding whether the marketable condition rule applied. 218 P.3d at 80.
Indeed, subsection B is titled “WE DO NOT ADDRESS THE MARKETABLE
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CONDITION RULE.” Id. It doesn’t get much clearer than that.13
F. Reliance on Creson
The New Mexico Trusts argue we should not follow Elliott because it relied on
Creson v. Amoco Prod. Co., 10 P.3d 853 (N.M. Ct. App. 2000). In doing so, they tell us,
Elliott rejected the marketable condition rule because “this conception of the implied duty
to market finds no support within New Mexico case law . . . because this duty imagined
by the plaintiff is inconsistent with New Mexico law because the express terms of the
Elliott royalty obligations direct the royalty to be paid on the value of the gas ‘at the
well.’” (Appellants’ Op. Br. at 18 (alterations incorporated).) A careful reading of Elliott
reveals this to be incorrect.
Elliott argued (1) the implied duty to market included the marketable condition
rule and (2) the operators’ fee for processing the gas “is a production cost that must be
borne by [the operators] because there is no market for the unprocessed gas at the
13 The New Mexico Trusts’ reliance on our decision in Abraham doesn’t help
them. There, a class of royalty owners alleged, among other things, that BP breached the
implied duty of good faith and fair dealing in underpaying royalties. 685 F.3d at 1201,
1204. The district judge refused to give a jury instruction on the claim. Id. at 1204.
Without knowing why the judge refused the instruction, we could not review the
decision. Id. at 1205. We also rejected BP’s argument that this claim was foreclosed by
Elliott: “The plaintiff in [Elliott] did not articulate the necessity of such a duty to
effectuate the express provision. Additionally, subsequent pronouncements by the New
Mexico courts may influence the analysis. See Davis v. Devon Energy Corp., 147 N.M.
157, 218 P.3d 75 (2009); Sanders v. FedEx Ground Package Sys., Inc., 144 N.M. 449,
188 P.3d 1200 (2008).” Id. The New Mexico Trusts seem to suggest that Abraham calls
Elliott’s discussion of the marketable condition rule into doubt. But Abraham was only
referring to Elliott’s discussion of the implied duty of good faith and fair dealing.
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wellhead.”14 407 F.3d at 1114 (emphasis added). As to the first argument, we said the
marketable condition rule “finds no support within New Mexico case law.” Id. With
regard to the second, we decided the argument was “inconsistent with New Mexico law
because the express terms of the royalty obligations direct the royalty to be paid on the
value of the gas ‘at the well.’”15 Id. We cited Creson only for the latter proposition. Id.
Creson had nothing to do with our rejection of the marketable condition rule in New
The New Mexico Trusts also say Creson is factually dissimilar because, unlike in
this case, the parties in Creson stipulated that the gas was marketable at the wellhead. 10
P.3d at 856. We repeat: Elliott did not rely on Creson in rejecting the marketable
condition rule in New Mexico. Creson did not address the marketable condition rule.
G. Sister States and New Mexico District Courts
The Trusts also tell us that since Elliott was decided in May 2005, several New
Mexico district courts have recognized the marketable condition rule as part of the
implied duty to market and none has ruled otherwise. See Davis, 218 P.3d at 79-80
(collecting cases). The Trusts also point us to other states, including Colorado,
14 Elliott tried to classify the processing fee in that case as a “production” cost,
rather than a “post-production” cost, because production costs (the costs associated with
bringing the gas forth from the earth) must generally be borne by the well operator.
Lyons, 299 P.3d at 853.
15 It was inconsistent with New Mexico law because the operators’ fee for
processing the gas was a post-production cost (as in this case), which is deductible from
the sales price of the processed gas to arrive at the “market value of the gas at the well.”
See supra note 12.
- 20 -
Oklahoma, and West Virginia, which have adopted the marketable condition rule. That is
an overstatement. Colorado, for example, applies it only when the parties’ agreement is
silent on the matter.16 They also rely on a footnote in Anderson Living Trust v. WPX
Energy Production, LLC, in which Federal District Judge James O. Browning criticized
Elliott and stated his belief that “if and when the Supreme Court of New Mexico
determines that the existence of the marketable condition rule is ripe for review, it will
find that the rule is included in oil-and-gas contracts as part of the implied duty to
market.” 27 F. Supp. 3d 1188, 1225 n.12 (D.N.M. 2014).
We are not bound by these decisions. However, we are bound by Elliott, absent
an intervening decision by the New Mexico Supreme Court or a state statute addressing
the issue. Wankier, 353 F.3d at 866. There has been no subsequent decision or statute.
Not only that, since Elliott was decided over twelve years ago, the New Mexico Supreme
Court, although given the opportunity to do so, has not expanded the implied duty to
market to include the marketable condition rule with respect to private oil and gas leases.
See Lyons, 299 P.3d at 860; Davis, 218 P.3d at 80-81; Ideal v. Burlington Res. Oil & Gas
16 See Garman, 886 P.2d at 653-54, 659-60 (Colo. 1994) (en banc) (when a royalty
agreement is silent with respect to allocation of post-production costs, the implied duty to
market prohibits the lessee from deducting those costs from the royalty payment); see
also Wood v. TXO Prod. Corp., 854 P.2d 880, 882-83 (Okla. 1992) (“We interpret the
lessee’s duty to market to include the cost of preparing the gas for market . . . . If a lessee
wants royalty owners to share in compression costs, that can be spelled-out in the oil and
gas lease.”); Wellman v. Energy Res., Inc., 557 S.E.2d 254, 265 (W. Va. 2001) (“[I]f an
oil and gas lease provides for a royalty based on proceeds received by the lessee, unless
the lease provides otherwise, the lessee must bear all costs incurred in exploring for,
producing, marketing, and transporting the product to the point of sale.”).
- 21 -
Co. LP, 233 P.3d 362, 365 (N.M. 2010).
The Trusts ask that we certify this issue to the New Mexico Supreme Court.17
“When state law permits, [we] may . . . certify a question arising under state law to that
state’s highest court according to that court’s rules.” 10th Cir. R. 27.2(A)(1). New
Mexico law permits the New Mexico Supreme Court to “answer a question of law
certified to it by a court of the United States . . . if the answer may be determinative of an
issue in pending litigation in the certifying court and there is no controlling appellate
decision, constitutional provision or statute of this state.” N.M. Sat. Ann. § 39-7-4. The
issue concerning the applicability of the marketable condition rule satisfies these criteria,
but that does not end the debate.
Whether to certify is ultimately left to our discretion. Lehman Bros. v. Schein, 416
U.S. 386, 391 (1974); see also Armijo v. Ex Cam, Inc., 843 F.2d 406, 407 (10th Cir.
1988) (“Whether to certify a question of state law to the state supreme court is within the
discretion of the federal court.”). While certification saves “time, energy, and resources
and helps build a cooperative judicial federalism,” Lehman Bros., 416 U.S. at 391, it “is
not to be routinely invoked whenever a federal court is presented with an unsettled
question of state law.” Armijo, 843 F.2d at 407; Boyd Rosene & Assocs., Inc. v. Kan.
Mun. Gas Agency, 178 F.3d 1363, 1365 (10th Cir. 1999) (“Certification is never
17 The Trusts also sought certification in the district court. The judge denied their
request, relying on Elliott.
- 22 -
compelled, even when there is no state law governing an issue.”). We have a “duty to
decide questions of state law even if difficult or uncertain.” Copier ex rel. Lindsey v.
Smith & Wesson Corp., 138 F.3d 833, 838 (10th Cir. 1998). “[W]e will not trouble our
sister state courts every time an arguably unsettled question of state law comes across our
desks. When we see a reasonably clear and principled course, we will seek to follow it
ourselves.”18 Pino v. United States, 507 F.3d 1233, 1236 (10th Cir. 2007).
We decline to certify in this case. Elliott decided the issue for this Circuit. Over
twelve years have passed since then and the New Mexico Supreme Court has not
included the marketable condition rule in the implied duty to market, despite having the
opportunity to do so in Davis and Ideal. And Lyons specifically declined to apply the
marketable condition rule to state leases where the statutory language contained in the
leases required royalty to be paid on the “net proceeds derived from the sale of such gas
in the field,” which the Court interpreted to allow the lessee to deduct its post-production
costs. 299 P.3d at 848, 850, 859-60. Moreover, the New Mexico legislature has not
addressed the issue. None of the arguments the New Mexico Trusts have provided for
not following Elliott are persuasive. While New Mexico law certainly implies a duty on
oil and gas well operators to diligently market the product for the benefit of the royalty
18 The New Mexico Trusts also suggest we should certify this issue because the
only reason they are in federal court is due to the Class Action Fairness Act, 28 U.S.C.
§ 1332(d)(2). They claim “[t]hey should not be penalized because they are in federal
court.” (Appellants’ Op. Br. at 12.) But, following their logic, we could never deny
certification in a case where federal jurisdiction derives from § 1332, including diversity
jurisdiction. “Such a rule would be clearly wrong.” See Copier ex rel. Lindsey, 138 F.3d
- 23 -
owners, see Darr, 346 P.2d at 1044, we continue to find no indication the New Mexico
Supreme Court would expand that duty to include the marketable condition rule, in
particular where, as in this case, the language of the royalty provision allows for the
deduction of post-production expenses. See supra note 12 (citing Creson, 10 P.3d at 856-
60, and Abraham, 685 F.3d at 1200 (10th Cir. 2012)); see also Lyons, 299 P.3d at 848,
The district judge properly dismissed the New Mexico Trusts’ implied duty to
market claim as it was based on the marketable condition rule, which does not exist in
II. New Mexico Gas Processors Tax Act – New Mexico Trusts
The State of New Mexico imposes a privilege tax, known as the “natural gas
processors tax,” on the third-party companies who process the gas for Energen. N.M.
Stat. Ann. § 7-33-4(A). The third-party companies pay the tax to the State but, pursuant
to their contracts with Energen, require Energen to reimburse them for their tax
payments. Energen in turn passes a proportionate share of this tax to the New Mexico
Trusts by deducting it from their royalty payment.19
19 Energen also occasionally deducted the tax from the Tatum Trust’s monthly
royalty payment even though its interest lies in wells in Colorado. However, it appears
the Tatum Trust was only assessed that tax when the gas from its wells was treated in a
processing plant located in New Mexico. The opening brief is unclear whether the Tatum
Trust is challenging the tax or simply the New Mexico Trusts. We need not resolve the
ambiguity because the answer to the narrow issue raised is the same irrespective of the
(Continued . . .)
- 24 -
The New Mexico Trusts think this deduction to be improper. Their argument is
narrow. Relying on a 1998 amendment to the statute (effective January 1, 1999), they
claim Energen cannot deduct the natural gas processors tax from their royalty payments
because they are not processors.
Prior to 1998, § 7-33-4 provided:
A. There is levied and shall be collected by the oil and gas accounting division of
the taxation and revenue department, a privilege tax on processors for the
privilege of engaging in the business of processing based on the value of their
products. The measure of the tax shall be forty-five one-hundredths of one percent
of the value of the products.
. . . .
C. Every interest owner is liable for this tax to the extent of his interest in the
value of such products or to the extent of his interest as may be measured by the
value of such products.
Blackwood & Nichols Co. v. N.M. Taxation & Revenue Dep’t, 964 P.2d 137, 139 (N.M.
Ct. App. 1998) (quotation marks omitted) (emphasis added).
In 1998 (effective January 1, 1999), the New Mexico legislature amended the Act.
Section 7-33-4(A) now reads:
There is levied and shall be collected by the department a privilege tax on
processors for the privilege of operating a natural gas processing plant in New
Mexico. This tax may be referred to as the “natural gas processors tax”.
The legislature eliminated the language making interest owners liable for the tax
(subsection C above). It also defined “processor” as “a person who operates a natural gas
named appellant—nothing in the New Mexico Gas Processors Tax Act or New Mexico
law prohibits a processor from passing its tax burden on to others.
- 25 -
processing plant.” See id. § 7-33-2(I).
We agree with the New Mexico Trusts that the amendment “shift[ed] the
responsibility for paying the [tax] from interest owners to processors.” See Amoco Prod.
Co. v. N.M. Taxation & Revenue Dep’t, 74 P.3d 96, 98 (N.M. Ct. App. 2003); see also
Blackwood & Nichols Co., 964 P.2d at 141 (“The 1998 legislative amendment of Section
7–33–4 clearly evinces a legislative intent to delete the requirement subjecting all
‘interest owners’ to liability for such tax . . . . The fact that the Legislature substantially
rewrote the provisions of Section 7–33–4 indicates that the change was intended to
modify the basis upon which the tax was previously levied. The change does not clarify
existing law, instead it materially changes the tax basis.”).20 But that begs the real
question presented here. It is not who is responsible for paying the tax to the State—the
third-party processing companies are responsible for paying it and they, in fact, do.
Rather, it is whether third-party processors can pass on all or part of that tax to the well
operator and, in turn, whether the operator can pass it on to the royalty interest owners.
The Supreme Court’s decision in Exxon Corp. v. Eagerton is instructive. 462 U.S.
20 The judge suggested the reason for the amendment:
In the context of the oil and gas industry, it is much more efficient for the state to
collect the tax from a handful of processors than from numerous royalty and/or
working interest owners. Instead of keeping track of all these owners and their
respective ownership interests, the state need only look to the processor.
(Appellants’ App’x at 1143.)
- 26 -
176 (1983).21 The State of Alabama imposes a severance tax on oil and gas extracted
from wells in the state. Id. at 178. Prior to 1979, the tax was imposed on the royalty
owners in proportion to their interests in the oil and gas produced. Id. at 179. In 1979,
the Alabama legislature increased the severance tax owed by well producers and
specifically exempted royalty owners from the tax increase (royalty-owner exemption):
“‘Any person who is a royalty owner shall be exempt from the payment of any increase
in taxes herein levied and shall not be liable therefor.’” Id. (quoting Ala. Code § 40–20–
2(d) (1979)). It also prohibited the well operators from passing the tax increase, either
directly or indirectly, on to their consumers. Id.
The well operators claimed the royalty-owner exemption violated the Contracts
Clause of the United States Constitution because it impaired their contracts with the
21 Interpreting the statute as the Trusts would have us do might create
constitutional concerns, which should be avoided when possible. Cf. Hernandez-Carrera
v. Carlson, 547 F.3d 1237, 1249 (10th Cir. 2008) (the canon of constitutional avoidance
provides that “where an otherwise acceptable construction of a statute would raise serious
constitutional problems, the Court will construe the statute to avoid such problems unless
such construction is plainly contrary to the intent of Congress.” (quotation marks
omitted)); see also Ashwander v. TVA, 297 U.S. 288, 348 (1936) (Brandeis, J.,
concurring) (“When the validity of an act of the Congress is drawn in question, and even
if a serious doubt of constitutionality is raised, it is a cardinal principle that this Court
will first ascertain whether a construction of the statute is fairly possible by which the
question may be avoided.” (quotation marks omitted)). As we will explain (see
discussion of the New Mexico Trusts’ fuel gas claims), Energen’s leases with those
Trusts allow it to deduct post-production costs from the royalty owed, as it has lawfully
done for years. The natural gas processors tax is a post-production cost. Reading the
statute to prohibit Energen from shifting the burden of the tax to the Trusts might well
impair its existing contracts with the Trusts in violation of the Contracts Clause. See U.S.
Const. art. I, § 10, cl. 1 (“No State shall . . . pass any . . . Law impairing the Obligation of
Contracts . . . .”). These leases are 70 to 90 years old and will continue as long as the
wells are producing.
- 27 -
royalty owners, which required the owners to reimburse them for the severance tax. Id. at
187-88 & n.9. The Supreme Court concluded the royalty-owner exemption did not
nullify the operators’ contractual obligations:
On its face [the exemption] provides only that the legal incidence of the tax
increase does not fall on royalty owners, i.e., the State cannot look to them for
payment of the additional taxes. In contrast to [the prohibition on passing the tax
increase through to consumers], the royalty-owner exemption nowhere states that
[operators] may not shift the burden of the tax increase in whole or in part to
Id. at 188-89 (emphasis added). Intended or not, its interpretation of the statute avoided a
constitutional problem. See supra note 21.
Similarly, nothing in the 1998 amendment to § 7-33-4(A) prohibits the processors
from passing the tax onto Energen or from Energen passing the tax onto the New Mexico
Trusts. The amendment simply prohibits the State of New Mexico from seeking payment
from the Trusts.
As a final matter, the Trusts rely on Amoco Prod. Co. and Blackwood & Nichols
Co. But those cases are not helpful. While they interpreted the amendment to § 7-33-4
as shifting the responsibility for paying the tax from royalty owners to processors, neither
case addressed whether the processors/operators can properly shift the burden of the tax
onto the royalty owners via contract.
The summary judgment on this claim was proper.
III. Gas Used as Fuel—New Mexico Trusts and Tatum Lease
This issue requires us to meld statutory and case law with various provisions in an
oil and gas lease. Those provisions include the royalty provision, which dictates how
- 28 -
much the lessee owes the owner of the mineral rights for the right to extract and sell oil
and gas from the land, and the “free use” clause, which governs the right of a lessee to
use oil and gas (fuel gas) from the leased properties in its operations. Our task is to
interpret these provisions and harmonize them to give effect to the intent of the parties.
Pursuant to its contracts with the third-party processing companies, Energen pays
these companies, in part, with gas produced from wells on the leased properties to fuel
their operations (in-kind compensation). Energen does not pay royalty on the gas so used
to either the New Mexico Trusts or the Tatum Trust.
The Trusts object, claiming they are entitled to royalties on the gas used as fuel
(fuel gas). Because the resolution of this issue depends in large part on the applicable
lease agreements, we address each Trust separately but discuss the Anderson and
Pritchett Trusts together because their interests are subject to one lease.
A. Anderson and Pritchett Trusts
The royalty provision in the Anderson and Pritchett Trusts’ lease provides in
[T]he lessee shall monthly pay lessor as royalty on gas marketed from each
well where gas only is found, one-eighth (1/8) of the proceeds if sold at the well;
or if marketed by lessee off the leased premises, then one-eighth (1/8) of its
market value at the well. The lessee shall pay the lessor (a) one-eighth (1/8) of the
proceeds received by the lessee from the sale of casinghead gas, produced from
any oil well; (b) one-eighth (1/8) of the value, at the mouth of the well, computed
at the prevailing market price, of the casinghead gas produced from any oil well
and used by lessee off the leased premises for any purpose or used on the lease
premises by the lessee for purposes other than development and operation thereof
. . . .
(Appellants’ App’x at 338 (emphasis added).)
- 29 -
The lease also contains a “free use” clause: “The lessee shall have the right to use
free of cost, gas, oil and water found on said land for its operations thereon, except water
from the wells of the lessor.” (Id.) “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 properties in the operation of said lease.” Lyons, 299 P.3d at 855
(citing 3 Williams & Meyers, § 644.5 at 573-574.1). “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.
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.”22 Id. at 856 (emphasis added) (citing 2 W.L.
Summers, The Law of Oil and Gas, § 33:12, at 160 (3d ed. 2008), and 3 Williams &
Meyers, § 661.4, at 763).
The Trusts claim the express terms of the royalty provision require royalty to be
paid on all gas produced, particularly that used off the leased premises for any purpose.
They further claim the “free use” clause limits Energen’s free use of gas to that occurring
on the leased premises. According to them, because the third-party companies’ use of the
gas occurs off the leased premises, the clause is inapplicable and they are entitled to
22 A “free use” clause may also dictate a lessor’s right to the free use of gas for
domestic purposes. See 3A W.L. Summers, The Law of Oil and Gas, § 30:4 (3d ed.
- 30 -
royalty on that gas.
The argument is problematic. The royalty language consists of two disparate
parts. The first relates to “gas only” wells and requires royalty to be paid on “gas
marketed from each well” and provides for a royalty of 1/8 of the market value at the
wellhead when, as here, the gas is marketed off the leased premises. The provision
relating to “casinghead gas” (gas produced from an oil well) is remarkably different and
more specific—a royalty payment is due for “casinghead gas produced from any oil well
and used by lessee off the leased premises for any purpose or used on the lease premises
by the lessee for purposes other than development and operation thereof.” (Appellants’
App’x at 338.) The record does not clearly reveal whether the wells at issue are gas only
or oil wells producing “casinghead gas.” The parties and the judge seem to have assumed
the gas at issue was produced from gas only wells.
In their arguments to us, the Trusts rely on the “casinghead gas” royalty
provisions, but by our reckoning they have never claimed or provided any evidence that
the gas used as fuel in this case is “casinghead gas.” Accordingly, we look to the royalty
provision relating to gas only wells.
That royalty provision requires royalty to be paid only on “gas marketed from
each well” (sold gas) and royalty is owed on the market value of the gas at the wellhead
if, as here, it is marketed off the leased premises. As we have already explained (see
supra at 8-10 and note 12), this allows Energen to deduct its post-production costs,
including the fuel gas (which is an in-kind post-production cost), from the sales price of
- 31 -
the gas to arrive at that value. Although the marketable condition rule would perhaps
produce a different result, the New Mexico Supreme Court has not adopted that rule and
we see no indication that it will or, if it does, it will apply the rule when the royalty
provision requires royalty to be paid on the market value of the gas at the well, which
allows for deduction of post-production costs from the downstream sales price to arrive at
that value. Moreover, the fact the lease expressly imposes a royalty on casinghead gas
“used off the leased premises for any purpose” strongly suggests royalty payments are
not expected on the production from gas only wells, which contain no such restriction.
The “free use” clause supports this conclusion. Since nothing else in the lease
suggests otherwise, the “free use” clause is only self-limiting. The Trusts seem to agree,
as their arguments focus only on the applicability of Lyons in assessing the scope of the
“free use” clause.
In arguing the “free use” clause obviates any requirement for it to make the royalty
payment the Trusts seek, Energen relies on Lyons. In it, the New Mexico Supreme Court
analyzed a “free use” clause in a state lease which granted the lessees “the right . . . to the
free use of oil [and] gas . . . from said lands” “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 . . . .” 299 P.3d at 855 (quotation marks omitted). The New Mexico
Supreme Court concluded this language gave the lessee the right “to the free use of oil
and gas produced from the leased premises, regardless of where the use occurred, so long
- 32 -
as the oil and gas was being used to further the economical operations of said land.” Id.
at 856 (first emphasis in original, second emphasis added). Because the gas used by the
post-production service providers in Lyons was for the development and production of
the leased premises, it was not subject to royalty. Id.
The Trusts tell us Lyons does not control because it explicitly said its decision
does not apply to private leases, only state leases. However, while the Court said “[t]his
opinion should not be interpreted as affecting private oil and gas leases agreements,” id.
at 860 (emphasis added), it did so in its discussion of the marketable condition rule. Id. at
860. It did not limit its analysis of the “free use” clause to state leases.
The Trusts also argue Lyons is distinguishable because the “free use” clause in that
case required the gas to be “from said lands” for the exploration, development, and
production of oil and gas “thereon and therefrom.” They claim these terms imply a use
away from the leased premises. In contrast, the “free use” clause found in their lease uses
only the term “thereon,” which they claim implies the use will occur on the leased
“Thereon” means “on that.” See https://www.merriamwebster.
com/dictionary/thereon; see also Black’s Law Dictionary (10th ed. 2014)
(defining “thereon” as “[o]n that or them”). Applying this plain meaning to the “free
use” clause in the Anderson and Pritchett Trusts’ lease, it seems the clause requires that
the use of gas “found on said land” be for operations “on that” land. But in Lyons, the
Court relied on Bice v. Petro-Hunt, L.L.C., 768 N.W.2d 496 (N.D. 2009), a decision from
- 33 -
the Supreme Court of North Dakota, which interpreted a nearly identical “free use”
clause to simply require that the use of the gas be in furtherance of the lease operations,
regardless of where that use occurs.
In Bice, Petro-Hunt sent casinghead gas to one of its three central tank batteries,
where the gas was separated from the oil and water. 768 N.W.2d at 503. The oil, gas,
and water were then transported in separate streams to the processing plant where the gas
was made marketable. Id. Petro-Hunt took processed gas from the plant and used it to
fuel its central tank batteries. Id. Some of the leases in that case contained “free use”
clauses giving Petro-Hunt “‘the right to use, free of cost, gas, oil and water produced on
said land for its operation thereon.’” Id. (emphasis added). The royalty interest owners,
like the Anderson and Pritchett Trusts, argued Petro-Hunt owed them royalty on the gas
used as fuel. Id. They claimed the “free use” clauses’ use of the phrase “operations
thereon” limited Petro-Hunt’s free use of gas to that occurring on the leased premises. Id.
The central tank batteries were located off the leased premises. Id.
The North Dakota Supreme Court disagreed:
The record indicates the functions performed by the central tank batteries
are the same functions normally performed at individual well sites. Instead of
having a battery at each well site, Petro–Hunt consolidated these facilities into
three central tank batteries. The record demonstrates the use of the central tank
batteries benefits both Petro–Hunt and the [royalty interest owners]. The central
tank batteries are beneficial to both . . . because they are more efficient resulting in
less overall use of lease gas, minimize surface disturbance and allow hydrocarbons
to be recovered from gas on which the lessors receive royalties.
Interpreting the “free use” clause to only allow Petro–Hunt to use residue
gas on the leased premises could lead to an absurd result because it would require
lessors who have a central tank battery on their property to bear the entire burden
- 34 -
of the “free use” clause, notwithstanding benefits conferred on the other lessors.
The record demonstrates the residue gas is used in furtherance of overall lease
operations because it is used to fuel equipment which separates the oil, gas and
water into separate streams, thereby allowing the [the processing plant] to process
the gas into a marketable product and to recover other products sold at the plant
tailgate. Since the residue gas is used in furtherance of the leased operations, we
conclude the district court did not err in determining the “free use” clause
allowed Petro–Hunt to use the residue gas off of the leased premises to fuel the
central tank batteries.
Id. at 503-04 (emphasis added).
By favorably citing Bice, the New Mexico Supreme Court seems to have
suggested that if confronted with a “free use” clause similar to that in the Anderson and
Pritchett Trusts’ lease it would rule the same way. Thus, the phrase “operations thereon”
in the Anderson and Pritchett Trusts’ “free use” clause is not a limitation on where the
use of the gas may occur but rather a limitation on the purposes for which the gas may be
used—furtherance of the lease operations. That is an expansive provision, easily satisfied
in this case. Gas is provided to third-party processors as partial payment for the services
they render in making the gas marketable (and the Trusts’ royalty payments are only
reduced by their pro-rata share of the expense). That furthers the lease operations.
Without it, there would be no viable market for the product. The Trusts do not contend
otherwise. Instead, they attempt to distinguish Bice.
They claim the reason Bice held the “free use” clauses allowed Petro-Hunt to use
gas free of cost to fuel its central tank batteries off the leased premises is because the
functions performed by those tank batteries were those normally performed on the leased
premises. They say the operations performed in this case by the third-party processors
- 35 -
are not normally performed on the leased premises.
We do not read Bice so narrowly. As the court noted, the central tank batteries
performed functions normally performed at individual well sites. 768 N.W.2d at 503.
However, it did so to emphasize that to interpret the “free use” clauses to only allow
Petro-Hunt to use the gas free of cost on the leased premises would lead to an “absurd
result”—it would require the royalty owners with a central tank battery on their property
to bear the entire burden of the “free use” clause, notwithstanding the benefits conferred
by the central tank battery on the other royalty owners. Id. at 504. Nevertheless, the
Court also explicitly held: “Since the residue gas is used in furtherance of the leased
operations, we conclude the district court did not err in determining the ‘free use’ clause
allowed Petro–Hunt to use the residue gas off of the leased premises to fuel the central
tank batteries.” Id. (emphasis added).
The Trusts also cite an oil and gas treatise, which in turn cites an Oklahoma case,
Vogel v. Cobb, 141 P.2d 276 (Okla. 1943). In Vogel, the Oklahoma Supreme Court
interpreted a clause in an oil and gas lease entitling the lessee to the free use of “‘water
produced on said land for its operation thereon.’” Id. at 279. It said the clause did not
give the lessee the right to use water from the land to supply houses located on other
lands, even though the occupants of the houses were the lessee’s employees. Id. Vogel is
an Oklahoma case; we are concerned with New Mexico law. The New Mexico Supreme
Court has interpreted similar language differently. The use of water from the leased
premises to supply employee housing would, remotely, be a use in furtherance of the
- 36 -
lease operations. But saying so strains credulity beyond elastic limits and is therefore
unlike the use of gas in this case.
Energen was entitled to summary judgment on the Anderson and Pritchett Trusts’
fuel gas claim.
B. N-R Trust
The N-R Trust’s overriding royalty agreement requires Energen to pay “at the
prevailing field market price therefor at the time when produced a royalty in cash or oil
amounting to seven and one half (7 ½) percentum of all oil and gas produced from the
lands embraced in said primary lease . . . .”23 (Appellants’ App’x at 342 (emphasis
added).) The Trust tells us the royalty provision requires Energen to pay royalty on all
gas produced, including that used as fuel. True enough.
The royalty provision is explicit: royalty is owed on all oil and gas produced from
the leased lands. In other words, royalty is to be paid on all gas emerging from the
wellhead of each well within the area described in the lease. The royalty provision does
not exclude gas used as fuel and, unlike the Anderson and Pritchett Trusts’ lease, this
lease does not contain a “free use” clause. Energen has been using fuel gas royalty free,
as it could if the lease had a “free use” provision permitting it do so. Its practice is not
23 The underlying lease agreement from which the N-R Trust’s overriding royalty
interest derives is a 1924 federal lease. The parties do not provide copies of that lease but
we assume the quoted language from the N-R Trust’s overriding royalty interest
accurately repeats the language of the federal lease, which is, of course, controlling.
Production costs cannot be deducted from the overriding royalty interest; post-production
costs may, however, if payment is to be made on the value of the gas at the well.
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only contrary to the royalty provision of the lease, it also impermissibly reads into the
lease a “free use” clause that is not there.24 See Thompson v. Potter, 268 P.3d 57, 62
(N.M. Ct. App. 2011) (“Our public policy is to give effect to the intention of the parties,
and we do not rewrite parties’ agreements.”). But that is only half of the issue; the value
of the fuel gas at the wellhead must be computed (as with the Anderson and Pritchett
Trusts) using the netback method.
Although royalty is owed on all gas produced, it need be paid based “at the
prevailing field market price . . . at the time when produced.” The field market price at
“the time when produced” is the value of the gas at the wellhead, where production
occurs, when production occurs. In calculating that value, Energen may deduct the value
of the fuel gas consumed as a post-production cost (along with other post-production
costs), but it must also pay royalty on the wellhead value of the fuel gas consumed.
Determining the wellhead value of the fuel gas consumed cannot be made on this record,
24 The district judge concluded that even though the N-R Trust’s lease did not
contain a “free use” clause, New Mexico law allowing for the deduction of postproduction
costs to calculate the value of gas at the wellhead necessarily allowed Energen
to the free use of fuel gas (because the fuel gas is an in-kind post-production cost that can
be deducted to arrive at the value of the gas at the wellhead). He relied on language in
Lyons, indicating that fuel gas is a post-production cost which is neither sold nor saved by
the operator and therefore is not subject to royalty. But that statement from Lyons came
in its discussion of a “free use” clause, see 299 P.3d at 856, something the N-R Trust’s
lease does not contain. Moreover, as we have explained, the N-R Trust’s royalty
provision requires royalty to be paid on all gas produced, not just gas that is marketed.
And, while the fuel gas can be deducted as a post-production cost from the sales price of
the processed gas (non-fuel gas) to arrive at that gas’s value at the wellhead, Energen
must also pay royalty on the fuel gas (at its value at the wellhead).
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given the myriad variables involved. For instance, the district judge voiced at least part
of the valuation problem—lost volume. No royalty is due, he said, on lost gas volume.
See Appellants’ App’x at 1139-40. Perhaps so25; we express no opinion. If correct, it
underscores the need to determine the amount of fuel gas consumed, post-production, as
well as its wellhead value. At the end of the day, the royalty owed on fuel gas may be
small, but it must be determined. However, if the measurements necessary to compute
the wellhead value of gas cannot be cost effectively made, reasonable estimates may
We have identified a unifying theme, not only here but for the Anderson and
Pritchett Trusts’ lease as well: royalties are to be calculated according to the lease terms
and unless the lease provides otherwise the netback method should be used to determine
the wellhead value of any gas at issue. We have every confidence that, aided by counsel,
the district judge, who has demonstrated a comprehensive understanding of Oil and Gas
Law, can find a way through the thicket.
The summary judgment entered in favor of Energen on the N-R Trust’s fuel gas
claim was improper. A remand is necessary for appropriate factual findings and required
C. Tatum Trust
25 But compare the N-R Trust’s royalty provision requiring royalty to be paid on
all gas “produced” with the Anderson and Pritchett Trusts’ lease, which requires royalty
only on gas (from a gas well) “marketed” (sold). Does the former, but not the latter,
require royalty to be paid on lost gas?
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The Tatum Trust’s royalty interests derive from two leases covering wells located
in Colorado. The leases have “free use” clauses, but a “free use” clause may be limited
by other lease provisions (see supra at 27-30). The Tatum Trust lease has exactly that
kind of limitation: it provides the Trust “shall not bear, directly or indirectly, any
production or post-production cost or expenses, including . . . cost or expenses for
storing, separating, dehydrating, transporting, compressing, treating, gathering or
otherwise rendering marketable or marketing the [gas], and no deduction or reduction
shall be made for any such costs and expenses in computing any payment . . . to be made
to Lessor.” (Appellants’ App’x at 390, 403.)
Energen seems to make “heads I win, tails you lose” arguments. For purposes of
the New Mexico Trusts’ fuel gas claims, it labels the fuel gas an in-kind post-production
cost, which is deductible under the royalty provisions of those Trusts’ agreements and
New Mexico law (which does not apply the marketable condition rule). But it shies away
from that label when discussing the Tatum Trust’s fuel gas claim, most likely because
Colorado prohibits oil and gas well operators like Energen from deducting from the
royalty payment the costs necessary to render the gas marketable, unless the lease
provides otherwise. See Garman v. Conoco, Inc., 886 P.2d 652, 653-54, 659-60
(Colo. 1994) (en banc). These leases do not provide otherwise; in fact, they explicitly
prohibit Energen from deducting post-production costs from the Trust’s royalty. Energen
cannot have it both ways—treating the fuel gas as an in-kind post-production cost when
convenient but ignoring that treatment when it is not. In any event, as we now explain,
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the “free use” clause does not help it.
“Free use” clauses are generally limited to the use of gas on the leased premises
unless the clause expressly states otherwise. 3 Williams & Meyers, § 661.4 at 763. In
this case, applying Colorado’s rules of contract interpretation, the plain language of the
“free use” clauses and the royalty provisions lead us to conclude the general rule
applies—the use of the gas must occur on the leased premises to be free of royalty. See
Pepcol Mfg. Co. v. Denver Union Corp., 687 P.2d 1310, 1313 (Colo. 1984) (in construing
a contract, we look to the contract as a whole and seek “to ascertain and give effect to the
mutual intent of the parties”; “[i]n the absence of contrary manifestation of intent in the
contract itself, contractual terms that have a generally prevailing meaning will be
interpreted according to that meaning”).
The “free use” clauses in the Tatum Trust’s leases provide: “[Energen] shall have
free use of oil, gas and water from said land . . . for all operations hereunder.”
(Appellants’ App’x at 392, 483 (emphasis added).) The plain meaning of “hereunder” is
“under or in accordance with this writing or document” or “[a]s provided for under the
terms of this document.” See https://www.merriam-webster.com/dictionary/hereunder;
https://en.oxforddictionaries.com/definition/hereunder; see also Black’s Law Dictionary
(10th ed. 2014) (defining “hereunder” as “[l]ater in this document” or “[i]n accordance
with this document”). The term “hereunder” qualifies the phrase “all operations.” So, to
be free of royalties, the use of the gas must be for operations “under or in accordance”
with the lease or “as provided for under the terms” of the lease.
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Looking to the terms of the Tatum Trust’s leases, the premises was leased “for the
sole and only purpose of exploring, drilling, and operating for and producing oil and gas
and of laying pipelines, storing oil and building tanks, telephone lines, roads and
structures thereon to produce, save, care for, treat and transport said substances produced
from the land leased hereunder.” (Appellants’ App’x at 403 (emphasis added).) As we
read it, the purpose of the lease was to allow Energen to produce oil and gas from the
leased premises and to store oil and build infrastructure on the leased premises. Thus, the
operations called for by the lease are those occurring on the leased premises. As a result,
the plain language of the “free use” clauses in these leases suggests only gas used on the
leased premises is free of royalty. Fuel gas used off the leased premises is not a free use.
But even if the “free use” clauses do not supply a geographical limitation, the
royalty provisions do. They differ from those appearing in the New Mexico Trusts’
agreements. They provide:
Lessee shall pay Lessor royalty . . . on all gas . . . produced from a well on the
leased premises or on lands pooled with the leased premises and sold or used off
the leased premises regardless of whether or not such [gas is] produced to the
credit of Lessee or sold under a contract executed or binding on Lessee. Should
[gas] be sold under a sales contract not binding on Lessor, Lessor’s royalty shall
be calculated by using the highest price paid for any of the [gas] produced from
the well from which such [gas] was produced.
(Appellants’ App’x at 403 (emphasis added).) As the Tatum Trust argues, these
provisions require Energen to pay it royalty on gas (1) produced from a well on the leased
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premises and (2) sold or used off the leased premises.26 Gas used as fuel by the thirdparty
processing companies is “used off the leased premises.”27 Under the express terms
of the royalty provisions, royalty is owed to the Tatum Trust on this gas.
The district judge imposed limitations on the royalty provisions not supported by
the express language of the leases. First, he decided royalties were due only when
Energen sells gas off the leased premises but the Trust receives no money for that sale.
But the provisions explicitly apply not only to the sale of gas off the leased premises but
also to the use of gas off the leased land. He further limited the royalty provisions to
require royalty to be paid only on gas that is “produced” and (critically) concluded that
fuel gas is not produced. Apparently, he equated “produced” with “processed.” The
leases do not define “produced.” However, while the gas at the wellhead, including the
fuel gas, may not be processed, it is produced. See 8 Williams & Meyers, at 830
(defining “[p]roduction of gas” as “[t]he act of bringing forth gas from the earth”).
Indeed, even Energen labels the fuel gas as an in-kind post-production cost.
26 Energen argues the Tatum Trust waived any reliance on the royalty provisions
because other than citing them, it does not otherwise provide any legal argument. We
agree the Trust’s argument is less than eloquent. However, the Trust does say “the
express terms of the royalty language in the . . . Tatum leases . . . address whether royalty
is due on the value of natural gas used off the lease premises” and then highlights the
relevant portions of the leases. (Appellants’ Op. Br. at 26-27.) It repeats this argument
later in its brief: “The royalty language in the Tatum lease states that royalty is due for
gas ‘used off the lease premises.’” (Id. at 34.) We consider the argument sufficiently
27 Nothing in our discussion should be read to apply to the use of gas to fuel postproduction
processes occurring on the leased premises.
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Relying on Lyons and Bice, Energen says the “free use” clauses should be
interpreted to allow it to use gas free of cost so long as the use is in furtherance of the
lease operations, irrespective of whether that use occurs on or off the leased premises.
Lyons controls as to the Anderson and Pritchett Trusts’ fuel gas claim. But
because the Tatum Trust’s interests lie in wells located in Colorado, its law controls the
fuel gas debate. The district judge concluded Colorado would decide the issue similar to
the New Mexico Supreme Court largely because the Tatum Trust produced no cases
holding otherwise. But the converse is also true; the judge cited no Colorado cases
adopting the Lyons rationale and we can find none. We are left with applying generally
In addition to interpreting a “free use” clause containing the phrase “thereon,”
Bice, a North Dakota case, interpreted a “free use” clause giving the operator the right to
“free use of oil, gas and water from said land . . . for all its operations hereunder.” 768
N.W.2d at 503 (emphasis added). It concluded this clause allowed the operator to use the
gas free of cost so long as the gas is used in furtherance of lease operations, regardless of
where that use occurs. Id. The only reason we relied on Bice in resolving the New
Mexico Trusts’ fuel gas claim is because it was cited favorably in Lyons. No Colorado
case has done so.
Energen also tells us our reading of the royalty provisions would nullify the “free
use” clauses and argues the more specific “free use” clauses prevail over the broad
language of the royalty provisions. But its arguments are based on there being a conflict
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between the royalty provisions and the “free use” clauses. There is no conflict. The
royalty provisions require royalty to be paid on gas produced from the leased premises
and sold or used off the leased premises. The “free use” clauses, on the other hand,
suggest Energen may use gas from the leased premises free of royalty only when the use
of the gas occurs on the leased premise or, at the very least, when the use accords with
the other provisions of the leases, including their royalty provisions.
At first blush it may appear our resolution of the Tatum Trust’s fuel gas claim is
inconsistent with that of the Anderson and Pritchett Trusts’ fuel gas claim. Any
“inconsistency,” however, derives from the different state law and lease provisions
applicable to each.
We reverse the summary judgment and remand the Tatum Trust’s fuel gas claim
to the district court for reconsideration.
IV. New Mexico Oil and Gas Proceeds Payment Act—New Mexico Trusts
The New Mexico Oil and Gas Proceeds Payments Act requires a producer, like
Energen, to pay royalty owners “not later than forty-five days after the end of the
calendar month within which payment is received by payor for production . . . .” N.M.
Stat. Ann. § 70-10-3. Energen did so, except it held royalty funds from a well in a
suspense account from July 2007 to December 2012 until a title issue relating to that well
was resolved in favor of the N-R Trust. It paid these funds to that Trust in February
The New Mexico Trusts agree Energen was entitled to hold these funds in
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suspense while the title issue was resolved. See id. § 70-10-4(A) (“In instances where
payments cannot be made within the time period provided in [§] 70-10-3 . . . , the payor
shall create a suspense account on his books for such interest or may interplead the
suspended funds into court.”). However, they claim Energen failed to pay interest on
these funds, as required by N.M. Stat. Ann. § 70-10-4 (“The person entitled to payment
from the suspended funds shall be entitled to interest on the suspended funds from the
date payment is due under Section [§] 70-10-3 . . . .”). See First Baptist Church of
Roswell v. Yates Petroleum Corp., 345 P.3d 310, 313 (N.M. 2015) (under N.M. Stat.
Ann. § 70-10-4, royalty interest owners are entitled to interest on funds held in suspense).
The district judge did not address whether interest was owed, even though he
recognized at the summary judgment hearing that “there is an issue on whether there
should be interest [on the late payment made to the N-R Trust].” (Appellants’ App’x at
1084.) Nevertheless, Energen claims the New Mexico Trusts failed to raise this issue in
the district court. But they did.
In their complaint, the New Mexico Trusts alleged Energen had failed to timely
pay them “in numerous instances” in violation of the Act. (Appellants’ App’x at 258.)
They sought payment of all amounts due, “together with interest at the statutory rate.”
(Id. at 259.) In response to Energen’s motion for summary judgment, the New Mexico
Trusts changed their tale, claiming Energen “occasionally pays royalty late,” pointing to
the February 23, 2013 royalty check. (Id. at 460.) However, they again claimed Energen
“failed to pay [them] interest on these late payments.” (Id. at 465.) And, at the summary
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judgment hearing, they argued Energen “owe[s] interest” on the late payments. (Id. at
1084.) The New Mexico Trusts clearly raised the issue.
Energen also seeks to distinguish First Baptist Church of Roswell, which, it tells
us, merely concluded that royalty owners could not contract away their right to receive
statutory interest on royalties held in suspense under the Act. Energen says no such
contract exists here. We agree that was the ultimate result of that case. 345 P.3d at 313-
16. However, to get to that result, the New Mexico Supreme Court first interpreted N.M.
Stat. Ann. § 70-10-4. It said:
Subsection A requires that when proceeds cannot be paid on time, the funds shall
be held in a suspense account or interpleaded into court. Subsection B provides
that interest owners shall be entitled to receive interest on suspended funds that
they are legally entitled to receive. The language in the statute clearly reflects the
Legislature’s intent to mandate that interest owners who are legally entitled to
proceeds, but who are not paid on time, shall receive interest on funds that are
rightfully owed to them.
Id. at 313 (citations omitted). The N-R Trust was entitled to interest on the suspended
Finally, Energen claims the New Mexico Trusts provided no evidence that the NR
Trust was not paid interest on the funds. However, the Trusts provided documentation
on how the amount of the funds was calculated. As we read it, nothing in that
documentation indicates whether the amount the N-R Trust received included statutory
interest. (Appellants’ App’x at 468-81.) On remand, the issue deserves clear resolution.
The district judge erred in granting summary judgment to Energen on this claim.
Outcome: We AFFIRM the district court’s dismissal and summary judgment orders with
respect to the New Mexico Trusts’ claims regarding the marketable condition rule and the
New Mexico Natural Gas Processors Tax Act. We also AFFIRM the summary judgment
order with respect to the Anderson and Pritchett Trusts’ fuel gas claim. We REVERSE
the summary judgment order with respect to the N-R Trust’s and Tatum Trust’s fuel gas
claims and the N-R Trust’s claim under the New Mexico Oil and Gas Proceeds Payments
Act and REMAND those matters to the district court for a decision consistent with this
opinion. We DENY the Trusts’ motion to certify the marketable condition rule issue to
the New Mexico Supreme Court. We will address Energen’s motion to seal its
supplemental appendix in a separate order.