INTERPRETING THE ROYALTY OBLIGATION BY
LOOKING AT THE EXPRESS LANGUAGE: WHAT
A NOVEL IDEA?'
by Bruce M Kramer"
I.
INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . • • . . . . . . . • . . • ..
II. THE HISTORICAL ANTECEDENTS
III. WHATIS PRODUCTION? .......•.........................
N. MARKET VALUE, MARKET PRICE, AMOUNT REALIZED? ALL FOR
ONE AND ONE FOR ALL? ......................•.........
V. AT THE WELL? IN THE PIPELINE? ATTHEBURNERTIp? THE
ApPLICATION OF THE NETBACK METHODOLOGY MEETS
RESISTANCE ..............................•..........•
VI. EXPRESS WORDS? IMPLIED COVENANTS? TRAIN WRECK OR
NEVERTHETWAINSHALLMEET?
223
224
233
241
252
258
I. INTRODUCTION
It is indeed a daunting task to wax eloquent about a subject matter for
which one's peers and mentors have felled many a tree beforehand.! Butthe
role of this article is somewhat more limited than attempting to develop a
grand, unifYing theme for dealing with royalty interests. Instead, this article
provides a brief historical perspective on the express language that has been
used in the royalty clauses.2 Royalty clauses are not uniform.' I have spent
a good deal of time in the past five to ten years reviewing the language in
* This· paper is a revised version of a paper presented at the Rocky Mountain Mineral Law
Foundation's Special Institute on Private Oil and Gas Royalties held in Denver, Colorado in September
2003. The author wishes to thank the Foundation for permission to revise the article for publication in the
Texas Tech Law Review.
.. Maddox Professor of Law, Texas Tech University School of Law, 1974. B.A., University of
California at Los Angeles, 1968; J.D., 1972; L.L.M., University of Illinois, 1975.
I. See. e.g., EUGENE KUNTZ, A TREATISEONTlIELAWOFOILANDGAS §§ 38-42 (1989); PATRICK
MARTIN & BRUCEM. KRAMER, WILLIAMS &MEYERB O'LAND GAS LAW §§ 640-656.9 (2002) [hereinafter
WILLlAMS&MEYERS): Owen L. Anderson, Royalty Valuation: ShouldRoyalty Obligations be Determined
Intrinsically, Theoretically, or Realistically? 37 NAT. RES.J. 547 (l997); Richard C. Maxwell, OilandGas
Roya/ties-A Percentage of What?, 34 ROCKY Mm. MIN. L. INST. 15~1 (1988); David E. Pierce.
Rethinking the Oil and Gas Lease, 22 TuLSALJ. 44S (1987); Glen L. Houston & Maurice H. Merrill,A
Suggested Oil and Gas Lease Form, 43 NEB. L. REv. 471 (1963); Earl A. Brown, Elemental Principles of
the Modern Oil and Gas Lease. 17 MONT. L. REv. 39 (1955); Robert E. Hardwicke, Jr., Problems Arising
Out afthe Royalty Clauses in Oi/ and Gas Leases in Texas, 29 TEx. L. REv. 790 (1951); A,W, Walker, Jr.,
The Nature a/the Property Interests Created by an Oil and Gas Lease in Texas. 7 TEx. L. REv. 1,32
(1928); 10 TEX. L. REv. 291 (1932).
2. See discussion infra Part II.
3. See generally Anderson, supra note I, atS49-52 (discllssinghowjurisdictions interpret royalty
clauses differently).
TEXAS TECH LAWREVIEW
224
[Vol. 35:223
literally thousands of oil and gas leases and assignments of oil and gas leases.
While the overall structure ofthe basic royalty clause has remained unchanged
over the past fifty years, the language used to describe either the delivery or
payment obligation substantially varies.' This article discusses and analyzes
some of the important terms found in many royalty clauses.' As Professor
Anderson and I have noted, this parsing-of-Ianguage approach may lead to
substantial differences in interpretation between states and sometimes within
a single state.' In contrast to this parsing approach, several courts apply the
extrinsic approach whereby courts use factors not gleaned from the language
of the instrument to determine the parties' intent.' Professor Merrill and, to
a certain extent, Professor Anderson are exponents of this approach.'
Nonetheless, this article argues that when the parties have articulated their
intent through express language, the court's principal role, in the absence of
fraud, duress, or mutual mistake, is to enforce the agreement as written. One
ofthe root causes ofthe disparate treatment ofroyalty clauses in the past two
decades has been the change of external circumstances regarding the
production and marketing of both oil and natural gas that does not mesh with
the language used by the parties in instruments which may be decades old?
But without an understanding ofwhy and how certain royalty clause language
became widespread, our attempts to resolve our current problems often prove
haphazard at best. Perhaps everyone would have been better off and the
national forests saved from an onslaught of articles, tomes, and treatises if
lease drafters had followed the simple advice given by Professor A.W.
Walker, Jr., in 1932: "Too much care cannot be devoted to the preparation
of a royalty clause in an oil and gas lease.,,10
II. THE HISTORICAL ANTECEDENTS
Some of the earliest oil and gas leases did not reserve to the mineral
owner what is now called a royalty interest. Instead, a type of shared profits
agreement using a fifty percent sharing arrangement was utilized.
Nonetheless, within a few years it became commonplace for the owner ofthe
See discussion infra Parts II-V.
See discussion infra Parts III-V.
6. See Anderson, supra note 1; Bruce M. Kramer, RoyaltyInterests in the United States: Not Cut
from the Same Cloth, 29 TuLSA L.J. 449, 450-84 (1994).
7. See John Burritt McArthur, The Mutual Benefit Implied Covenant for Oil and Gas Royalty
Owners, 41 NAT. RESOURCES!. 795, 866 (2001).
8. See Maurice H, Merrill, The Oil and Gas Lease-Major Problems, 41 NEB. L. REv. 448. 51518 (1962); Anderson. supra note I. at 604, 610. Two ofthe leading propo~ents ofthis extrinsic approach
are John BurrittMcArthurand Jacqueline Weaver. See, e.g., McArthur, supra note 7, at 866-67; Jacqueline
Lang Weaver, When Express Clauses Bar Implied Covenants, Especially in Natural Gas Marketing
Scenarios, 37 NAT. REsOURCESJ. 491, 491-544 (1997).
9. See discussion infra Part n.
10. Walker,supranote1,at291.
4.
5.
!
!i
!
2004]
INTERPRETING THE ROYALTY OBLIGATION
225
mineral estate to reserve a smaller fraction, typically one-eighth, of all of the
oil collected. II But the origin ofthe one-eighth fraction as the norm is clouded
in history.12 The earliest leases reported show a royalty share of as much as
one-third of the oil producedY Yet many of the earliest cases provide for a
one-eighth in kind royalty for oil wells and a cash payment for gas wells. I4
One of the earliest printed oil and gas lease forms, first distributed around
1870, provided for the "usual royalty ofone-eighth ofthe oil produced, but no
payments for gas."" But by 1880, the flat rate royalty clause for gas began to
appear in printed form leases." By the tum of the twentieth century, few
reported cases described the shared profits arrangement, preferring the typical
royalty arrangement." No explanation has ever been proffered for the demise
of the shared profits agreement, but as with the no-term lease, it disappeared
from the oil and gas scene in a reasonably short period oftime.
By the decade ofthe 191 Os, the leading oil and gas treatise identified the
following seven methods that were currently in vogue for the fixing of the
rents or royalties in a mining or oil and gas lease:
(I) a fixed sum; or an (2) annual or other periodical sum; or (3) a royalty on
the amount of the minerals or oil mined or produced, payable at fixed
intervals or times; or (4) a royalty, not, however, less in the aggregate than a
specified sum each year; or (5) a royalty accompanied by a covenant to mine
a certain minimum amount or pay a certain sum thereon; or (6) in case of a
gas lease, to bore so many wells and pay so much a well, or forfeit a certain
sum per well for a failure to bore the required number; or (7) in case ofan oil
lease, to pay a certain percentage of the oil taken out of the premises. "
11. Leslie Moses, The Evolution andDevelopment ofthe Oil andGas Lease, 2 INST. ON OIL& GAS
L. & TAJ<'N 1,8 (1951).
12. Dean Eugene Kuntz suggested two possible reasons for the near-universal use afone-eighth
as the royalty fraction. KUNTZ, supra note 1. The first is that it appeared in printed fonns and reflected
an intent of the parties "to share equally in the profits from the land." ld. at 265. The second. and more
reasonable according to Dean Kuntz, is that "experience of the industry has led to the conclusion that a
royalty of one-eighth results in a division of production which is fair in the usual or ordinmy operation."
[d. In 1935, Ohio, California. Texas university lands, and Osage Nation lands were identified as locales
where the usual royalty fraction was one-sixth. SAMUEL GLASSMIRE, LAw OF OIL AND GAS LEASES AND
ROYALTIES 185 (1st ed. 1935) (hereinafter GLASSMlRE 1).
13. V.B. ARcHER, ARCHER'S LAw AND PRACTICE IN OIL AND GAS CASES 135-36 (1911): see Funk
v. Halderman, 53 Pa. 229 (1867) (involving alease giving one..fuird to the landlord); see also Ohio Oil Co.
v. Lane, 52 N.B. 791 (Ohio 1898) (involving an oil royalty ofone-sixth).
14. ARCHER, supra note 13, at 132·35. For several early cases providing for a one-eighth royalty,
see Parish Fork Oil Co. v. Bridgewater Gas Co., 42 S.B. 655 (W. Va. 1902) and Lowther Oil Co. v. MilIerSihleyCo., 44 S.E. 433 (iN. Va 1903).
15. SAMUEL GLASSMlRE, LAW OF OIL AND GAS LEASES AND ROYALTIES 56-57 (2nd ed. 1938)
(hereinafter GLASSMlRE II).
16. Id. at 57.
17. See, e.g., Far West Oil Co. v. Witmer Bros. Co., 77 P. 61 (Cal. 1904) (involving an agreement
by the lessee to pay one-half of the costs of drilling and operation and evenly split the proceeds from the
sale of the oil with the lessor).
18. W.W. THORNTON, THE LAw RELATING TO OIL AND GAS 287-88 (1912). In McArthur v.
226
TEXAS TECH LAW REVIEW
[Vol. 35:223
Thus, early on scholars established that gas production was to be treated
separately from oil production and that the traditional reservation of a
fractional share of production was not the only remuneration received by the
lessor."
But by the mid I 920s, standard oil and gas leases, whose basic structure
and organization still prevails today, were in wide distribution. In Richard
Leroy Benoit's Cyclopedia of Oil and Gas Forms published in 1926, the
author lists twenty different types of oil royalty clauses and an even larger
number of gas and casinghead gas royalty clauses." The oil royalty clauses
seen in 1926 mirror the type of oil royalty clauses seen in oil and gas leases
fifty years later." Several examples ofthe classic in-kind-only royalty clause
are provided that contain differences concerning the point of delivery. Some
of the clauses provide:
To deliver to the credit of the lessor, free of cost, in the pipe line to which
lessee may connect its wells, the equal one-eighth part ofall oil produced and
saved from said leased premises ...
If oil should be found in paying quantities on said premises, the lessee
shall deliver as royalty to said lessor, free of expense, one-eighth part of all
the oil saved from that produced, such delivery to be made either into tanks
supplied by lessor, with connections by lessor provided, or into any pipe line
that may be connected with the wells;
The grantee agrees to deliver to the grantor in gauge tanks on the
premises and free of cost, the equal ... part of all oil produced and saved
from the premises."
Tionesta Gas Co., the court finds that a royalty clause that provides for an in kind delivery of gas as wen
as a clause requiring a fixed payment for each gas well drilled where gas is taken offthe premises and sold
were in conflict and gave precedence to the fixed payment clause. 28 Pa. Super. Ct 568 (1905). All twelve
ofthe oil and gas leases listed by Thornton in the appendix provide for a fixed payment gas royalty clause.
THORNTON, supra, at 91943.
19. THORNTON, supra note 18. One treatise published in 1920 defines arayatty as "[r]ent reserved
in kind as a percentage ofthe oil, coal or are mined." R.S. MORRISON & EMILIO DE SOTO, OIL AND GAS
RIGHTS 977 (1920). The absence of any reference to natural gas in the definition suggests that the fixed
payment methodology for gas wells was still widely used. See id. It should also be noted that the above
authors make the following statement: "Thetenns 'net proceeds' and 'net profits' seem to be synonymous."
Id. atl42.
20.
21.
RICHARD LEROY BENOIT, CYCWPEOlA OF OIL AND GAS FORMS 161-82 (1926).
Walker, supra note I, at 32·33. A.W. Walker, Jr. noted in 1928 that
[t]he royalty on oil is an agreed portion ofthe oil produced and saved from the leased premises,
nonnally one~ighth. Payment ofthis royalty may be provided for in one oftwo ways: first, by
delivering the agreed portion of the oil free of cost to the credit of the lessor in the pipe line to
which the well may be connected by the lessee (or into storage tanks); or, second, the lessee may
agree to pay the lessor the current market price ofthe stipulated portion ofthe oil produced and
saved.
/d.
22. BENOIT, supra note 20, at 161~62. The first clause comes from the ubiquitous Producers 88
lease used in Texas and analyzed in several Texas court opinions such as Stephenson v. Glass, 276 S.W.
1110 (Tex. Civ. App.-San Antonio 1925, writrefd)andAndersv. Johnson, 276 S.W. 678 (Tex. Comm'n
1
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INTERPRETING THE ROYALTY OBLIGATION
227
In addition, several clauses provide for either a lessor or lessee option
whereby the in kind delivery obligation may be changed to a payment
obligation.23 Some of these clauses provide:
The lessee shall deliver to the credit ofthe lessor, as royalty, free of cost, in
the pipe lines to which lessee may connect his wells, the equal one-eighth part
of all oil produced and saved from the leased premises, or at the Jessee's
option, may pay to the lessor for such one-eighth royalty the market price for
oil oflike grade and gravity prevailing on the day such oil is run into the pipe
line or into storage tanks.
To pay and deliver to the credit of lessor, free of cost, in the pipe line
or pipe lines to which lessee may connect its well or wells, the equal oneeighth part ofall oil produced and saved from the premises, or at the lessor's
election to pay in cash the current market value oflessor's one-eighth interest
in said oil."
All but one ofthe twenty oil royalty clauses are one paragraph in length and
reasonably short. Some refer to posted market price while others allocate the
costs of storage or building a pipe line between the parties. Only one of the
model clauses is lengthy and talks about the sale of the royalty oil at the
prevailing market price. It also allocates the cost of constructing storage
facilities on the premises. Interestingly enough, this longer royalty clause
authorizes the lessee to make a $.05 per barrel charge for storing or
transporting the oil, or both, to the third-party purchaser should the lessee not
purchase the royalty oil on its own account. 2S
These oil royalty clauses raised some ofthe same issues now being raised
regarding the allocation ofcosts and the role ofexpress and implied covenants
in determining how much is owed under gas royalty clauses.'· For example,
is there a difference between the express obligation to deliver to a pipeline and
the express obligation to deliver to tanks? It was generally perceived in the
1920s that an express covenant to deliver to a pipeline carried with it the duty
to put the oil in marketable condition by the removal of water, basic
sediments, or other foreign substances that might contaminate the oil stream."
But what about the circumstance where the lessee is given the option to
App. 1925).
23. BENOIT, supra note 20, at 161-62.
24. Id.
25. ld. Also reported in Benoit are model clauses dealing with oil payments out oftbe lessee's
share upon the attainment of production or production in paying quantities. ld. at 166-68.
26. See discussion infra Part IV.
27. L. MILLS & J.C. WILLINGHAM. THE LAw OF OIL AND GAS § 129 (1926); see also Hamilton v.
Empire Gas & Fuel Co., 230 P. 91 (Kan. 1924) (explaining that the lessor should not be able to dictate tile
method of treating the oil as long as it is accurate, efficient, and fair); Clark v. Slick Oil Co., 211 P.464
(Okla 1923) (explaining that the agreement to deliver a pipeline gives rise to the duty to put the oil in
marketable fonn),
LY
VI • .JJ.~~.J
deliver to either a pipeline or a tank? The authors of a 1926 treatise make the
following observation:
If, on the other hand, the lessee covenants to deliver in tanks at the well or
into the pipe line, there is room for argument as to the construction. Ifhe (the
lessee) may elect which he will do then he would seem to satisfy his
obligation by putting the royalty oil in a tank without treating. If that be
correct then he would, in such a case, be entitled to charge lessor with his
proportion of the expense oftreatruent."
As evidenced from the model gas royalty clauses found in the 1920s, it
was still acceptable practice to provide for a cash payment for each gas well
producing gas. 29 During this era, the division of the gas royalty clause into
two parts was widely used: one dealing with gas well gas and. the other
dealing with gas from an oil well or casinghead gas." But the predominant
forms apparently still provided for a fixed payment for each well producing
gas well gas or casinghead gas." During this period oftime, some gas royalty
clauses in the Appalachian Basin provided for a sliding scale royalty payment
based on various factors including pressure and volume." The oil and gas
lease used by the Department of the Interior for Indian lands changed from a
fixed amount per gas well in 1908 to a fractional royalty payment obligation
by 1926.33 The modern form, whereby the gas royalty calculation
methodology differs depending on what is done with the gas produced, does
not appear to be widely used early in this decade. The predominant form of
payment requirement was share of the "net proceeds" from the sale of the
natural gas, although "prevailing market price" also appeared in some of the
model clauses." However, the origins ofthe distinction between gas sold or
used off the premises and gas not so sold or used appears to date back to this
.......... 'J
period of time, An oil and gas lease forms book published by the influential
Mid-Continent Oil and Gas Association in I926 provides five model oil and
gas leases all of which provide that when gas is either sold or used off of the
premises, fractional royalty payments are owed. 35 In several gas royalty
clauses from this vintage, the language used makes clear that gas used by the
lessee on the premises is royalty free, notwithstanding the fact that the gas has
been produced and saved." These clauses are the precursor to the modern free
use clauses that make it explicit that royalty is not due on gas used on the
premises by the lessee.
By the 1930s, little appreciable difference inhered in the oil royalty
clauses in widespread use." The model lease form published in a 1935
treatise provides for the standard in kind royalty of one-eighth for all "oil
produced and saved from the leased premises" or, at the lessee's option, the
payment obligation ofone-eighth ofthe "market price for oil oflike grade and
gravity prevailing on the day such oil is run into the pipe line, or into storage
tanks."" The gas royalty clause, on the other hand, was beginning to assume
the form that has become prevalent in the modem oil and gas lease. This same
treatise provides several different model oil and gas leases." The first lease
provides for a divided royalty obligation depending on the source of the gas
and what is done with the gas after production.
The lessee shall pay lessor, as royalty, one-eighth of the proceeds from the
sale ofthe gas, as such, for gas from wells where gas only is found .... The
lessee shall pay to lessor for gas produced from any oil well and used by the
lessee for the manufacture of gasoline, or any other product, as royalty, oneeighth ofthe market value of such gas. Ifsaid gas is sold by the lessee, then
as royalty one-eighth of the proceeds ofthe sale thereof."
Although the syntax is somewhat different, this type ofclause, as found in the
Mid-Continent 88 Rev. Form lease, clearly distinguishes between gas from gas
wells and gas from oil wells or casinghead gas,'l Legal uncertainty about the
28.
MILLS & WILLINGHAM, supra note 27, at 186.
See MORRISON & DE SOTO, supra note 19 (defining royalty without reference to natural gas
production). Benoit lists thirty-two gas royalty and rental clauses, over half of which are flat rate royalty
clauses and at least one provides for a fixed sum of$.02IMCF. BENOIT. supra note 20. at 170-79.
30. Robert E. Hardwicke, Evolution o/Casinghead Gas Law, 8 TEX. L. REv. 1 (1929).
31. fd. at 9, 15. 20 (citing examples of royalty clauses providing a lesser royalty for casinghead
gas wells than for gas well gas). But cf id. at 2S (discussing a royalty clause providing for the same
payment per well). See also MILLS & WILLINGHAM, supra note 27. at 620 (providing a "Magnolia No.3"
29.
Fonn that has two separate blanks forthe flat fee to be paid where gas is produced from oil wells depending
on whether the gas is used in the manufacture of gasoline).
32. See, e.g., Addleman v. Mm. Light & Heat Co., 100 A. 446, 446 (pa. 1917); Noble v. W. Pa.
Natoral Gas Co., 100 A. 480, 481 (Pa. 1917): Moore v. Ohio Valley Gas Co., 60 S.E. 401, 401 (W. Va.
1908).
33. See generally MILLS & WILLINGHAM, supra note 27, at 628. 634. The Oklahoma School Land
lease fonn ofthis era provides that for all natural gas produced, the lessor is entitled to an in kind delivery
ofthe natural gas or, at the lessor's option, a payment obligation based on the market value of the gas. fd.
at 647.
34. [d. at 172-74.
35. MID-CONTINENT OILAND GAS FORMS, 64, 66, 71-72, 77, 80 (PostPuh. 1926). Thefivefoffils
are categorized as two Mid·Continent fonns, a Texas Co. fonn, a Prairie Oil and Gas Co. fonn, and a
Louisiana lease form. Id; see also MILLS & WILLINGHAM, supra note 27, at 611-12 (identifying "Prairie
No. 461" as a fonn that contains a similar bifurcated flat rate and fractional gas royalty provision).
36. MILLS & WILLIN'GHAM. supra note 27, at 190.
37. GLASSMlREI, supra note 12, at 152.
38. Id. The lease is described as MidwContinent 88 Rev. fd. The same lease form is reproduced
in the second edition ofGlassmire's treatise that was published in ]938. GLASSMlREII, supra note 15, at
389.
39, GLASSMIRE I, supra note 12, at 330.
40.
41.
[d.
See id. The distinction between "oil well gas" and "gas well gas" probably arose in the 1920s
when the technology became available to strip out the "wet gas" from the dry gas stream. One other factor
that may have influenced the distinction between oil well gas and gas well gas was that in some states
production of natural gas liquids triggered payment under the oil royalty clause rather than the nominal
230
TEXAS TECH LAWREVIEW
[Vol. 35:223
status of casinghead gas, not only regarding what the royalty clause governed
but also whether it was conveyed in the lease, was undoubtedly a driving force
behind the inclusion of separate clauses for these two kinds of gas. 42 In
addition, the clause provides for a proceeds basis for making payments when
the gas is sold while providing for a market value basis for making payments
when no sale occurs because the gas is being treated and processed in the
manufacture of gasoline.43 When no proceeds are generated, the parties are
substituting an independent royalty calculation methodology that is obviously
not dependent on the sale of the natural gas stream."
It is also apparent that by the 1930s the parties to an oil and gas lease
were reacting to the wider use ofnatural gas for a myriad ofactivities. Again,
a leading treatise during this time period reproduces two model leases that
have lengthier gas royalty clauses attempting to deal with these wider
commercial uses." For example, one lease, identified as the ubiquitous Fonn
88-Producer' s, has two separate paragraphs to describe the royalty obligation
. for natural gas production." The first paragraph provides for the payment of
gross proceeds at the prevailing market rate for all gas used off the premises
and produced from a gas well. The second paragraph provides for a share of
the gross proceeds at the prevailing rate for gas produced from an oil well and
either used offth.e premises or for the manufacture of casinghead gasoline or
dry commercial gas. With the benefit of hindsight, many shortfalls in this
royalty clause emerge.47 What happens ifno proceeds are generated from the
gas that is used off the premises, such as ifthe lessee uses gas produced from
sums for gas well gas, while in other states natural gas liquids were treated as not being conveyed by the
oil and gas lease since there was no royalty provision included. See Hardwicke, supra note 30. at 16-25.
Oklahoma followed the rule that unless the term oil well gas or casinghead gas was used in the lease, the
lessee did not have the right to produce natural gas liquids. See Hammett Oil Co. v. Gypsy Oil Co., 218
P. 501, 504-06 (Okla. 1921). Texas, on the other hand, treated casinghead gas as oil requiring payment
under the oil royalty clause. Livingston Oil Corp. v. Waggoner, 273 S.W. 903, 908 (Tex. Civ. App.- .
Amarillo 1925, writ refd). But if the parties had a specific royalty clause covering oil well gas then the
royalty obligation would be fulfilled by payment ofthe per well charge and not payment oftbe one~ighth
share that the lessor retained for oil production. See Magnolia Petroleum Co. v. ConneUee. 11 S. W.2d 158.
159-60 (Tex. Comm'n App. 1928,judgm't adopted). Incredibly, however, if the lease provided for afixed
sum per well for gas well gas then the royalty would be payable under the oil royalty clause. See Reynolds
v. MoMan Oil & Gas Co., 11 S.w.2d 778, 786 (Tex. Comm'n App. 1928, jUdgm't adopted). When
casinghead gas is produced, the lessee need not make the fixed payment for production from a gas well,
even when the gas is being sold or used off the premises. See Twin Hills Gasoline Co. v. Bradford Oil
Corp., 264 F. 440, 441-42 (E.D. Okla 1919); see generallY WILLIAMS & MEYERS, supra note I, § 651.2.
42. WILLIAMS & MEYERS, supra note 1, § 656.
43. GLASSMlRE II, supra note IS, at 389·90.
44. See id.
45. See GLASSMlRE I, supra note 12, at 334-42.
46. See id. at 334-36.
47. Walker, supra note 1, at 294-300 (identifying various shortcomings multiple gas royalty
clauses). Professor Walker suggested that two clauses be used: one covering "dry gas" and one covering
"gas containing a commercially recoverable gasoline content," to replace the various descriptions used in
then-current gas royalty clauses. Jd. at 299. Unfortunately, his perspicacious insights were not followed.
2004]
INTERPRETING THE ROYALTY OBLIGATION
231
Well # I to assist in the production from Well # 2? Likewise, the second
paragraph has a similar weakness for gas well gas." The triggering events are
(1) use off the premises or (2) use in the manufacture of gasoline, neither of
which may result in a sale transaction and therefore not involve proceeds of
any kind. Finally, problems result from the contradictory use of a proceeds
methodology and a market rate or prevailing market rate methodology. What
happens if the gross proceeds exceed or are less than the prevailing market
rate for natural gas?
Finally, this 1935 treatise posits a Sinclair 88-Special Gas Fonn lease
that contains much lengthier and more complex gas royalty clause
provisions." The first paragraph of the royalty clause provides for a share of
the "proceeds received by lessee from the sale of gas from each well where
gas only is found while the same is being sold or used off the premises."'o
This eliminates the problem inherent in the previous fonn by covering both
sale and use, but does not deal with the problem of having to artificially
construct proceeds if the gas is used and not sold. The fifth paragraph deals
with casinghead gas and also provides for a proceeds payment when the gas
is "used off the premises for any purpose other than to extract gasoline
therefrom."'1 In addition, if the gas is "sold by lessee to extract gasoline
therefrom, lessor shall receive one-eighth ofthe amount received therefor by
the lessee."" The sixth paragraph deals with gasoline that is extracted from
any gas, be it produced from a gas or oil well." It provides for a value royalty
based on the Interior Department regulations and schedule as approved in
1917 and amended in 1921." Finally, the lease provides for a payment offifty
dollars per well for gas or casinghead gas produced from either an "oil well
or gas well and used offthe premises by lessee for any purpose other than for
the purpose of extracting gasoline therefrom.""
These lease fonns show an attempt by the parties to deal with events that
occur after the natural gas is produced. 56 While oil royalty clauses typically
run their course at the moment ofproduction, natural gas royalty clauses from
the earliest days have tried to predict what is going to happen to the gas and
then to provide an appropriate royalty calculation methodology. The problem
with this approach is that the uses ofnatural gas, and therefore its value, could
not be predicted. This is especially true with an instrument that may have a
life of fifty or more years. Because natural gas was originally seen as a waste
48.
49.
50.
51.
52.
53.
54.
55.
56.
GLASSMIRE I, supra note 12, at 335.
Id. at 338-40.
/d. at 339.
Id.
Id.
Id.
Id.
Id. at 340.
See generally id., at 329-421 (providing examples of lease forms).
TEXAS TECH LAWREVIEW
232
[Vol. 35:223
product and a hindrance to the production of oil, lessors made no effort to
demand taking their gas in kind. Thus, the early use of the small stipend per
gas well was readily accepted by lessors. As gas became a usable, and
therefore, a commercially valuable commodity, clauses began to appear that
required a payment, usually based on some type of proceeds formula, for gas
used off of the premises. Then came the discovery of the process by which
liquid hydrocarbons could be stripped from the natural gas stream. This led
to further clauses to deal with "wet" gas because it may have been unclear
whether such production should be covered under the oil royalty clause or the
gas royalty clause. These royalty clauses reflect the fact that what the lessee
did with the gas probably contributed to its value in the marketplace. By the
late I920s, royalty clauses were already regularly being segregated based on
the type ofproduction achieved. Thus, A.W. Walkernoted in 1928 that "[t]he
modern royalty clause contains separate provisions for the three physical
substances that may be produced, namely, oil, dry gas, and casinghead gas.""
This heritage explains the post-World War II standard, divided natural gas
royalty clause that has created substantial problems in the latter-half of the
twentieth century as natural gas markets developed in light of either federal
governmental regulation or de-regulation.
Another leading oil and gas scholar writing in the mid-1950s identified
the following royalty clause as typical:
In consideration ofthe premises the said lessee covenants and agrees:
I.
2.
3.
57.
To deliver to the credit oflessor, free ofcost in the pipe line to
which lessee may connect weBs on said land, the equal oneeighth part of all oil produced and saved from the leased
premises.
To pay lessor one-eighth (1/8) ofthe gross proceeds each year,
payable quarterly, for the gas from each weB where gas only
is found, while the same is being used offthe premises, and if
used in the manufacture of gasoline, a royalty on one-eighth
(1/8), payable monthly at the prevailing market rate for gas;
[free gas clause for lessor's dwelling] ...
To pay lessor for gas produced from any oil well and used off
the premises or in the manufacture of gasoline or any other
product a royalty of one-eighth (1/8) of the proceeds, at the
mouth of the well, payable monthly at the prevailing market
rate."
Walker. supra note I, at 32.
ROBERT E. SULLIVAN, HANDBOOK OF OIL AND GAS LAW 124 (1955). In another fonn manual
published in 1952, the author identifies some twelve model leases. all of which have the basic structure of
58.
theclause cited above. CURTISOAKES.STANDARDOILANDGASFORMS (1952). All ofthe oil royalty fonns
provide for alessee option to pay the lessor for her royalty oil using either currentor prevailing market price
2004]
INTERPRETING THE ROYALTY OBLIGATION
233
This royalty clause could just as likely appear in a lease executed twenty,
thirty, or forty years later. 59
What is interesting to note is that in a number of the oil and gas lease
forms that began to appear in the 1950s, the oil royalty clause is expanded to
deal with the issue of who bears the expense of on-lease treatment such as
dehydration or sediment removal." It also appears that the problem ofdealing
with on-lease treatment of crude oil was mostly an Eastern or Midwestern
problem since none ofthe forms from the Midcontinent or GulfCoast regions
had similar language. By this time, the ubiquitous split of authority had
already appeared among the states as to whether such costs were to be borne
by the lessee alone or shared proportionally with the lessor. Oklahoma took
the position that the lessee had the unilateral duty to treat the oil to prepare it
for marketjust as it had the unilateral duty to drill and produce the crude oil.'!
But Califomia had taken the position that the oil royalty clause did not contain
an implied covenant to treat the oil once it is produced." The theory
underlying the California approach is that the lessor has the choice of
accepting the crude oil as it is produced and then dehydrating it itself or
allowing the lessee to dehydrate and share in that expense. The court appearS
to be saying that the delivery obligation under an in kind royalty is to deliver
the crude oil in its natural, untreated condition as it is severed from the earth."
Notwithstanding this split of authority on a very basic royalty issue, a
movement in the model forms to expressly allocate the costs of on-lease
development does not appear to exist, except in the east and Midwest. That
may result from the fact that oil production in those regions are less bounteous
and involve crude oil that contains more impurities than those encountered in
the main oil producing areas of the country.
HI. WHAT IS PRODUCTION?
When oil royalty clauses provide for an in kind royalty, the language of
the clauses requires the delivery of the royalty oil when it is produced or
as the payment methodology. Some of the oil royalty clauses expressly impose the costs of storage and
sediment removal treatment on the lessor. The gas royalty clauses are more varied than the oil royalty
clauses. Some distinguish between royalty payment methodologies based on Whether it is oil well gas or
gas well gas while others make that distinction based on what is done with the gas following production.
59. See SULLIVAN, supra note 58, at 63.
60. OAKES, supra 58, at 63. Oakes reproduces the Producers 88 Eastern fonn with the following
language in the oil royalty clause: "Lessor's interest . .. shall bearits proportion ofany expense oftreating
unmerchantable oil to render it merchantable as crude." Jd. Similar language is used in the "Illinois and
Indiana Form." [d. at 12.
61.
62.
Clark v. Slick Oil Co., 21 1 P. 496, 501 (Okla. 1923).
Vedder Petroleum Corp. v. Lambert Lands Co., 122 P.2d 600 (Cal. Dist. Ct App. 1942): see
also Alamitos Land Co. v Shell Oil Co., 44 P2d 573 (Cal. 1935); Fowler v. Associated Oil Co.• 74 P.2d
727 (Cal. 1937).
63. Vedder Petroleum, at 604-05.
234
TEXAS TECH LAW REVIEW
[Vol. 35;223
produced and saved. Little dispute has arisen under the oil royalty clause as
to when oil or gas is produced. What is produced may depend on the term
production. Production, as we all know, has many different meanings within
the oil and gas industry." But for purposes of the oil royalty clause,
production normally means the act of severing the hydrocarbons from the
ground." Until such time as the oil is removed from the ground, the delivery
obligation cannot be complied with.
As for gas royalty clauses, the term produced is not as universally present
as in oil royalty clauses.·· In certain circumstances, gas royalty clauses refer
to the sale ofthe natural gas as the royalty triggering event.·' Production has
been defined as "actually taking oil or gas from the well in a captive state for
either storing or marketing the product for sale."·' The relationship or nexus
between royalties and production seems self-evident. Unless the parties
otherwise agree, as in the case of advanced or minimum royalty provisions,
one might presume that a royalty clause delivery or payment obligation is only
triggered by production:' But that assumption may be incorrect. For example,
in Denio v. City ofHuntington Beach, several attorneys who performed work
on behalf of the city agreed to be compensated out of funds received by the
city as royalties from certain designated offshore wells.'· The city received
a large lump sum payment from the lessees as a result of a settlement of
litigation regarding whether the city or State ofCalifornia owns the gas under
the tidelands where the wells were producing. The attorneys quite naturally
argued that they were entitled to their share of that lump sum payment. The
city argued that the term royalties as used in the context ofan oil and gas lease
required actual production from which the royalty share is taken. In fact, the
64. See generally WILLIAMS & MEYERS. supra note 1 § 656 (explaining that the issue of what
constitutes production is not the first example of some basic definitional issues that impacted royalty
clauses). See also Hammett Oil Co. v. Gypsy Oil Co.• 218 P. 501. 502 (1922) (noting substantial confusion
as to whether "casinghead gas" was oil or gas or whether oil well gas was "casinghead gas" for purposes
of determining jf a royalty was owed and if so, how much was owed).
65. See, e.g., Rileyv. Meriwether, 780 S.W.2d 919, 923, III Oil & Gas Rptr. 336 (Tex. App.-EI
Paso 1989, writ denied).
66. See WILLIAMS & MEYERS, supra note 1, § 643,2.
67. See generally id. (giving several examples of gas royalty clauses where the term produced is
not mentioned).
68. Riley, 780 S.W.2d at 923 (citing WILLIAMS & MEYERS, supra note I, § 631); Ice Bros., Inc.
v. Bannowsky, 840 S.W.2d 57. 59, 121 Oil & Gas Rptr. 125 (Tex. App.-EI Paso 1992. no writ); see
WILLIAMS & MEYERS, supra note I, § 631 et seq. (dealing with shut-in royalties).
69. See PATRICK MARTIN &BRUCEM. KRAMER, WILLIAMS & MEYERS MANuAL OF OIL AND GAS
TERMS 28, 627-28 (11th ed. 2001) [hereinafter MANUAL OF TERMS] (defining advance or minimum
royalties). In either case whether the payments made prior to production may be recouped when production
commences will depend on the language creatingthe obligation. See, e.g" Pittsburgh Nat'l Bank v. Allison
Eng'g Co., 421 A,2d 281, 284 (Pa. Super. Ct. ]980) (holding that minimum royalty payments for a coal
lease are not recoupable when actual production starts).
70, 140 P,2d 392, 394 (Cal. ]943). The agreements provides that: "We are further to be paid out
of all moneys paid to the City ofHuntington Beach as royalties, or received by it out of the sale of its oil,
gas or other hydrocarbon substances, if its royalties are paid to it in kind." ld. at 400 (emphasis omitted).
2004]
INTERPRETING THE ROYALTY OBLIGATION
235
agreement specifically dealt with the issue of what should happen if the city
did not receive a cash payment but took its hydrocarbons in kind.
Nonetheless, the California Supreme Court found that a reasonable jury could
determine that the term "royalties" as used in the compensation agreement
might have encompassed more than just a share of the production of oil and
gas. 7I The court looked to the entire document to put the term "royalties" in
context and found that production may not be the sole source from which the
royalty obligation is to be made. By applying the canon of construction that
looks at the entire document, not isolated sections or terms, the court is
disconnecting royalty from production when the parties have signaled an
intent to make that disconnect. 72
The first major doctrinal dispute over what the term "production" means
in the context of a royalty clause arose out of the take-or-pay disputes that
began in the 1980s. 73 These disputes also are a good vehicle for exploring the
differences between the jurisprudential approaches of treating the written
word as the sine qua non of contract interpretation, or treating the written
word as merely the starting point in a broader strategy designed to both divine
the intent ofthe parties as well as to do 'Justice and fairness." As alluded to
earlier, the first approach will be labeled the parsing approach while the
second approach will be labeled the extrinsic approach. Neither the courts nor
the commentators agree on whether royalty is owed on money received by a
lessee from a purchaser for not taking natural gas, or for money received by
a lessee in settlement of such claims where such settlement is not attributable
to the sale of natural gas. As stated elsewhere;
The different approaches and outcomes depend in large part on one's focus:
whether there has been "production" and a "sale" of gas under the wording
oftypical lease royalty clauses or whether sharing ofproceeds from take-orpay and settlements is governed by the implied obligation to market as a
prudent operator (viewing the oil and gas lease as a 'cooperative venture.')"
71. ld. •t400.
72. ld. The court also noted that in the case of a settlement of a dispu.te between the lessor and
lessee regarding the payment of royalties, no one would claim that the attorneys would not be entitled to
a share ofthe settlement monies even though it may not constitute a share ofthe production, ld. Early gas
royalty litigation concerned the analogous principJeofwhethergas was marketed or used offofthe premises
so as to trigger the fixed annual royalty for such wens. The cases are not consistent in their treatment of
such language. Compare Pittsburg-ColumbiaOil & Gas Co. v, Broyles, 91 N,E. 754, 755 (Ind. App. 1910),
with Ohio Oil Co. v. Lane, 52 N.E. 791, 793 (Ohio 1898), with Indiana Natural Gas & Oil Co. v. Wilhelm,
86 N.E. 86, 88 (Ind. App. 1908).
73. See generally WILLlAMs&MEYERS,SUpranote 1, § 643.6;John S. Lowe, Deflningthe Royalty
Obligation, 49 SMU 1. REV, 223 (1996); Kirk J. BHy, Royalty on Take-or-Pay Payments and Related
Consideration Accruing to Producers, 27 Haus. 1. REv. 105 (1990),
74. WILLIAMS & MEYERS, supra note], § 643.6.
236
TEXAS TECH LAW REVIEW
[Vol. 35:223
This will be a recurring theme in this paper as the express terms ofthe royalty
clauses are reviewed. But one should not think that one can merely put a state
into a single "cubby-hole" by saying it always sticks to either the parsing or
the extrinsic approach to the exclusion of the other. Just as it is unfruitful to
conclude that State A always favors the producers and State B always favors
the royalty owner, each state's oil and gas jurisprudence cannot be so simply
analyzed. While many states have certain tendencies thatre-appearwith some
frequency, surprises always lurk out there for the overconfident seer who
predicts that the Oklahoma, Colorado, or Texas Supreme Court will reach a
particular decision in any type oflease or royalty clause interpretational issue.
If one follows the parsing approach to contract interpretation, the issue
in the take-or-pay cases appears to be relatively straightforward: Is royalty
owed on money received when neither production nor sale of the natural gas
has taken place? That requires a court to define the term production. Two
cases decided prior to the take-or-pay disputes seemingly resolved that
definitional issue in favor of finding that no royalty is owed. 75 In Monsanto
Co. v. Tyrrell, the court interpreted a lease clause allowing the lessor to
convert its royalty interest into a net-profits interest once the lessee recovers
from payments, "as recovery from production," certain designated costs of
production and development." The lessee received a large advance payment
from the gas purchaser prior to the onset of actual production. 77 In this
declaratory judgment action seeking to determine whether those payments
could be included in the "payout" determination, the court focused on the
language of the agreement limiting payments recovered from production.
Relying on habendum clause cases, the court concluded that production
required the "actual physical extraction of the mineral from the soil.,,7.
Leaving aside the question of whether the same term should have the same
meaning in different clauses ofthe lease,79 the Texas Court ofAppeals did not
go beyond the language used by the parties in their agreement, nor did it look
at the fairness or justice ofthe overall deal in resolving the dispute.
A similar result was reached by the Ninth Circuit Court of Appeals
applying Montana law in Energy Oils, Inc. v. Montana Power Co. 80 In this
case, the court interpreted an assignment of a working interest with the
75. See Monsanlo Co. v. Tyrreli, 537 S.W.2d 135,55 Oil & Gas Rptr. 219 (Tex. Civ. App.Houston [14th Dist.] 1976, no writ); Energy Oils. Inc. v. Mont. Power Co., 626 F.2d 731, 68 Oil & Gas
Rptr. 255 (9th Cir. 1980).
76. Monsanto Co., 537 S.W.2d at 136.
77. ld. Under the terms of the gas purchase agreement, the purchaser is to recoup this payment
under an agreed-to formula once production begins. ld.
INTERPRETING THE ROYALTY OBLIGATION
2004]
reservation of an overriding royalty by the assignor. There was a sliding scale
percentage ofroyalty based upon the assignee's recovery cert~in co~ts from
roduction.'! The court found that production as used m thiS assignment
P
"refers to oil and gas actually severed from the groun d .""Wht"t
a IS merest'm.g
is that Montana defines the term production differently insofar as that term IS
used in the habendum clause. In order to maintain a lease in the secondary
term based on "production," the Montana Supreme Court has said .that "[t]he
oil or gas must be withdrawn from the land and reduced to possessIOn f?r use
in commerce, especially whele the real consideration for the lease IS the
proceeds."83 Yet in that same opinion, the court said that severance from ~e
ground was not required where gas was the discovered hydrocarbon, agreemg
with Oklahoma, that production really means capable of production." The
court did not attempt to resolve the inconsistent definitions of the term
production, nor did it attempt to explain why it chose to follow the rule th~~
production means a physical severance ofthe hydrocarbon from the ground.
In lining up the jurisdictions that follow the parsing approach to the
. "New
.
royalty on take-or-pay Issue,
one finds Texas, "Oklahoma,"wyommg,
90
Mexico," Mississippi and the federal courts.'! The common thread in all of
these jurisdictions is the courts' parsing ofthe language ofthe royalty clause,
specifically the term production, and in some cases, the term sale. On~e the
issue is reduced to the simple definitional question of what constitutes
0:
81.
82.
83.
84.
Energy Oils, Inc., 626 F.2d at 733.
[d. at 738.
Christian v. A.A. Oil Corp., 506 P.2d 1369, 1373,45 Oil & Gas Rptr. 77 (Mont. 1973)..
Christian, 506 P.2d at 1373-74. While there is some unu5uallanguage in the lease regardmg
gas production, the court applies this dual interpretation ofthe tenn production to the standard habendum
clause language of so long as there is production in paying or commercial quantities. See id.; Fey v. A.A.
Oil Corp., 285 P.2d 578, 4 Oil & Gas Rptr. 1324 (Mont. 1955).
85. Christian, 506 P.2d at 1373-74.
86. Condra v. Quinoco Petroleum, Inc., 954 S.W.2d 68, 138 Oil & Gas Rptr. 171 (Tex. App.-8an,
Antonio 1997, writ denied); Alameda Corp. v. TransAmerican Natural Gas Corp., 950 S.W.2d 93, 97,137
Oil & Gas Rptr. 423 (Tex. App.-Houston [14th Dist.] 1997, writ denied); TransAmeric~ Natural Ga:>
Corp. v. Finkelstein, 933 S.W.2d 591, 137 Oil & Gas Rptr. 383 (Tex. App.-San AnloDlo 1996, wnt
denied); Hurd Enters. v. Brun~ 828 S.W.2d 101, 118 Oil & Gas Rptr. 311 (Tex. App.-SanAntomo 1992,
writ denied);Mandeli v. Hamman Oil & Ref. Co., 822 S.W.2d 153, 118 Oil & Gas Rptr. 287 (Tex. App.
-Houston [1st Dist] 1991, writ denied); Killam Oil Co. v. Bruni, 806 S.W.2d264, 118 Oil & Gas Rptr.
280 (Tex. App.-San Antonio 1991, writ denied).
87. Rnye Realty & Developing, Inc. v. Watson, 949 P.2d 1208, 137 Oil & Gas Rptr. 83,
republished with corrections, 2 P.3d 320 (Okla. 1996); Goss Family Ltd. P'ship v. Wood, 15 P.3d 517
(Okla 2000) (cert. denied).
88. Slate v. Pennzoil Co., 752 P.2d 975, 979, 100 Oil & Gas Rptr. 359 C'Nyo. 1988).
89. Harvey E. Yates Co. v. Poweli, 98 F.3d 1222, 1230, 135 Oil & Gas Rptr. 100 (lOth Cir.1996)
78. [d. (citing Gulf Oil Corp. v. Reid, 337 S.W.2d 267, 12 Oil & Gas Rptr. 1159 (Tex. 1960);
Rogers v. Osborn, 261 S.W.2d 311, 2 Oil & Gas Rptr. 304 (Tex. 1953»).
(applying New Mexico law).
79. ForexampJe. Oklahoma defines the term production in habendum clauses as only meaning
capable of production. See, e.g., Gard v. Kaiser. 582 P.2d 1311, 61 Oil & Gas Rptr. 394 (Okla. 1978).
Should that carry over to the royalty clause?
law).
80.
626 F.2d 731, 68 Oil & Gas Rptr. 255 (9th Cir. 1980).
237
90.
.
....
Williamson v. Elf Aquitaine, Inc.• 138 F.3d 546, 550 (5th Cir. 1998) (applymg MISSISSippI
91. Indep. Petroleum Ass'" of Am. v. Babhitt, 92 F.3d 1248, 1259, 135 Oil & Gas Rptr. I (D.C.
Cir. 1996); Diamond Shamrock Exploration v. Hodel, 853 F.2d 1159, 1167, 103 Oil & Gas Rptr. 38 (5th
Cir. 1988).
238
TEXAS TECH LAW REVIEW
[Vol. 35:223
production, the answer becomes reasonably simple. As stated by the lOth
Circuit in Harvey E. Yates, "royalty payments are not due under a
'production'-type lease unless and until gas is physically extracted from the
leased premises."" The Oklahoma Supreme Court added that the royalty
owners are "entitled to royalties on gas produced and sold or used off the
leased premises, or gas produced, saved and sold from the premises.""
Because there is no gas production, meaning a severance of the gas from the
ground and not sale ofthat severed gas, the royalty owners are not entitled to
a share of the payments. Oklahoma, as mentioned earlier, does not require a
physical severance of natural gas in order to comply with the "production"
requirement ofthe habendum clause. It refuses, in this instance, to look at any
external factors to resolve the issue ofroyalty liability, instead relying on the
parsing approach.
The contrasting view is recognized in Louisiana94 and Arkansas?' The
following lengthy excerpt from Frey provides probably the best rationale for
not following the parsing approach, as well as the difficulty the court
acknowledges in ignoring the express contractual language:
Although Article 213(5) provides a standard for interpretation ofthe mineral
lease, the rather expansive defmition of royalty is not dispositive of the
lessor's right to a royalty share oftalee-or-pay payments .... The principle
of freedom ofcontract is expressly recognized by the Mineral Code ... and
therefore, the accessorial right ofroyalty may not be defined absent reference
to the oil and gas lease in which it appears. Accordingly, this Court must give
consideration to the fundamental principle that the lease contract is the law
between the parties, defming their respective legal rights and obligations ....
Disinclined to rewrite a mineral lease in pursuit ofequity, we are nonetheless
cognizantthe terms ofa mineral lease are neither intended to, nor capable of,
accommodating every eventuality....
The purpose ofinterpretation is to determine the common intent ofthe
parties .... Words of art and technical terms must be given their technical
meaning when the contract involves a technical matter ... and words
susceptible ofdifferent meanings are to be interpreted as having the meaning
that best conforms to the object ofthe contract .. " When the parties made
no provision for a particular situation, it must be assumed that they intended
to bind themselves not only to the express provisions ofthe contract, but also
92. 98 F.3d at 1231. But cf [n ee Century Offshore Mgmt. Corp., 111 F.3d 443, 445, 136 Oil &
Gas Rptr. 40 (6th Cir. 1997) (holding that "[a]n up-front payment made in exchange for a substituted
contract that changes the price ofthe old contract, followed by new purchases, is a sufficient cause of new
production ofgas to qualitY as 'production sold' under the Act").
93. Goss Family Ltd. P'ship v. Wood, IS P.3d 517, 518 (Okla. 2000)(cert. denied).
94. Freyv. Amoco Prod. Co., 603 So.2d 166, 113 Oil & Gas Rptr. 478 (La. 1992).
95. SEECO, Inc. V. Hales, 22 S.W.3d 157, 148 Oil & Gas Rptr. 155 (Ark. 2000); Klein V. Jones
980 F.2d 521,124 Oil & Gas Rptr. 442 (8th Cir. 1992), on lalerappeal sub nom., Klein v. Arkoma Prod.
Co., 73 P.3d 779, 134 Oil & Gas Rptr. IS (8th Cie. 1996).
2004]
INTERPRETING THE ROYALTY OBLIGATION
239
to whatever the law, equity, or usage regards as hnplied in a contract ofthat
kind or necessary for the contract to achieve its purpose.
Under the facts before us, a search for the parties' specific intent
relative to the obligation to pay royalty on the take-or-pay proceeds would
prove fruitless. . . Accordingly, we look not at the parties' intent to provide
expressly for take-or-pay payments, but rather at the parties general intent in
entering an oil and gas lease, viz.,the lessor supplies the land and the lessee
the capital and expertise necessary to develop the land for the mutual benefit
of both parties ... Consequently, we endeavor to ascertain the meaning of
the royalty clause in a manner consistent with the nature and purpose ofan oil
and gas lease, ... having due regard for: I) the function ofa royalty clause;
and 2) the lessee's implied obligation ... to market diligently the gas
produced.
. " [W]e conclude an oil and gas lease, and the royalty clause therein,
is rendered meaningless where the lessee receives a higher percentage ofthe
gross revenues generated by the leased property than contemplated by the
lease. The lease represents a bargained-for exchange, with the benefits
flowing directly from the leased premises to the lessee and the lessor, the
latter via royalty. An economic benefit accruing from the leased land,
generated solely by virtue of the lease, and which is not expressly negated,
... is to be shared between the lessor and lessee."
The court, while acknowledging the importance ofthe written instrument as
being the primary source ofinterpretingthe respective duties and rights ofthe
parties, nonetheless, is driven by its notions of fairness and justice to ignore
the written language and apply an implied "cooperation principle" to resolve
the issue. The Eighth Circuit opinions applying Arkansas law are even less
hesitant to openly adopt the extrinsic approach and consider Professor
Merrill's fairness and equity factors in interpreting oil and gas leases?'
A related issue to the "production" definitional problem is what types of
production are covered by a fixed-rate royalty clause that in earlier times
applied to "gas produced from an oil well" or "casinghead gas sold or used off
the premises."" This definitional dispute arose when substantial gas
production from oil wells were processed for the liquid hydrocarbons
96.
Frey, 603 So.2d at 172-74 (citations omitted).
97.
See, e.g., Klein. 73 F.3d at 787. "The breach in this case is neither the decision to settle, nor
the decision to reform the contract, but the failure to share the benefits ofthe settlement with the beneficial
owners of those proceeds." Jd. The SEECO case Uses similar language but also relies on an Arkansas
statute that requires the lessee to protect the lessor's royalty interest 22 S.W.3d at 148; ARK. CODE ANN.
§ 15-74-705 (1994). The equity rationale is further supported by the Eighth Circuit's failure to extend its
holding to a non-lease situation. See IN Exploration & Prod. v. W. Gas Res., Inc., 153 F.3d 906, 141 Oil
& Gas Rptr. 93 (8th Cir. 1998) (determining that the seller of natural gas was entitled to a percentage of
net proceeds from sale by processor or purchaser to third parties not entitled to share in take~or-pay
settlement payment received by processor or purchaser.).
98. See, e.g., OAKES, supra note 58.
240
TEXAS TECH LAWREVIEW
[Vol. 35:223
entrained in the gas stream. 99 The widespread use of this technology did not
begin to appear until the 1910s at the earliest. lOo Lessees would take the
position that the fixed-rate royalty clause applies, rather than a percentage
royalty clause for oil or gas production, or both. 101 Here again, a lack of
agreement inheres between states, and in some instances within a single state,
about what those terms mean.
The Oklahoma Supreme Court expressed one view in its decision in
Mussellem v. Magnolia Petroleum CO. 102 In that case, the royalty clause
provided for a fixed-sum payment for "gas produced from an oil well, and
used off the premises."103 The lessee removed gasoline and other liquid
hydrocarbons on the leased premises. The court found that the removed
gasoline was being used off ofthe premises because it was not being used for
lease production purposes. Therefore, the expresS language of the royalty
clause covered the facts and required that the lessor only receive the fixed-rate
royalty. Texas agrees with that position although positing a somewhat
different rationale for the same result. IO' Thus, Oklahoma and Texas are
applying the same parsing approach.
Louisiana, however, takes the position that when gasoline is removed
from the gas stream produced from an oil well, the fixed-rate royalty clause
that applies to "gas produced from an oil well" is not applicable. lOS The
rationale is that the parties' lack ofknowledge ofthe method by which liquids
Were processed from the gas stream and then used for something other than
heat, fuel, or carbon black purposes means that they neVer intended the fixedrate gas from an oil well clause to apply.I06 The extrinsic approach shows a
lack ofrespect for the language ofthe parties and allows the royalty clause to
be reformed to COVer an unanticipated circumstance in order to achieve the
Merrill goals offaimess andjustice. A Texas caSe also exists that agrees with
the Louisiana approach of ignoring the written language also on the basis of
a lack of specific intent even though the week-earlier Texas holding rejected
that same rationale. 107 These early caSeS were undoubtedly a factor in oil and
gas leases including express royalty clauses to deal with casinghead gas
production and the general problem of the processing of natural gas liquids.
To the extent the earlier language was unclear, the response should be to
99.
100.
101.
See Hardwicke, supra note 30, at 5-6.
Id.
Id.at6-33.
102.
231 P. 526, 530-32 (Okla. 1924).
Id. at 527.
Magnolia Petroleum Co. v. Connenee, 11 S.W.2d 158, 159-63 (Tex. Comm'n App. 1928,
103.
104.
2004]
INTERPRETING THE ROYALTY OBLIGATION
241
change the language, although that obviously does not resolve the issue as to
the parties who have executed a fixed-rate royalty clause.
IV. MARKET V AWE, MARKET PRICE, AMOUNT REALIZED? ALL FOR ONE
AND ONE FOR ALL?
If a term as simple as the term "production," when used in a royalty
clause, can be given different meanings, it is not surprising that .the other
terms used in royalty clauses can also create disparities across state hnes. One
of the most obvious schisms that developed in the 1980s was the problem of
defining the terms "market value," "market price," "amount realized," and
"proceeds."
. Twenty years ago, I made the following observation:
Royalty is not a share of the lessee's profits, but is a share of the lessee's
production. In the case ofa landowner's royalty the calculation ofthe amount
of royalty owed should depend upon the express language of the leasehold
royalty clause .... [ejourts sometimes iguore the express language m order
to reach results that are deemed to serve other public purposes than freedom
of contract.
In theory there should be a distinction between the terms market price
and market value. Market price seemingly refers to an actual sale ofthe gas
in exchange for a cash consideration. Thus without a sale there is no market
price. Market value, however, may exist in the absence of any actual sale
because it is based on a hypothetical standard. In fact, a number of courts
have made that distinction. But the vast majority of courts have treated
. al
. al ts 108
market price and market value royalty clauses as fun ctlon
eqUlv
en .
The blurring of the distinction between market value and market price is not
a recent phenomenon. Two early caSeS arising out of Louisiana production,
one in state court and One in federal court, treated the terms as functionally
equivalent. 109 But a federal court decision in the 1940s set forth what arguably
should be the correct approach to dealing with the differences between market
value and market price. The Fifth Circuit stated:
Market price is the price that is actually paid by buyers for the same
commodity in the same market. It is not necessarily the same as 'market
value' or 'fair market value' or 'reasonable worth.' Price can only be proved
by actual transactions. Value or worth, which is often resorted to when there
holding approved).
105. Wemple v. Producers' Oil Co., 83 So. 232 (La. 1919); accord, Gilbreath v. States Oil Corp.,
4 F.2d 232 (5th Cir. 1925).
106. Wemple, 83 So. at 235-38.
107. Reynolds v. McMan Oil & Gas Co., II S.W.2d 778 (Tex. Comm'n App. 1928, holding
approved); see WILLIAMS & MEYERS, supra note 1, § 651.2.
108. Kramer, supra note 6, at 459 (footnotes omitted).
109. See, e.g., Ark. Natural Gas Co. v. Sartor, 78 F.2d 924, 927 (5th Cir. 1935), cert. denied, 296
U.S. 656 (I936): Sartor v. United Gas Pub. Servo Cu., 173 So. 103 (La. 1937); see Mont. Power Co. v.
Kmvik, 586 P.2d 298, 62 Oil & Gas Rplf. 472 (Mont. 1978).
242
TEXAS TECH LAW REVIEW
[Vol. 35:223
is no market price provable, may be a matter ofopinion. There may be wide
difference between them.
IIO
In circumstances when a competitive market exists for the commodity, the end
result probably will not differ much regardless of whether the term market
price or market value is used. But the absence of arms-length sales in the
relevant market may make a determination of market price difficult if not
impossible. Another major distinction that could arise between market price
and market value relates to the timing of the valuation. Market price
represents the price that is being obtained in the relevant marketplace. I I I At
a time when natural gas was being sold under long-term contracts, market
price might conceivably be substantially less than market value, because
market value assumes that the natural gas is available for sale at the current
time. 112
Any determination of market value normally starts with the generally
accepted proposition that value is determined by what a willing buyer would
pay to a willing seller when neither party is compelled to enter into the
transaction. '13 While evidence ofmarket price is reasonably straightforward,
evidence ofmarket value may be much more ambiguous and may be presented
by any witness who has facts or opinions relating to market value. 1I4 In
circumstances when arms-length transactions occur at the point ofvaluation,
the prices agreed to in those transactions will provide the best, if not only,
evidence of market value. '"
A series of cases dealing with natural gas production in the Panhandle
Field in the mid-1940s seems to establish various principles relating to the
determination ofmarket value that are largely ignored today. I 16 The Ochsner
110. Shamrock Oil & Gas Corp. v. Coffee, 140 F.2d 409, 410-11 (5th Cir. 1944), cerl. denied, 323
U.S. 737 (1944).
111. E.g., id.
112. See Hugolon Prod. Co. v. Uniled Slates, 315 F.2d 868, 874, 18 Oil & Gas Rptr. 365 (C1. CI.
1963), modified, 349 F.2d 418, 23 Oil & Gas Rptr. 593 (Ct. CI. 1964). This point was made long before
the market valUe/proceeds dichotomy of the late 1970s and early 1980s. See id.
113. See generally Ashland Oil, Inc. v. Phillips Petroleum Co., 463 F. Supp. 619, 626, 62 Oil & Gas
Rptr. 483 (N.D. Okla. ]978) (stating that the fair rnarket value of an item is the price at which both buyers
and sellers are willing to engage in the transaction); Lightcap v. Mobil Oil Corp., 562 P.2d J, 13.57 Oil
& Gas Rptr. 487 (Kan. 1977) (holding that market value was the price paid by awilling buyer to a willing
seller in a free market).
114. See, e.g., Piney Woods Counlly Life Sch. v. Shell Oil Co., 726 F.2d 225, 238,79 Oil & Gas
Rptr. 244 (5th Cir. 1984); J.M. Huber Corp. v. Denman, 367 F.2d 104, 104,25 Oil & Gas Rptr. 347 (5th
Cir. 1966); Butler v. Exxon Corp., 559 S. W.2d 410, 59 Oil & Gas Rptr. 529 (Tex. Civ. App.-EI Paso
1977, writ refd n.r.e.). There may be limits on who can testifY as to market value after Daubertv. Merrell
Dow Pharmaceuticals, Inc., 509 U.S. 579 (1993), but laypersons are regularly qualified to provide
testimony as to market value in eminent domain or inverse condemnation cases. See, e.g.• Steams Co. v.
United Slates, 53 Fed. CI. 446, 446, 153 Oil & Gas Rptr. 253 (2002).
115. See Imperial Colliery Co. v. Oxy USA, Inc., 912 F.2d 696, 111 Oil & Gas Rptr. 618 (4th Cir.
1990).
116. These cases are discussed in WILLIAMS & MEYERS, supra note 1, § 650.2. See generally
2004]
INTERPRETING THE ROYALTY OBLIGATION
243
case is interesting because of the way the court defined the relevant mark~t
from which market value was to be derived. Phillips, the major producer m
the field, effected an exchange of gas produced from wells in one pa~l~fthe
field for gas produced by other operators in another part ofthe field. The
swap meant that Phillips-produced gas was being used for the more valuable
purposes of providing heat and fuel. The other market for the gas was to
process the natural gas liquids. Phillips m~de royal.ty ~ayments based on the
market value for gas subject to processmg for liqUIds. In Ochsner, that
amount was about .66 cents/MCF. The royalty owners asserted they were
entitled to a royalty based on the value ofgas used for heat and fuel purposes.
That figure was pegged at 3.29 cents/MCF or about a 500 percent larger
royalty. The Fifth Circuit rejected the notion that the relevant market for the
Phillips-produced gas was for heat and fuel purposes. The .only market
available was for gasoline processing. Because a market eXIsted ~or .the
Phillips-produced gas, the evidence relating to market value had to be limited
to that market. The swap or bartering arrangement made by the lessee does
not control the duty owed by the lessee to the lessor regarding royalty
payment. The lessor by agreeing to accept a percentag~ of the mark~t value
of the natural gas was limited to its agreement. EVIdence regardmg the
relevant market can limit the evidence as to the market value of the natural
gas.
While in the 1940s it may have been possible to balkanize the relevant
market for natural gas to different parts of the same field, it may be more
difficult in today's natural gas market to narrowly define the relevant
market. 118 Butthese early cases suggest that market value must be determined
without considering what happens downstream of ,the point of valuation
because most of the clauses referred to the wellhead when market value or
market price was to be determined. They also suggest that any party seeking
to move away from a market value royalty calculation methodology, when ~at
is what the lease expressly requires, must prove that no market value eXIsts.
Finally, the courts suggest that market value is not necessarily dependent on
Phillips Petroleum Co. v. Williams, 158 F.2d 723 (5th Cir. 1946) (holding that. absent a prevailingmark.et
rate the value of the gas is based on its use); Phillips Petroleum Co. v. Bynum, ISS F.2d 196 (5th Clr.
1946) (holding that where it is proved that it is impossible to determine market value,.the court will.use the
reasonable value ofthe gas); Phillips Petroleum Co. v. Johnson, 155 F.2d 185 (5th CIt. 1946) (slaung that
the law often uses "fair value" in place of "market value" when there is not a market); Phillips Petroleum
Co. v. Record, 146 F.2d 485 (5th Cir. 1944) (holding that the lessor's damages based on prevailing market
rate should be measured by the market value of the gas at well); Phillips Petroleum Co. v. Ochsner, 146
F.2d 138 (5th Cir. 1944) (holding that where gas only had amarketvaIue for gasoline prices, that value was
to be used rather than the market vallie elsewhere when the gas is used for light and fuel).
117. Ochsner, 146 F.2d at 139 n.1.
118. Since Phillips is exchanging gas, it is also bearing various risks not applicable to th~ royalty
interest. See Crosby~Mississippi Res., Ltd. v. Saga Petroleum U.S., Inc., 767 F.2d 143, 146, 86 Od & Gas
Rptr. 534 (5th Cir. 1985).
244
TEXAS TECH LAWREVIEW
[Vol. 35:223
what the lessee, in fact, does with the natural gas. The Fifth Circuit
concluded:
Finally we agree with [Phillips] that the amount due plaintiff must be
determined without regard to the use its lessee made ofthe gas. Plaintiffwas
entitled to be paid on the basis ofthe market value ofthe gas at the well, and
the answer to whether a jury issue was made out is to be found not in the
actual use made of the gas in question but in whether plaintiff's gas had a
market value at the well and what that market value was. .. But plaintiff,
admitting that ifhis gas had been piped to the gasoline plant, he would have
been entitled to no more than its market value for gasoline plant purposes,
urges that because the gas was not processed in a gasoline plant but was
delivered to a pipe line company for use by it for light and fuel, plaintiff can
insist that the value ofhis gas should be determined not on its market value
at the well where appellant took it, but by its value for light and fuel uses
determined by a consideration of pipe line royalties and purchases. We
cannot agree. There was no market for appellee's gas for light and fuel
purposes. For such uses it would bring nothing. There was a market for, and
an established market value of, his gas for gasoline plant purposes. The price
of a thing is what it will bring, and appellee cannot decline to take the price
thus established upon the claim that his gas was not used in a gasoline plant
but for light and fuel. I "
This approach is consistent with the view that words have meaning and that
"market value at the well" royalty clauses should be interpreted by reference
to the clearly understood meaning of those words.
But concluding that market value or market value at the well has a
definite meaning does not necessarily mean that determining the actual
amount owed to a particular royalty owner will be easy to ascertain. As
written earlier, the cases have developed a hierarchy of methodologies to
determine market value. After all, saying that the lessee owes to the lessor a
fractional share of what a willing buyer would pay a willing seller for the
produced hydrocarbons does not get one very far up the decision tree. Most
courts start with the proposition that the best evidence of market value is the
price at which the commodity is sold in an arms-length transaction at the point
of valuation. l20 In addition, the sale transaction that is being used must be at
the same time ofvaluation as provided for in the royalty clause. 121 Ifno actual
sale takes place at the time and place of valuation used in the royalty clause,
119. Ochsner, 146 F.2d aI141.
J20. See, e.g., Phillips Petroleum v. Bynum. ISS F.2d 196,201 (SthCir. 1946); Ochsner, 146 F.2d
at 141; Cabot Corp. v. Brown, 754 S.W.2d 104,99 Oil & Gas Rptr. 154 (Tex, 1987).
121. See supra text accompanying notes 149~ 74 (discussing the potential time distinction between
amarket value and market price methodology); infra text accompanying note 177 (discussing this issue as
critical to the market value and proceeds issue).
2004]
INTERPRETING THE ROYALTY OBLIGATION
245
the next best valuation methodology is the use of comparable sales. 122
Comparable sales should not be used if the lessee or other producers from the
same well execute arms-length sales at the well. I2 ' Comparable sales raise the
rather fact-specific issue ofhaving multiple factors to comp~re. The following
is a listing of a wide range of factors that may affect the pnce of natural gas:
(a) The volume available for sale. Generally, the greater the
volume or reserves, the greater the price the seller could
command.
(b) The location of the leases or acreage involved, whether in a
solid block or scattered, and their proximity to prospective
buyers' pipelines.
(c) Quality of the gas as to freedom from hydrogen sulphide in
excess of I grain per 100 cubic feet.
(d) Delivery point.
(e) Heating value of the gas.
(f) Deliverability of the wells. The larger the volume that could
be delivered from a reserve, the greater the price the seller
could command.
(g) Delivery or rock pressure. The higher the pressure, the less
compression for transportation is required. I2'
These factors were identified in the 1950s and applied a decade later. l2S
Obvious changes have occurred in the natural gas market since then which
may prove relevant to determining market value. Obviously, the broadening
of the natural gas market through third-party marketers, the unbundling of
pipeline transportation services, and the existence ofa futures market all have
an impact on market value. The Fifth Circuit noted: "The only general rule
that emerges from these cases is that the method ofproofvaries with the facts
of each particular case.,,126 Evidence of "incomparable" comparable sales is
to be admitted, but is subjectto cross-examination regarding the properweight
to be given. 127 As more variables affecting comparability are involved, the
relationship between sales becomes more tenuous. Butnonetheless the parties
122. See, e.g., Piney Woods Christian Life Sch. v. Shell Oil Co., 726 F.2d 225.79 Oil & Gas Rptr.
244 (5th Cir. 1984); Ashland Oil, Inc. v. Phillips Petroleum Co., 554 F.2d 381, 387, 57 Oil & Gas Rptr.
390 (lOth Cir. 1975); Exxon Corp. v. MiddlelOn, 613 S.w.2d 240, 246, 67 Oil & Gas Rptr. 431 (Tex.
1981).
123. Hugoton Production Co. v. United States, 315 F.2d 868, 18 Oil & Gas Rptr. 365 (el. Cl. 1963).
124. Jd. at 894-95.
125. Jd. at 894.
126. Piney Woods, 726 F.2d at 238.
127. Jd. at 239.
246
TEXAS TECH LAW REVIEW
[Vol. 35:223
are free to present their evidence regarding what they consider to be
comparable sales in order to prove what the market value is. 12'
To overcome the lack of actual or comparable sales at the point of
valuation, it became standard industry practice for royalties to be calculated
using the so-called "net-back" approach. This approach is described in
Ashland Oil, Inc. v. Phillips Petroleum CO. '2' The court says:
Effective application of this [net-back] method requires selection of an
appropriate starting value in the form of a processing stage whose product
possesses a value certain; accurate assessment ofthe costs accruing between
the known stage and the one in question is also essential. In developing a
resource from a raw material into a fmished product, each production stage
will add economic value to what was initially only the value of the raw
material. The value added at each stage of production is essentially the cost
ofresources used in taking the material through that stage ofproduction. The
work-back method essentially establishes at each production stage the value
ofthe product at that point. By subtracting out all production costs, the value
of the raw material is revealed. I "
This methodology received nearly universal acceptance through the decade of
the 1970s. While this approach for calculating royalty has come under
attack in recent years, in earlier times it was a recognized, although sometimes
disparaged, method of calculating market value at the well where there were
no actual or comparable sales available.'"
While market value and market price royalty clauses created some
problems in calculation, little litigation arose concerning the "amount
realized" or "proceeds" clauses because everyone believed that the royalty
'3'
128. See id. at 225 (authorizing the admissibility oftestimony regarding the three top prices for gas
sold in the relevant market). That same approach was approved by the Texas courts in Exxon v. Middleton,
613 S.W.2d 240, 67 Oil & Gas Rptr. 431 (Tex. 1981) and Butler v. Exxon Corp., 559 S.W.2d41O, 59 Oil
& Gas Rptr. 529 (Tex. App.-EI Paso 1977, writrefd n.r.e.).
129. Ashland Oil, Inc. v. Phillips Petroleum Co., 463 F. Supp. 619, 620, 62 Oil & Gas RpIr. 483
(N.D.Okla 1978).
130. Ashland, 463 F. Supp. at 620.
131. See, e.g., Scott Paper Co. v. Taslog, Inc., 638 F.2d 790, 799, 69 Oil & Gas RpIr. II (5Ib Cir.
1981); Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225,79 Oil & Gas Rptr. 244 (5th Cir.
1984); At!. Richfield Co. v. State, 262 Cal. Rptr. 683,688, 108 Oil & Gas RpIr. 17 (1989): Ashland Oil,
IDe. v. Phillips PeIroleum Co., 554 F.2d 381, 57 Oil & Gas Rptr. 390 (10Ih Cir. 1975): Freelandv. Sun Oil
Co., 277 F.2d 154, 13 Oil & Gas Rptr. 764 (51h Cir. 1960), cert. denied, 364 U.S. 826 (1960); Old Kent
Bank & Trost Co. v. Amoco Prod. Co., 679 F. Supp. 1435, 99 Oil & Gas RpIr. 68 (W.D. Mich. 1988);
Clear Creek Oil & Gas Co. v. Bushmaier, 264 S.W, 830 (Ark. 1924); Matten v. Hugoton Prod. Co., 321
P.2d 576, 8 Oil & Gas Rptr. 1216 (Kan. 1958): Reed v, Hackworth, 287 S.W.2d 912, 5 Oil & Gas Rptr.
1314 (Ky. 1956); Wall v. Uoited Gas Pub. Servo Co., 152 So. 561 (La. 1934): Schroederv. Terra Energy,
Ltd., 565 N.W.2d 887, 138 Oil & Gas RpIr. 361 (Mich. 1997); Mont. Power Co. v. Kravik, 586 P.2d 298,
303-04,62 Oil & Gas Rptr. 472 (Mont. 1978): Creson V. Amoco Prod. Co., 10 P.3d 853,145 Oil & Gas
RpIr. 324 (N.M. Ct. App. 2000); Danciger Oil & Ref. V. Hamill Drilling Co., 171 S.W.2d 321 (Tex. 1943).
132. See itifra text accompanying notes 138-57.
2004]
INTERPRETING THE ROYALTY OBLIGATION
247
should be based on the pass-through ofthe contract price for the sale ofthe oil
or gas. 133 The change in the natural gas market that began in the 1970s
triggered a series of cases that had to ask the reasonably straightforward
question: If a lessee paid the lessor a fraction of a long-term contract price
executed years prior to the date of delivery of the gas, has the lessor met its
contractual obligation to pay the market value or market price of the gas?'"
This issue actually arose prior to the major upheaval in the natural gas
markets. I3S In Foster v. Atlantic Refining Co., the royalty clause required the
lessee to deliver both the oil and gas into the pipeline with it then to be sold
at the prevailing market price. l36 The lessee executed a twenty-year gas sales
contract in 1950 with standard price escalator provisions. Nonetheless, by
1957 the prevailing market price in the field exceeded the contract price. The
court had no difficulty requiring the lessee to pay royalty based on the higher
market price and noted thatthe lessee bears the risk thatthe long-term contract
price will not keep up with the market price. When the lessee executes a longterm contract it should be aware of its royalty obligation. That obligation
cannot be ch~ged by a contract between the lessee and the gas purchaser. 137
The next bombshell, according to industry veterans, was the Texas
Supreme Court decision in Texas Oil & Gas Corp. v. Vela. '38 Vela concerned
a 1933 lease that contained various royalty provisions, including an in-kind
provision for oil and both market price and proceeds gas royalty clauses
depending on whether the gas was produced from an oil well or a gas well. l3 '
Natural gas was discovered, and in 1935 a "life of the lease" gas purchase
contract was executed. It was shown that in 1935 such contracts were the only
way that gas could be sold and that the contract price was the only price that
could be obtained at the time. By the mid-1960s the market price had risen to
133.
134.
See infra text accompanying notes 140-45.
See generally WILLIAMS & MEYERS, supra note I, § 6~0.4. The issue engendered the usual
forest ofarticles. See. e.g., David Pierce, Royalty Calculation in a Restructured Gas Market, 13 E. MIN.
L. INST. 18~1 (1992); Maxwell, supra note 1; Frank G. Harmon, Gas Royal~Vela. Middleton and
Weatherford, 331NST. ON OIL & GAS L. & TAX'N 65 (1982).
135. See Foster V. Atl. Ref. Co., 329 F.2d 485, 20 Oil & Gas Rptr. 422 (5Ib Cir. 1964).
136. 329 F.2d at 485. Foster was roundly criticized by many including Judge Joseph Morris. See
Joseph Morris, The Gas Royalty Clause-What is Market Value?, 2S INST. ON OIL & GAS L.& TAX'N 63,
75 (1974).
137. Foster, 329 F.2d at 489~90. The colirt uses language typical of courts that treat contractual
language as important. Jd. at 490. It says:
Stripped ofall the trimmings Atlantic's position is simply: ... The lease calls for royalty based
on the market price prevailing for the field where produced when run. The fact that the
ascertainment of future market price may be troublesome or that the royalty provisions are
improvident and result in a financial loss to Atlantic "is not a web of the Court's weaving."
Atlantic cannot expect the court to rewrite the lease to Atlantic's satisfaction.
ld. at 489-90.
138. 429 S.W.2d 866, 29 Oil &Gas Rptr. 121 (Tex. 1968), reforming, 405 S.W.2d 68, 25 Oil&Gas
Rptr. 253 (Tex. Civ. App.-San Autonio 1966).
139. ld. at 868,870-71.
248
TEXAS TECH LAW REVIEW
[Vol. 35:223
slightly over 13 centslMCF while the contract price remained at 2.3 centsl
MCF. The royalty owners were successful in claiming that the lessee owed
them a fractional share of thirteen cents, rather than a fractional share of 2.3
cents. The Texas Supreme Court relied on the Foster rationale. The market
price royalty standard cannot be affected by the subsequent gas purchase
contract. The parties were well aware of the different types of royalty
provisions because they used different language covering different products
and different circumstances. The lessee bears the risk that the contract price
will not keep up with the market price and will not be saved by a financially
burdensome contract that it voluntarily executed.
These two early cases applying the parsing approach to royalty clauses
were followed in most jurisdictions. For example, the Montana court noted
that the term "market price is understood to mean the current market price
.... The price to be paid is not to be an arbitrary price fixed by the lessee but
the price actually given in current market dealings."140 Similar adherence to
the view that market price or market value means current market value and not
the amount realized under a long-term contract can be found in judicial
opinions from the Fifth Circuit,141 Kansas,I42 North Dakota,l43 West
Virginia,I44 and the IBLA. I"
The extrinsic approach, whereby external factors will be considered so
that the term market value or market price will be treated as the functional
equivalent of amount realized or proceeds, has been adopted in three
jurisdictions. I' 6 The earliest, and best written opinion, was authored by the
Oklahoma Supreme Court in Tara Petroleum Corp. v. Hughey.I'7 The factual
scenario remains the same as in the just-discussed cases; the lease contained
a market price at the well royalty clause; the lessee executed a long-term gas
purchase contract; the current market price in the relevant field exceeded the
contract price. 1" Under the Foster and Vela parsing approach, market price
has a definite meaning that reflects the current price in the marketplace.
Instead of leaving the parties where they lie, the Tara court noted the
140. Mont Power Co. v. Kravik, 586 P.2d 298, 302, 62 Oil & Gas Rptr. 472 (Mont 1978), affd,
616 P.2d 321, 68 Oil & Gas Rptr. 269 (Mont 1980).
141. Piney Woods Country Life Sch. v. Shell Oil Co., 539 F. Supp. 957, 981, 74 Oil & Gas Rptr.
485 (S.D. Miss. 1982).
142. Holmes v. Kewanee Oil Co., 664 P.2d 1335, 77 Oil & Gas Rplr. 447 (Kan. 1983); Lightcap v.
Mobil Oil Corp., 562 P.2d 1,57 Oil & Gas Rptr. 487 (Kan. 1979).
143. Amerada Hess Corp. v. Conrad, 410 N.W.2d 124, 129, 96 Oil & Gas Rptr. 191 (N.D. 1987)
(interpreting market value as used in the statute dealing with gross production tax calculation).
144.
2004]
INTERPRETING THE ROYALTY OBLIGATION
249
unfairness to the lessee of having to pay an increasingly larger share of its
proceeds to the lessor. The court considered the fact that the lessee was under
an implied obligation to market the gas. That obligation arose when the gas
was discovered. Because of that implied obligation, the lessee may be
compelled to enter into a long-term contract that will expose it to potential
liability under the Foster and Vela approach. To rationalize this result, which
shifted the risk from the lessee to the lessor of increasing market prices and
a steady contract price, the Oklahoma Supreme Court stated:
This would not be fair to the producers. We do not believe that the lessors
in this case, the original lessee, or the assignee-producers ever contemplated
that the lessors' royalty could be half of what the producers received for the
gas. The better rule-and the one we adopt-is that when a producer's lease
calls for royalty on gas based on the market price at the well and the producer
enters into an arm's-length, good faith gas purchase contract with the best
price and term available to the producer at the time, that price is the 'market
price' and will discharge the producer's gas royalty obligation ....
We believe that our interpretation of 'market price' is consonant with
the intent and understanding ofparties to oil and gas leases. And it is the only
interpretation that would operate fairly for producers. Moreover, it is not
unfair to lessors. 149
How the court can determine that it is consonant with the intent and
understanding ofthe parties and is not unfair to the lessors is unknown to me.
Royalty clauses use different terms to describe different royalty calculation
methodologies. Ifthe parties want to pay on the basis ofthe amount received
by the lessee, language in leases can lead to that result. However, in these
cases, the parties voluntarily chose to include multiple payment
methodologies, including some based on market value or market price. The
Oklahoma Supreme Court was essentially, using the language of Foster and
Vela, rewriting the oil and gas lease royalty clause to achieve what it
perceived to be a fair result, partially by adding the implied covenant to
market to the express royalty clause language. In this case, a decision fair to
the lessee and, notwithstanding the court's protestations to the contrary, unfair
to the lessor is the result. The Tara approach of interpreting the term market
price to be the equivalent ofcontract price as a matter oflaw was followed in
Arkansas. lSO
The Louisiana Supreme Court, while reaching the same result as Tara,
used a somewhat different approach. 151 In Henry, the royalty clause that was
Teavee Oil & Gas, Inc. v. Hardesty, 297 S.E.2d 898,900,75 Oil & Gas Rptr. 649 (W. Va.
1982) (interpreting market value as used in the statute dealing with business and occupation tax on oil and
gas).
145.
Supron Energy Corp., 46 IBLA 181, GFS (O&G) 1980-75 (Mar. 21, 1980).
146.
See irifra notes 146·55 and accompanying text.
630 P.2d 1296,71 Oil & Gas Rptr. 386 (Okla. 1981).
Tara Petroleum Corp., 630 P.2d at 1271-72.
147.
148.
149. fd. at 1273-74.
150. Hillard v. Stephens, 637 S.W.2d 581, 74 Oil & Gas Rptr. 228 (Ark. 1982); see Taylor v. Ark.
La. Gas Co., 604F. Supp. 779, 85 Oil & Gas Rptr. 1 (W.D. Ark. 1985), aff'd, 793 F.2d 189, 193,90 Oil
& Gas Rptr. 201 (8th Cir. 1986).
151. Henry v. Ballard & Cordell Corp., 418 So. 2d 1334, 1339-40, 74 Oil & Gas Rptr. 280 (La.
250
TEXAS TECH LAW REVIEW
[Vol. 35:223
at issue called for royalty to be based on the market value ofthe natural gas. I"
Rather than finding that market value means contract price as a matter of law
because offairness concerns, the Louisiana Supreme Court finds that the term
market value is legally ambiguous. 1l3 The court's bewilderment regarding
whether the parties intended market value to mean current market value or
market value at the time the gas purchase contract is executed causes the
ambiguity. It seems to be a "no-brainer" because the term market value must
have a temporal context. The context clearly suggests that because the royalty
was only owed upon actual production, the market value that defined the
calculation methodology should have been determined when the hydrocarbons
were severed from the ground. Nonetheless, the Louisiana Supreme Court
found the term as used in the oil and gas lease ambiguous. One way to deal
with ambiguous instruments is to apply appropriate canons of construction.
The most apt canon of construction in this situation would be the canon that
ambiguous provisions are construed against the scrivener, in this case the
Jessee. But, the court chose not to use that canon and looked at extrinsic
factors to reach a result favorable to the lessees. In reviewing what the court
termed the "necessary realities of the oil and gas industry,"'" the court
1981). The court dismisses as dicta language from Wally. United Gas PublicServs. Co., 152 So. 561, 563
(La. 1934) that treats market value as current market value not market value at the time the contract is
executed. Henry, 418 So. 2d at 1337.
152. [d. at 1335.
153. ld. at 1337. This result would be a surprise to many economists and lawyers. Texas courts.
for example, rarely find contractual or deed language ambiguous. See Bruce Kramer, The Sisyphean Task
ojInterpreting Mineral Deeds and Leases: An Encyclopedia ofCanons a/Construction, 24 TEX. TECH
L. REv. ) (1993). In a case decided within two years of Henry, the Louisiana Supreme Court treated the
term market value as not being ambiguous and meaning what Foster and Vela held. Shell Oil Co. v.
Williams, Inc. 428 So. 2d 798, 76 Oil & Gas Rptr. 221 (La. 1983). Perhaps because both parties did not
contend that the term was ambiguous and because both agreed that the term market rate or market price
refers to current market value the issue was presented in a different context, but it is hard to reconcile Henry
and Williams. The court in Williams drops a footnote saying that because ofthe agreement ofthe parties
regarding the meaning of the term market rate or market price or market value, the issue is different than
in Henry. Jd. at 798 n.). I personally do not see how the same term can be ambiguous in one oit and gas
lease and not in another. This harkens back to the problems caused in Texas regarding the term "other
minerals" in oil and gas deeds as requiring a case by case analysis ofsuch factors as depth ofminerais and
methods ofextraetion. Compare Moserv. U.S. Steel Corp., 676 S.W.2d 99,10).82 Oil & Gas Rptr. 143
(Tex. 1984) (holding title to uranium belongs to the owner ofthe mineral estate), with Reed v. W.C. Wylie,
597 S.W.2d 743, 744 (Tex. 1980) (holding that the depth afthe ignite "at the surface" was included in the
surface estate), and Reed v. W.C. Wylie, 554 S.W.2d 169, 170, 65 Oil & Gas Rptr. 286 (fex. 1977)
(holding owner oftbe minerals has to show extraction would deplete the source), and Ackerv. Guinn, 464
S,W.2d 348, 352-53, 38 Oil & Gas Rptr. 273 (fex. 1971) (holding ore helongs to the surface estate and not
the mineral estate).
154. Henry, 4) 8 So. 2d at 1339. The court also relies on the old reliable custom and practice excuse
ofadmitting evidence. The court states:
The custom ofthe industry may also be considered in determining the true intent ofthe parties
as to ambiguous contract provisions . ... At trial, defendants presented unrefuted evidence that
customary practice in the oil and gas industry required the Jessee to pay 'market value' royalties
on gas in dollar amounts equivalent to the price received under a long-term sales contract (less
permissible transportation charges), and the lessors to accept royalty payments so calculated.
2004]
INTERPRETING THE ROYALTY OBLIGATION
251
considered such factors as the prevalence oflong-term gas purchase contracts
at the time the lessee executed the contract in this case, the unforeseeable rise
in natural gas prices, and the limited marketing options available because of
pipeline monopolies. The issue was really not the surrounding circumstances
of the marketing practices existing at the time the oil and gas lease was
executed but rather, what methodology did the parties agree to utilize? The
meaning of the term market value did not change between 1960 and 1980.
What changed was the marketplace. If one executes a contract to deliver
widgets in sixty days at market value, that seller bears the risk that market
value will fall within that sixty day period while the buyer bears the risk that
the market value will rise. If a catastrophic event occurs that totally craters
the market value of widgets or increases their value by ten-fold, the parties
will nonetheless be bound by their agreement. Yet, Louisiana, Arkansas, and
Oklahoma are willing to bail out unfortunate lessees from making bad
economic and contractual choices in their oil and gas leases.
Finally on this issue, it must be determined whether the parsing approach
to the market value royalty clause works for both the lessee and the lessor.
Obviously, lessors under Foster and Vela receive the full benefit of having a
market value clause at a time when market value exceeds the contract price.
What would happen if the opposite occurs, namely that the contract price
exceeds the market value or market price? That issue was before the Texas
Supreme Court in the recent case of Yzaguirre v. KCS Resources, Inc. ISS The
gas royalty clause required payments based on the amount realized when the
gas was sold at the wells, while payments were to be based on market value
for gas sold off the premises. ISO The gas purchase contract was executed in
1979. The contract provided that the sale would take place at the tailgate of
a processing plant several miles away from the lease. After 1990, the contract
price began to exceed the market price for gas sold in the same field. The
lessees filed a declaratory judgment action seeking to affirm their view that
royalty payments could be made on the lower market price than on the actual,
higher contract price or proceeds.
The Texas Supreme Court has been, over the years, a primary adherent
to the parsing approach to contract and deed interpretation issues. It follows
its earlier decisions in Vela and Middleton that the terms amount realized and
market value involve two different calculation methodologies. Extrinsic
factors such as fairness to the lessor and the changing gas marketplace are
irrelevant under the parsing approach. The court observed, "The same plain
terms that fix the lessee's duty to pay royalty also define the benefit the lessor
is entitled to receive. Thus, under the leases, Yzaguirre and the other Royalty
[d. at 1339-40.
155. 53 S.W.3d 368 (fex. 2001); see DeLos Santos v. Coastal Oil & Gas Corp., No. 05-97-00029CV (Tex. App.-Dallas 1999, writ denied) (not designated for pUblication), 1999 Tex. App. LEXIS 6100.
156. YZQ£uirre. 53 S.W.3dat370-71.
252
TEXAS TECH LAW REVIEW
[Vol. 35:223
Owners are entitled to a market-value royalty, not an amount-realized
royalty."IS7
V. AT THE WELL? IN THE PIPELINE? AT THE BURNER TIp? THE
ApPLICATION OF THE NETBACK METHODOLOGY MEETS RESISTANCE
As noted in the previous section, one way of determining either net
proceeds, market price, or market value is to use the netback or workback
methodology. I" The interpretational issue that arises in these cases and which
has led to the felling of many trees is whether the term "at the well" or
something similar authorizes the lessee to utilize the netback methodology
where actual or comparable sales data is unavailable or not conclusive. IS. In
other words, while royalty is universally treated as an interest that is free of
the cost of production, does that make it free of the costs that follow the
production process, whereas in most oil and gas leases the point of valuation
is typically defined to be the wellhead, the lease, the pipeline to which the
well is connected, or the field. In addition, reviewing thousands ofleases over
the past few years uncovered lease language that expressly deals with the
right, or lack of right, of the lessee to use the netback methodology to
determine the appropriate value, price, or proceeds from which the royalty
figure is to be calculated.
157.
158.
[d. a1373.
See discussion supra Part IV.
159. See generally WILLIAMS & MEYERS, supra note 1, § 645. See McArthur, supra note 7; Scott
Lansdown, The Implied Marketing Covenant in Oil and Gas Leases: The Producer's Perspective, 31 Sr.
MARY'S L.J. 297 (2000); Owen L. Anderson, Royalty Valuation: Should OverridingRoyalty Interests and
Nonparticipating Royalty Interests, Whether Payable in Value or in Kind, Be Subject to the Same
Valuation Standard as Lease Royalty? 35 LAND & WATER L. REv. 1 (2000); Mark D. Christiansen, A
Landman's Guide to Drafting Provisions/or the Allocation alGas Marketing-Related Costs Under the
Oil and Gas Lease, 45 ROCKY MTN. MIN. L.INST. 21-1 (1999); David E. Pierce, The Missing Link in
Royalty Analysis: An Essay on Resolving Value-Based Royalty Disputes, 5 TEX. WESLEYAN L. REv. 185
(1999); Brian S. Tooley & Keith D. Tooley, The Marketable Product Approach in the Natural Gas Royalty
Case, 44 ROCKYMTN. MIN. L. INST. 2)-1 (1998). Whilethesewell-written tomes are very recent, the issues
they analyze have also been around for many years. The issue of whether a gas producer may use the
netback methodology where the point ofvaluation is at the well and the producer must construct a pipe line
to market the gas at some distance from the weJIhead was analyzed in a 1926 treatise, and the conclusion
was reached that the lessor would not be liable for the cost of the pipe line but may be liable for the
proportionate share ofthe reasonable rental value ofsuch a line. MILLS & WILLINGHAM, supra note27, at
188-89. Those authors note a disagreement on that issue between the states. Compare Clear Creek Oil &
Gas Co. v. Bushmaier, 255 S.W. 37 (Ark. 1923), and Scott v. Steinberger, 213 P. 546 (!Can. 1923), and
Raines v. Ky. Oil Co., 255 S.W. 121 (Ky. (923), with Batton v. LaClede Oil Co., 112P. 965 (Okla. 1910).
This same division ofauthority was cited as continuing in 3A SUMMERS, THE LA WOF OIL AND GAS 124-28
(2nd ed. (958).
2004]
INTERPRETING THE ROYALTY OBLIGATION
253
The parsing approach to resolving this issue is probably best exemplifie?
by the Fifth Circuit decision, Piney Woods ~~untry Life ,fchool v. Shell ~'l
CO. 160 In describing the meaning of the term at the well the court stated.
But we do find his discussion [Frank G. Hannon, Gas Royalty-Vela,
Middleton, and Weatheiford, 33 INST. ON OIL & GAS L. & TAX'N 65 (1982)]
instructive on the purpose ofthe distinction between gas sold at the well and
gas sold offthe lease. We conclude that the purpose is to distinguish.between
gas sold in the fonn in which it emerges from the well, and ga:o to whIch value
is added by transportation away from the well or by processmg after the gas
is produced. The royalty compensates the lessor for the value. of the. ga~ at
the well: that is, the value of the gas after the lessee fulfills Its oblIgatIon
under the lease to produce gas at the surface, but before the lessee adds to the
value of this gas by processing or transporting it. .. '.
.
,At the well' therefore describes not only locatIon but qualIty .as well.
Market value at the well means market value be.fo~e pro~essm.g and
transportation and gas is sold at the well ifthe price paId IS conSIderatIon for
,
•
161
the gas as produced but not for processing and transportatIOn.
Not surprisingly, the parsing approach is also followed in Texas. The Texas
Supreme Court has said:
Market value at the well has a commonly accepted meaning. in the oil an? ~as
industry .... Market value is the price a willing seller obtams from a wlllmg
buyer. " There are two methods to determine market value at the well.
The most desirable method is to use comparable sales ...
Courts use the second method when information about comparable sales
is not readily available. . .. This method involves subtracting r~asonable
post-production marketing costs from the market value a~ the pomt of sale
. . .. Post-production marketing costs include tran~~~rtmg the gas to the.
market and processing the gas to make it marketable.
The words "at the welJ" or their equivalent sufficiently indi.cat~ that,
according to these decisions, the royalty should b.e calculated III Its raw
commodity state. Nothing more is needed to authorIze the lessee to use the
160. 726 F.2d 225, 79 Oil & Gas Rptr. 244, reh 'gdenied, 750 F.2d 69 (5th Cir. 1984), cerl. denied,
471 U.S. 1005 (1985).
.
161
P·
Wi ods 726 F.2d at231. Several early cases and commentators concluded that, Insofar
mey 0
•
the pipe
. I'me even were
h therewas
as oil was. concerned,
the >point ofvaluation was to be at the well or In
no express leasehold language to that effect. Walker. supra note 1. at 31 0-11.
162 HeritageRes., Inc. v. Nationsbank, 939 S.W.2d 118,122, 1340i1 & Gas Rptr. 547 (Tex. 1996).
Heritage' is also interesting because there was express language in the royalty clause not allowmg certam
deductions to be made. See 939 S.W.2d at 120~21. The court relies on Texas Oil & Gas Corp. v. Hagen,
683 S.W.2d 24, 28 (Tex. App.-Texarkana 1984), dism'd as moot: 760 S.W.2d 960 (Tex. 1988~ for u:
ofthe netback methodology. ld. at 126; see Judicev. MewboumeOti Co., 939 S.W.2d 133, 133 ad &G
Rptr. 513 (Tex. 1996).
254
TEXAS TECH LAWREVIEW
[Vol. 35:223
netback methodology when either the proceeds, price, or value is more easily
ascert~inable downstream of the wellhead which is the designated point of
valuatIOn.
Using the parsing approach does not necessarily lead to a finding that the
netback m~thodology may be used by the lessee incurring post-production
costs. The Issue becomes: Does the lease provide for a point ofvaluation that
clearly shows thatvaloe-enhancing costs that are downstream ofthat point can
be S? used? For example, the North Dakota Supreme Court applied the
parsmg approach to a royalty clause that merely used the term "proceeds" to
describe the royalty obligation. The clause mentioned no point of valuation.
Here nothing to parse existed; the clause was ambiguous so that extrinsic
evidence or canons ofconstruction should have been used. In West, the court
relied on the canon ofconstruing against the scrivener to find that the netback
methodology should not be employed to deal with processing costs incurred
downstream of the wellhead. Yet, several years later, an Eighth Circuit
opinion applying North Dakota law was discerning enough not to apply a
blanket rule of not allowing post-production costs to be used in the netback
methodology when the royalty clause provided for payments based on "market
value at the we1L,,163
As note.d earlier, the acceptance of the netback methodology was
reasonably WIdespread by courts throughout the nation. 164 Louisiana was one
of the states that allowed the use ofthis methodology when it authorized the
lessor's royalty share to be based on the value at the wellhead, rather than the
value received by the lessee after transporting the gas some two miles. 165 This
parsing approach was also explained by a Michigan court as a way to avoid
uncertainty and ambiguity in interpreting the royalty clause. IOO The court
noted:
[I]f the term [at the wellhead] is understood to identify the
location at which the gas is valued for purposes of calculating a
lessor's royalties, then the language 'at the wellhead' becomes
clearer and has a logical purpose in the contract. In construing
'wellhead' thusly-in a manner that seeks to accord reasonable
meaning to the plain language ofthe contract-we believe that it
necessarily follows that to determine the royalty valuation,
163.
Hurinenko v. Chevron U.S.A., Inc:, 69 F.3d 283, 134 Oil & Gas Rptr.249 (8th Cir. 1995).
164.
See. e.g., Pmey Woods CountrY LIfe Sch. v. Shell Oil Co., 726 F.2d 225, 238, 79 Oil & Gas
Rptr. 244 (5th Crr. 1984); J.M. Huber Corp. v. Denman, 367 F.2d 104, 104,25 Oil & Gas Rptr. 347 (5th
CIf. 1966); Butler v. Exxon Corp., 559 S.W.2d 410, 59 Oil & Gas Rptr. 529 (Tex. Civ. App.-EI Paso
1977, wntrefd n.r.e.).
165. Wall v. Pub',Gas Servo Co., 152 So. 561 (La. 1934); see Phillips Petroleum Co. v. Johnson, 155
F.2d 185, 188-89 (5th Crr. 1946), cer!. denied, 329 U.S. 730 (1946); Kretni Dev. Co. v. Consol. Oil Corp.,
74 F.2d 497, 499-500 (lOth Cir. 1934), cerl. denied, 295 U.S. 750 (1935).
1997;66. Schroeder v. Terra Res., Ltd., 565 N.W.2d 887, 894, 138 Oil & Gas Rptr. 361 (Mich. App.
2004]
INTERPRETING THE ROYALTY OBLIGATION
255
postproduction costs must be subtracted from the sales price ofthe
gas where it is subsequently marketed. I"
While the parsing approach was widely followed, cracks began to appear in
the jurisprudence as early as the 1960s.168 The article now turns to the
extrinsic approach.
.
Outside ofthe federal oil and gas royalty arena,16. it was Kansas that led
the parade in moving away from the parsing approach to the "at the well"
issue. l7o In two separate cases, the court found that compression costs that
were incurred after the gas had been severed from the ground could not be
used to determine the value of the royalty, even though both of the royalty
clauses involved used "at the well" or similar language to describe the point
of valuation, I7l While the court's rationale is unclear, some language
suggested that under an implied covenant to market, the duty is placed upon
the lessee to put the gas into a marketable condition and apparently un..
compressed gas is not deemed marketable. 172 Remarkably, th ese tw0 opInIOns
ignore at least four earlier decisions finding that the terms "at the well" or "~n
the pipeline" authorize the lessee to use the netback methodology. In
calculating royalty. 173 While the earlier cases involved transportat~on
expenses, the opinions do not attempt to distinguish between tran~po~tlOn
and compression costs because both types of costs under the extrmslc test,
167. [d. It is interesting to note that the Fifth Circuit opinion in Frey v. Amoco Production Co., 943
F.2d 578, 113 Oil & Gas Rptr. 434 (5th Cir. 1991), that was withdrawn when the issues were c~rtified t?
the Lo'uisiana Supreme Court applied the parsing approach to the "at the well" language saymg that It
effectively allocated post~production costs to both the lessor and lessee where the actual proceeds were
received downstream oCthe wellhead. Frey. 943 F.2d at 583.
168. See, e.g., Gilmore v. Superior Oil Co., 388 P.2d 602, 605-07, 20 Oil & Gas Rptr. 457 (Kan.
1964); Schupach v. Cont'! Oil Co., 394 P.2d I, 5-6, 21 Oil & Gas Rptr. 304 (Kan. 1964).
169. See DANTE ZARLENGO, ROYALTIES, LAW OF FEDERAL OIL & GAS LEASES § 1304 (2002).
Because federal oil and gas royalties are not only subject to the tenns of the lease. but to Inte~or
Department regulations, the parsing and extrinsic dichotomy does not really apply. Id. The 1nte~or
Department has consistently taken the position ~ince the 1950s that only limited ~es o~~ost-productlo~
expenses may be deducted in the royalty calculation methodology. See generally ld. The gross proceeds
or "marketable product" rule has been adopted as ageneral basis for royalty payment since 1988 altho~gh
the practice was approved much earlier in California Co. 'V. Seaton, 187 F. Supp. 445, 44~-49, 14 011 &
Gas Rptr. 513 (D.D.C. 1960), aff'd sub nom. California Co. v. Udall, 296 F.2d 384, 16 all & Gas Rptr.
22 (D.C. Cir. 1961).
170. See Gilmore, 388 P.2d at 605-07; Schupoch, 394 P.2d al 5-6.
171. See Gilmore, 388 P.2d at 606; Schupach, 394 P.2d at 5.
172. Gilmore, 388 P.2d at 606-07 (relying on Professor Merrill's 1940 treatise on implied
covenants).
173. See. e.g., Matzen v. HUglon Prod. Co., 321 P.2d 576,8 Oil & Gas Rptr. 1216 (Kan. 1958)
(discussing natural gas production, gathering expenses); Molter v. Lewis: 134 P.2~ 40~ (K~. 1943)
(discussing oil production, transportation expenses); Vosh~JJ v. Indian Temtory I1Iu~tnattng ad Co., 19
P.2d 456 (Kan. 1933) (discussing oil production, transportation expenses); Scott v. S~tnberger, 2.1~ P. 646
(Kan. 1923) (oil production, transportation expenses). These cases ate analyzed In Marla Wilhams &
William Watson, The Deductibility ofPostproduction Costs in Determining Royalty Under Nonfederal
Leases, 48INST. ON OIL & GAS L. &TAX'N 6-1, 6-18 10 6-25 (1997).
256
TEXAS TECH LAW REVIEW
[Vol. 35:223
applying the implied marketing covenant, would appear necessary to create a
marketable product. 174 This ambivalent approach towards applyingthe parsing
approach to transportation expenses and the extrinsic approach to compression
costs was followed by a federal district court opinion issued three years after
Schupach and Gilmore. The federal court followed the parsing approach and
allowed a lessee to use the netback methodology for natural gas production
that was transported away from the lease for eventual sale to a third party.'"
The real impetus, however, for the extrinsic approach comes with the
Oklahoma Supreme Court decision, Wood v. TXO Production CO. 176 In this
5-4 decision, the majority used the extrinsic approach to find that the term
"market price at the well for the gas sold" was not clear enough evidence of
intent to allow the lessee to use the netback methodology to calculate royalties
where compression, dehydration, and gathering expenses were incurred
downstream of the well. 177 The court's rationale was that the implied
covenant to market required the lessee, at its sole expense, to get the product
to the place of sale in marketable form. 178
174.
See, e.g., Matzen, 321 P.2d at 576; Molter, 134 P.2d 8t404; Voshell, 19 P.2d at456;Scott, 213
P. at 646. Several subsequent cases apply the parsing approach to situations where compression costs are
incurred by the lessee who is allowed to the netback methodology to get back to a wellhead valuation point.
See, e.g., Martin v. Glass, 571 F. Supp. 1406,78 Oil & Gas Rptr. III (N.D.Tex. 1983), aff'd without
opinion, 736 F.2d 1524 (5th Cir. 1984); Merrittv. Southwestern Elec. PowereD., 499 So. 2d 210, 93 Oil
& Gas Rptr.491 (La. App. 1986); Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 133 Oil & Gas Rptr. 513
(Tex. 1996); Niemeyer v. Tana Oil & Gas Corp., 39 S.W.3d 380, 150 Oil & Gas Rptr. 139 (Tex. App.Austin 200 I, pet. denied).
175. Ashland Oil & Ref. Co. v. Staats, Inc., 271 F. Supp. 571, 577, 27 Oil & Gas Rptr. 6 (D. Kan.
1967).
176. 854 P.2d 880, 125 Oil & Gas Rptr. 139 (Okla. 1992). Arkansas had somewhat earlier signaled
its intent to apply the extrinsic approach to compression costs in Hanna Of! & Gas Co. v. Taylor, 759
S.W.2d 563, 103 Oil & Gas Rptr. 7 (Ark. 1988). The royalty clause provided that payments were to be
made on "proceeds received by Lessee at the well." Hanna Oil & GasCa., 759 S.W.2d at 564. The court
relied on the canon ofconstruction of construing against the scrivener, and that the lessee had not used the
netback methodology during the first years of production. See id. at 564-65. The contemporaneous
construction canon, like the construe against the scrivener canon, is typically used where the language is
either ambiguous or unclear, indicating that the court finds the "at the well" language insufficient by itself
to authorize the use ofthe netback methodology. See id.
177. Wood,854P.2dat882.
178. Id. The rationale of Wood is followed in TXa Prod Corp. v. State ex rei. Comm 'rs ofthe Land
Office, where the court holds that compression, dehydration, and gathering costs are not chargeable against
the royalty value because such processes are necessary to make the gas marketable. 903 P.2d 259, 132 Oil
& Gas Rptr. 189 (Okla. 1994). In TXa, the royalty clause provides that the delivery obligation is into the
pipeline while the payment obligation is merely market value. 903 P.2d at26I. The court states: "when
Commissioners elect to receive cash instead of actual production, they should receive the market value of
the in-kind royalty which is one-eighths royalty ofproduction without cost into pipelines." Id. The court
does not cite to Land Office regulations that define market value in away consistent with the holding. See
id. The issue in Oklahoma has been muddled somewhat by the Supreme Court's response to a certified
question from afederal district court in Mitllestadt v. Santa Fe Minerals, Inc., 954 P.2d 1203, 140 Oil &
Gas Rptr. 551 (Okla. 1998). In MiUlestadt, the royalty clause provided for payments based on gross
proceeds at the mouth of the well. 954 P.2d at 1204. The Oklahoma Supreme Court, however, in
answering the certified question, omitted the "mouth of the well" language, making it easier for the court
to continue to adhere to the marketable product or marketable condition rule based on an implied covenant.
2004]
INTERPRETING THE ROYALTY OBLIGATION
257
Shortly thereafter, the Colorado and Kansas Supreme Courts seemingly
179
adopted the extrinsic approach to the "at the well" issue. .Most remarka~ly,
the Colorado Supreme Court, in Garman v. Conoco, Inc., did not even believe
that the language creating the royalty obligation was at all.relevant to d~~ne
that obligation. ISO The language of the assignment creatmg the overndmg
royalty interest was not deemed to be a critical or even necessary. fa~tor
because the court was going to rely on extrinsic factors to create the obligatIOn
on behalf ofthe lessee to place all production into a marketable condition or
form. Thus, the court's sense ofjustice and fairness led it to apply the implied
covenant to market as the defining principle for determining the lessee's
royalty obligation. lSI The court did note that onc~ t.he natural ga~ was placed
into a marketable condition, post-marketable condltton expenses mcurred that
enhance the value ofthe natural gas may be used in a netback methodology to
calculate the royalty owed. l82 Given a second chance to apply the parsing
approach, the Colorado Supreme Court expressly held in Rogers v. Westerman
Farm Co. that express lease language such as "at the well" or "at the mouth
ofthe well" do not do away with the extrinsically created implied covenant to
place the natural gas in a marketable condition for royalty calculation
purposes. IS'
Cases applying the extrinsic approach to the "at the well" issue cha~ge
the question from "what are production costs?" and "what are post-productIOn
costs?" to "when is a marketable product achieved?" Most of the courts that
have adopted the extrinsic approach have not provided a clear definition of a
marketable product. 1S4 The Rogers case treats that issue as a question offact
for ajury, so it is possible that gas from a split-stream well may be found to
have different marketable conditions based on a series ofexternal factors such
as the location where the gas is sold, the existence of a commercial
marketplace for the gas made up ofmore than a few buyers, and the physical
condition ofthe split-stream well. I" As stated elsewhere, "It appears that the
See id. The Oklahoma court follows Garman v. Conoeo, Inc., 886 F.2d 652. 132 Oil & Gas Rptr. 488
(Colo. 1994), in concluding that various post·marketable product expenses that are reasonable and increase
the value ofthe natural gas may be used in the netback methodology. Mittlestadt, 954 F.2d at 1210. But
see WILLIAMS & MEYERS, supra note I, § 645,2 (critiquing the holding of Mittlestadt).
179. See Garman, 886 P.2d at 652; Sternbergerv. Marathon Oil Co., 894 P.2d 788, 132 Oil & Gas
Rptr. 65 (Kan. 1995).
180. 886 P.2d at 652.
181. See id. at 659.
182. AeeordMittlestadt, 886 F.2d at 66I;Sternberger, 894 F.2d at788; see also Wellman v. Energy
Res., Inc., 557 S.E.2d 254, 263, 149 Oil & Gas Rptr. 37 011. Va. 2001) (adopting the Wood/Garman
extrinsic approach). The Sternberger opinion, however, has several contradictory sections: at one p~int
embracing the extrinsic approach but then also declining to extend Sehupach/Gilmore to the transportation
of natural gas. See Sternberger, 894 P.2d at 802.
183. 29 P.3d 887, 897 (Colo. 2001).
184. The parties stipulated that the natural gas was marketable before the compression,
transportation, and processing costs were incurred. Garman, 886 P.2d at 652.
185. See Rogers v. Osborn, 261 S.W.2d3]] (Tex. 1953).
258
TEXAS TECH LAW REVIEW
[Vol. 35:223
Colorado Supreme Court has done nothing less than fashion a new rule for the
purpose of enhancing royalty values throughout Colorado."186 Extrinsic
factors, namely the relationship between the lessee and the lessor as defined
by the court, without regard to the language of the lease, now control the
royalty obligation.
VI. EXPRESS WORDS? IMPLIED COVENANTS? TRAIN WRECK OR NEVER
THE TwAIN SHALL MEET?
Earlier discussion makes clear that courts following the extrinsic
approach to royalty clause interpretational issues oftentimes resort to, or fall
back upon, the implied covenant to market to define the relationship between
the parties. 187 That fact is more evident in the recent post-production costs or
first marketable product cases than anywhere else. The supporters of both
positions tend to take the view that the concepts ofthe parsing approach and
implied covenants used in the extrinsic approach are mutually exclusive. 18•
While the basis for implied covenants is properly grounded in the general
contract principle ofcooperation, 189 that principle needs to be limited to when
the parties have not expressly agreed to a standard of conduct that wil1 bind
them for the life ofthe contract. When matters are left open, the cooperation
principle clearly, as implemented through the traditional implied covenant
reasonable and prudent operator standard, may fill in those lacunae. It does
not necessarily follow that a state that tends to follow the parsing approach
wil1limit the application of implied covenants, nor does it necessarily follow
that a state that tends to follow the extrinsic approach will ignore the express
language of the instrument. Having said that, as the earlier discussion
illustrated, a certain confluence inherently exists between the parsing and
express covenant approaches and the extrinsic and implied covenant
approaches.!'"
While forty-nine states adhere to the common law tradition, Louisiana,
follows the civil law tradition. The civil law typically does not leave such
matters to the courts but instead adopts statutory provisions such as Article
122 ofthe Louisiana Mineral Code which imposes upon the lessee the duty to
be a "good administrator" of the lease. 19! But the cooperation principle still
186.
supra note 1, § 645.2.
See discussion supra Part IV.
188. Compare McArthur, supra note 7. and Weaver. supra note 8, with Lansdown, supra note 254.
and Williams & Watson, supra note 273.
189. WILLIAMS & MEYERS. supra note I. § 802.1.
190. See discussion supra Part IV.
WILLlAMS & MEYERS,
]87.
19I. LA. MIN. CODE art. 122 (2002); see also LA. CIV. CODE art. 2710 (2002) (imposing a similar
duty on other types of contracts).
INTERPRETING THE ROYALTY OBLIGATION
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259
must be measured against the express agreement between the parties in the
absence of fraud, duress, or gross inequality of bargaining power.!92
Many courts and commentators, even those that support the extrinsic
view of contract interpretation, start from the premise that when the parties
have clearly evinced their intentthrough the written instrument, the instrument
should prevail. l " In earlier times, this dispute was reflected in the academic
debate between A.W. Walker and Maurice Merrill as to whether implied
covenants were implied in law or implied in fact.!'4 In discussing this debate,
the treatise makes the following observation:
We suspectthat the disagreement [between Walker and Merrill] is more than
academic shadowboxing. While bDth the cases and the text writers agree that
a covenant cannot be implied in contradiction of an express lease provision,
nevertheless, the greater emphasis that is put on the equitable nature of
implied covenants, the greater freedom courts have to fmd a covenant that
does not loom out of the printed words ofthe lease. I"
Two cases arising some fifty to sixty years ago reflect these two approaches
to the problem ofdetermining whether a court should imply a covenantto deal
with a performance problem by the lessee to an oil and gas lease. 196
Danciger Oil & Refining Co. v. Powell is the paradigm of the Walker
view that implied covenants only exist in the absence of express leasehold
language governing the conduct of the parties. I ' 7 While Danciger actually
involved a mineral deed reserving a royalty interest rather than a mineral
lease, the court finds that the standard for implying a covenant in both
situations is the same. I" The court in the following language imposes a fairly
rigorous test:
In the outset it should be noted that when parties reduce their agreements to
writing, the written instrmnent is presumed to embody their entire contract,
See supra text accompanying note 133,
See, e.g., Adkins v. Adams, 152 F.2d 489 (7th Cir. 1945).
Compare A. W. Walker, The Nature oj/he Property Interests Created by an Oiland Gas Lease
in Texas, 11 TEx. L. REv. 399. 402-06, with MAURlCE MERRILL, COVENANTS IMPLIED IN OfLAND GAS
LEASES §§ 7, 220 (2d ed. 1940). See Patrick Martin, A Modem Look at Implied Covenants to Explore,
Develop and Market Under Mineral Leases, 27INST. ONQIL&GAS L.& TAX'N 177 (J 976); Eugene Kuntz,
Professor Merrill's Contribulion to Oil and Gas Law, 25 OKLA. L. REv. 484 (1972).
195. WILLIAMS & MEYERS, supra note I. § 803 (footnote omitted). It is interesting to note that
Professor Merrill has extensive portions of his treatise devoted to the fact that express leasehold language
may preempt any ofthe varieties ofirnplied covenants found in an oil and gas lease. MERRILL, supra note
194, §§ 65, 199-202. Likewise, when our predecessors organized the implied covenant volume, each of
the major categories ofimplied covenants had as a sub-category the effect ofexpress lease provisions. See
WILLIAMS & MEYERS, supro note I, §§ 807, 812, 826.3, 835.3, 858.4.
196. See infra notes197-205.
197. 154 SW.2d 632 (Tex. 1941).
192.
193.
194.
lOR.
fA
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[Vol. 35:223
and the court should not read into the instrument additional provisions unless
this be necessary in order to effectuate the intention of the parties .... An
implied covenant must rest entirely on the presumed intention ofthe parties
as gathered from the terms as actually expressed, ... and it must appear that
it was so clearly within the contemplation of the parties that they deemed it
unnecessary to express it . . .. It is not enough to say that an implied
covenant is necessary in order to make the contract fair, or that without such
a covenant it would be improvident or unwise, or that the contract would
operate unjustly. "9
While this may go a bit overboard by requiring that the issue be within the
clear contemplation of the parties so that it is not necessary to include it, the
Texas Supreme Court made the point that extrinsic factors should not, by
themselves, be used to modifY, alter, or amend the express language contained
in the written instrument.
Millette v. Phillips Petroleum Co., on the other hand, represents the view
that the court should use extrinsic factors such as fairness and justice even in
the face of express language to interpret an oil and gas lease.'oo In Millette,
the parties expressly agreed to a ISO-foot offset well clause.'ol A well, located
some 570 feet from the lease line, was allegedly causing drainage.'o, The
result under Danciger appeared to be straightforward: the lessee and lessor
agreed to require an offset well under a limited set ofcircumstances. Since no
triggering event implicated the duty to drill an offset well, the lessee was free
not to drill such a well. Millette reached a different result, partly on the basis
of its interpretation of the state's oil and gas conservation laws and partly on
the basis of the unfairness to the lessor. The court observed:
It is elemental that parties may not contract contrary to expressed public
policy so that while the express provision regarding the drilling ofoffset wells
may be upheld, there remains a fundamental principle founded as well in
equity as in policy that an owner or lessor is entitled to reasonable protection
against the loss ofmineral resources in his lands. The express provision here
involved absolved the lessee from meeting his duty to the less[or] by
capturing lessor's oil in situ through wells drilled on lessors' lands. The
equitable duty, existing as well under implication, to conserve the mineral
resources oflessors or to refrain from depletory acts survives unimpaired.20'
Jd.oI635.
48 So. 2d 344 (Miss. 1950).
201. Jd. 01345.
202. Jd.
203. Jd. 01347; see Phillips Petroleum Co. v. Millette, 72 So. 2d 176, 179,3 Oil &Gas Rptr. 803
(Miss. 1954).
199.
200.
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INTERPRETING THE ROYALTY OBLIGATION
261
Influenced by the existence of fraudulent drainage, the court determined that
the express language of the lease would not control. Instead, the implied
covenant's reasonable and prudent operator standard bound the lessee.
While these two cases appear to represent the polar positions regarding
the effect ofexpress leasehold language on the implication ofcovenants, most
court decisions tend to fall somewhere in between, realizing that the courts are
not free to rewrite a written agreement, but taking the temporizing view that
an oil and gas lease may not cover all ofthe future events that can impact t~e
relationship between the parties. '04 In fact, the language used by ~he court In
Frey shows a need to explain that the express language o~~e partIes does not
gOvern the situation since the parties are free under the CIVIl Code to agree to
. '0'
a performance standard less than the standard which the co de wou ld reqUIre.
Up until the use of the implied covenant to market as the support for the
"first marketable product" rule, relatively few cases dealt with the effect of
express lease provisions on the covenant. '06 The cases analyzed in Pro: Iy
reflect the current division between jurisdictions that apply the extrmslc
approach to leasehold terms that define the point ofvaluation andjurisdictions
that apply the parsing approach. Jurisdictions in which courts apply the
extrinsic approach, in general, apply it in these point of valuation cases. One
exception to this rule is Louisiana, a firm adherent to the extrinsic approach.
Notwithstanding that approach, Louisiana has been a reasonably firm adherent
to the view that expenses incurred downstream ofthe wellhead can be used as
part of the netback methodology. One of the earliest ~ases ~ayi~g ou~ ~e
rationale for the use ofthe netback methodology was a FIfth CIrCUIt deCISIon
applying Louisiana law.'o' The court stated:
[I]n determining market value costs which are essential to make a commodity
worth anything or worth more must be borne proportionately by those who
benefit. To put it another way: in 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 ofthat cost, but not
because the obligation (or expense) ofproduction rests on him. Rather, it is
Compare Danciger, 154 S.W.2d at 632, with Millette, 48 So.2d at 344.
See Frey v. Amoco Prod. Co., 943 F.2d 578, 113 Oil & Gas Rplr. 454 (5th Cir. 1991).
206. The few cases are gathered at WILLIAMS & MEYERS, supra note 1, § 858. See also Bruce
Kramer & Chris Pearson. The Implied Marke/ingCovenant in Oiland Gas Leases: Some Needed Changes
fo' the 90 's, 46 LA. 1. REV. 897 (1986).
207. Freeland v. Sun Oil Co., 277 F.2d 154, 13 Oil & Gas Rptr. 764 (5th Cir. 1960).
204.
205.
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TEXAS TECH LAWREVIEW
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because that is the way in which Louisiana law arrives at the value ofthe gas
at the moment it seeks to escape from the wellhead. 208
Even as to compression costs, Louisiana courts have allowed the lessee to use
the netback methodology when the point of valuation was at the well. 209 At
least one post-Frey opinion recognizes the continued adherence ofLouisiana
courts to the use ofthe netback methodology for post-production downstream
processing costs, although the court determined that factual issues existed
regarding the reasonableness of the amount of costs so utilized."o
Another good example of a disconnect within a jurisdiction arises in
Texas. Most commentators will agree that Texas follows the parsing approach
to contract interpretation issues. In addition, when it comes to the royalty
clause and implied covenant to market cases, Texas treats the express
language of the royalty clause as preempting any implied covenant when the
royalty clause requires the payment of market value. 211 Yet in at least one
area, Texas courts have been loath to find express leasehold language
preempts or co-opts an implied covenant. A series of cases finds that where
the parties have included an express offset clause in their oil and gas lease,
that clause will only be operative no later than the end of the primary term, if
not sooner, even though the express language contains no such time
limitation.'12 While this approach has been criticized, it is still good law.213
The Louisiana and Texas examples are illustrative of the fact that we
should not fall into the trap sometimes called "a tyranny oflabels." One might
say that Texas, for example, is a paradigm for the parsing approach, as well
as the "implied in fact" approach to covenants. One might also say that
Colorado, for example, is a paradigm for the extrinsic approach, as well as the
"implied in law" approach to covenants. But the two approaches are not
mutually exclusive. Courts tend to be fact-specific in their orientation.
Whether a court will apply a parsing approach or an extrinsic approach will
not be an either"or choice. Instead, the court will employ more of a linedrawing contest on a continuum where one pole represents parsing and the
other represents extrinsic. The same proves true for a court's view of how
express and implied covenants interrelate. Most courts will draw a line
somewhere between the implied in fact and implied in law poles. Where that
208. Free/and, 277 F.2d at 159.
209. See, e.g., Merrittv. Southwestern Blee. Power eo., 499 So. 2d210. 93 Oil & Gas Rptr. 491 (La.
Ct. App. 1986).
210. Babin v. First Energy Corp.• 693 So. 2d813, 96 Oil &Gas Rptr. 1232 (La. App. 1997) (relying
on Freelandto treatas settled law the use ofthe netback methodology to determine royalties where the lease
provides for a wellhead valuation).
211. See Yzaguim: v. KCS Res., Inc., 53 S.W.3d 368 (Tex. 2001).
212. See Coatsv. Brown, 301 S.W.2d 932, 8 Oil & Gas Rptr. 27 (Tex. Civ. App.-Texarkana 1957,
no writ); Magnolia Petroleum Co. v. Page, ]41 S.W.2d 691 (Tex. Civ. App. 1940, writ ref d).
213. WILLJAMS &MEYERS,SUpra note I, § 826.3.
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INTERPRETING THE ROYALTY OBLIGATION
263
line is drawn will depend on the language ofthe oil and gas lease and the facts
ofthe particular case. Oil and gas leases are not uniform. Royalty clauses are
not uniform. While undoubtedly, common language is shared among different
fonus and widespread use of the same form exists in specific areas, courts
should, as their first order ofbusiness, look to what the parties said. When the
parties have used ambiguous language, canons of construction or other
extrinsic factors may be appropriately used to ascertain the intent of the
parties.'14 Where the agreement fails to mention a particular matter, reliance
on the cooperation principle as a basis for the implication of covenants is
appropriate. Courts should remain flexible in dealing with issues. They
should not blindly adhere to the parsing or extrinsic approach or to the implied
in fact versus implied in law approach. Ad hoc decision-making, while
creating a host ofuncertainty, will lead to better decisions, and ifthe lawyers
are paying attention, better written instruments in the future.
214. There are some states, such as New Mexico, that have essentially done away with the parole
evidence rule by making all evidence admissible regarding the fannatian of a contract, whether or not the
final agreement is ambiguous or unambiguous. See C.R. Anthony Co. v. Loretto Mall Partners, 817 P.2d
238 (N.M. 1991).