A Reexamination and Reformulation of the Habendum Clause Paying Quantities Standard Under Oil and Gas Leases
Under Oil and Gas Leases A Reexamination and Reformulation of the Habendum Clause Paying Quantities Standard
Alex Ritchie 0
Mineral Law Commons 0
0 Alex Ritchie, A Reexamination and Reformulation of the Habendum Clause Paying Quantities Standard Under Oil and Gas Leases, 3 Oil & Gas, Nat. Resources & Energy J. 977 (2017), https://digitalcommons.law.ou.edu/onej/vol3/iss4/4
Part of theEnergy and Utilities Law Commons; Natural Resources Law Commons; and theOil
A REEXAMINATION AND REFORMULATION OF
THE HABENDUM CLAUSE PAYING QUANTITIES
STANDARD UNDER OIL AND GAS LEASES
* Executive Director, Rocky Mountain Mineral Law Foundation, and Associate
Professor of Law, University of New Mexico School of Law. B.S.B.A, 1993, Georgetown
University; J.D., 1999, University of Virginia. Alex is grateful once again for the able
research assistance provided by Professor Ernesto Longa.
Most United States gas production remains trapped in North American
markets due to transportation constraints.1 As such, the price of natural gas
in the United States is based almost entirely on North American supply and
demand. Since 2005, production technologies to efficiently produce natural
gas from shale and tight formations have kept natural gas prices very low;2
and prices are expected to remain stubbornly low for the foreseeable
Crude oil is another matter. Crude oil can be easily transported, imported
and exported. As such, the price of crude oil is based on global supply and
demand. The U.S. has nearly doubled production over recent years without
a corresponding rise in demand. This excess supply has battered crude oil
prices.4 The spot price of crude oil in the United States rose to a high of
$145 per barrel in July 2008, quickly and abruptly fell to $31 per barrel in
December 2008 due to the onset of the great recession financial crisis,
recovered to $113 per barrel by 2011, then began a prolonged decline in the
third quarter of 2014 until the price reached a low of $26 a barrel in
February 2016.5 During this low price environment the Organization of the
Petroleum Exporting Countries continued to produce oil at record levels
1. A movement is underway to substantially increase exports of liquefied natural gas.
See Jude Clemente, The U.S. is Transforming the Global Liquefied Natural Gas Market,
FORBES (Apr. 16, 2017, 8:01 PM), https://www.forbes.com/sites/judeclemente/2017/04/
16/the-u-s-is-transforming-the-global-liquefied-natural-gas-market/#731548bb22ef; see also
Michael A. Levi, The Case for Natural Gas Exports, N.Y. TIMES, http://www.
nytimes.com/2012/08/16/ opinion/the-case-for-natural-gas-exports.html (last visited Nov.
18, 2017). If substantial enough, this could have the effect of increasing natural gas prices.
2. U.S. ENERGY INFO. ADMIN., ANNUAL ENERGY OUTLOOK 2017, at 54, available at
http://www.eia.gov/outlooks/aeo/ (last visited Mar. 12, 2017). The Henry Hub price of
natural gas was $18.13 in September, 2005 and was $2.68 per MMBtu in March 2017. The
price has ranged between a high of $6.55 per MMBtu and a low of $1.60 per MMBtu
between August 2009 and the present. MACROTRENDS, NATURAL GAS PRICES-HISTORICAL
CHART, http://www.macrotrends.net/2478/natural-gas-prices-historical-chart (last visited
Mar. 12, 2017).
3. The U.S. Energy Information Administration forecasts Henry Hub natural gas spot
prices to average only $3.03 MMBtu in 2017 and $3.45 MMBtu in 2017. U.S. ENERGY INFO.
ADMIN., SHORT TERM ENERGY OUTLOOK MARCH 2017, at 10, available at
http://www.eia.gov/outlooks/steo/report/us_oil.cfm (last visited Mar. 12, 2017) [hereinafter,
4. Clifford Krauss, Oil Prices: What’s Behind the Volatility? Simple Economics, N.Y.
TIMES (Dec. 12, 2016).
5. Macrotrends, Crude Oil Prices – 70 Year Historical Chart, http://www.macrotrends.
net/1369/crude-oil-price-history-chart (last visited Mar. 12, 2017).
with some analysts believing that Saudi Arabia intended a price war to
harm U.S. unconventional producers.6 Since the collapse in the crude oil
market the price has slowly recovered but is expected to remain relatively
low with an average price of between $55 and $57 per barrel through 2018.7
An unknowable number of leases were executed during the high-price
environment but now many of those leases have become unprofitable.
Industry’s first response to the downturn was to delay drilling programs on
producing leases. This led to litigation involving the implied covenant to
further develop producing leases already in the secondary term. With a
sustained downturn, however, lessors are now turning to the habendum
clause of the lease and its requirement for production in paying quantities.
Does such a sustained downturn call for flexibility under the clause, or is
the clause a bluntly efficient tool? Should the reasonable time period for a
well to earn a profit include a period to restore commercial production after
a price recovery, or is the time required measured by the lessor’s patience?
This paper is only concerned with the situation where a lease has
produced in paying quantities before the end of the primary term and into
the secondary term. The lessee may have incurred substantial sums during
the exploratory term of the lease to conduct seismic testing, obtain core
samples, grade and prepare drilling sites, drill one or more test wells, and
drill and complete one or more wells that at once produced in paying
quantities. After a precipitous fall in prices, a lessee might decide to shut in
the well or wells on a now unprofitable lease and wait for prices to
improve. In that case, the lessor will complain because she has ceased
receiving royalties. Or the lessee might continue to produce
notwithstanding the depressed prices. In that case, the lessor will be
dissatisfied with the amount of royalties she now receives because her
checks have been reduced by half or more. In either case, the lessee faces
the prospect of losing its lease.
As occurred in the 1980s,8 a price downturn provides motivation to
reexamine provisions such as the two prong paying quantities standard in
the habendum clause of the oil and gas lease. Part II of this article examines
the habendum clause and the evolution of the paying quantities standard
which will determine whether a lease continues in effect or terminates
automatically. At one time the test was focused on whether the lessee was
operating the lease in good faith. The courts subsequently discarded the
deferential good faith standard in favor of a reasonably prudent operator
standard. Now these past standards have been replaced by a two part test
that first asks the accounting question whether a well produces sufficiently
to pay a profit to the operator over a reasonable time, and then asks whether
a reasonable prudent operator would continue to operate the lease for profit
and not for speculation.
Part III of this article seeks to show that courts have placed undue focus
on the mathematical first prong of the paying quantities test. The
transaction costs and litigation risks associated with unanswered legal
questions as to the contours of the mathematical prong and uncertainties as
to the time periods involved in the calculations impede private bargaining
between the parties and reduce the aggregate economic surplus to the lessor
and the lessee. Further, while litigation focuses on past performance, it is
the future that ultimately will determine whether the lessee recovers some
or all of its drilling costs and operates the lease for a profit.
The “reasonable time” required for a profit under the first prong of the
paying quantities test does not contemplate changes in market conditions.
As such, vast numbers of leases are subject to changing hands. The law
prohibits a lessee from holding a lease for speculation, but an overly
technical interpretation of paying quantities incentivizes opportunistic
behavior by lessors that could also be labeled “speculation.” During a high
price environment, lessors may realize their share of lease benefits in the
form of high bonuses, rentals, and royalties flowing from high market
prices. But the “paying quantities” requirement will in many cases allow
in Oil and Gas Leases—The Determination of Profitability, 27 KAN. L. REV. 443 (1979);
Jacqueline Lang Weaver, Implied Covenants in Oil and Gas Law under Federal Energy
Price Regulation, 34 VAND. L. REV. 1473 (1981); Patrick H. Martin, Implied Covenants in
Oil and Gas Leases—Past, Present & Future, 33 WASHBURN L.J. 639 (1993-94); Cyril A.
Fox, Jr. & Patrick C. McGinley, Maintaining Oil and Gas Leases in Depressed Gas
Markets, 8 E. MIN. L. INST. 14-1 (1987); Thomas P. Battle, Lease Maintenance in the Face
of Curtailed/Depressed Markets, 32 ROCKY MT. MIN. L. INST. 14-1 (1986); David E. Pierce,
Unresolved Implied Covenant to Develop and Paying Quantities Issues; Defining Prudent
Operator Obligations and Operations During, Good, and Not-So-Good, Times, Paper
Presented at Eugene Kuntz Conference on Natural Resources Law and Policy (2015) (on file
these same lessors to terminate their leases in the “hope” that a new lessee
will better operate or develop the premises.
Due to the shortcomings of the mathematical prong, Part IV of this
article proposes that courts reformulate the paying quantities standard by
removing the express mathematical prong of the test and by taking the best
aspects of the test from both earlier and more recent decisions. The paying
quantities test question should focus on what a prudent operator would do
and whether the current lessee has and will continue to conduct lease
operations in good faith for a profit. Although past performance remains
relevant to both the overall profitability of the lease and to the lessee’s good
faith efforts, a test that focuses on the future better correlates with the
overall purpose of the lease to benefit both the lessor and the lessee by
maximizing their cooperative surplus.
II. Paying Quantities
A. The Habendum Clause
Depending on the jurisdiction, an oil and gas lease may be either
possessory or nonpossessory, and it may be either real or personal
property.9 Nevertheless, the grant of an oil and gas lease is the grant of an
interest in land and the habendum clause is a limitation on that grant. For
historical reasons this grant has been referred to as a “lease,” but in most
jurisdictions it is not a lease in the traditional sense. It is more properly
characterized as a deed or conveyance of less than all of the fee simple or
lesser interest in the oil and gas and other minerals described in the
After experimenting with no term leases or rental paid clauses,11 the oil
and gas industry adopted the modern lease form that contains a habendum
clause with a relatively short fixed term generally ranging from one to ten
years12 (called the primary term), with a “thereafter” clause that will
9. PATRICK H. MARTIN AND BRUCE M. KRAMER, 1-2 WILLIAMS & MEYERS, OIL AND
GAS LAW § 209 (corporeal-incorporeal classification), § 212 (realty-personalty
classification) (2016) [hereinafter, WILLIAMS & MEYERS].
10. Id. § 207 (criticism of lease-deed distinction).
11. WALTER L. SUMMERS, A TREATISE ON THE LAW OF OIL AND GAS 291 (1927)
12. For cases where a shorter six month to one year lease created structural problems
with other provisions of the lease such as the “unless” clause and the dry hole clause, see
Rolander v. Sanderson, 43 P.2d 1061 (Kan. 1935); J.J. Fagan & Co. v. Burns, 226 N.W. 653
continue the lease in effect after the fixed period for “so long as” oil and
gas is produced (called the secondary term).13
The courts did not allow the lessee to remain completely idle during the
fixed primary term, but instead imposed upon the lessee an implied
requirement to drill a test well and to explore for oil and gas during the
primary term. To avoid this requirement, creative lessees crafted the “drill
or pay” clause and then the “unless” form of rental clause allowing the
payment of delay rentals to substitute for the implied drilling obligation
during the primary term.14 As such the fixed primary term has become a
mere option to drill so long as delay rentals are paid.
During the secondary term, however, production is required to maintain
the lease in effect under the habendum clause. This production requirement
is two-fold. The lease must be producing oil or gas at the end of the fixed
primary term and it must continue to produce thereafter under the “so long
Most courts construe the “so long as” language as creating a
determinable interest and the requirement for production as a special
limitation on the grant.15 In classic property terms, the interest of the
mineral owner is referred to by the Middle French term “profit à prendre,”
meaning the right to remove something from the land.16 Although clearly
proper, the “thereafter” clause has not always been classified as creating a
determinable interest. In particular, Oklahoma courts have seemingly
classified the thereafter clause as a condition subsequent such that the lessor
retains a right of entry or power of termination.17 The distinction is
A determinable interest may theoretically last forever and yet it will
expire automatically when and if the special limitation on the grant is no
13. SUMMERS, supra note 11, at 291. A lease might be drafted differently, of course, so
that it continues so long as oil and gas is “found,” “discovered,” etc., although a number of
cases have interpreted the words “found” or discovered” as synonymous with “produced.”
Id. at 293 (citing cases).
14. See SUMMERS, supra note 11, at 386; 5-8 WILLIAMS & MEYERS, supra note 9, § 812.
15. See 1-13 POWELL ON REAL PROPERTY § 13.05 (2017) (an intent to create a fee
simple determinable is manifested, inter alia, by a limitation that contains the terms “so long
as,” “until,” or “during”).
16. 4-34 POWELL ON REAL PROPERTY § 34.01 (2017).
17. See Stewart v. Amerada Hess Corp., 604 P.2d 854, 858 (Okla. 1979) (“The
occurrence of the limiting event or condition does not automatically effect an end to the
right. Rather, the clause is to be regarded as fixing the life of a lease instead of providing a
means of terminating it in advance of the time at which it would otherwise expire.”); see
also text accompanying 3-6 WILLIAMS & MEYERS, supra note 9, § 604 n.1.2.
longer satisfied.18 When the lessee holds a determinable interest the lessor
holds a possibility of reverter.19 There is no need when a special limitation
fails for the lessor to declare a forfeiture.20 In fact there has been no such
forfeiture and no termination because the term “produced” simply fixes the
term of the lease.21 Termination requires an action to cause something to
come to an end, but when the special limitation in a determinable interest is
no longer satisfied the working interest simply reverts automatically to the
In contrast, if the habendum clause is classified as subject to a condition
subsequent, then theoretically the lessor must take some sort of affirmative
act such as providing notice to the lessee of termination or commencing a
judicial action to cause the termination and forfeiture of the lease.22 Since
Stewart v. Amerada Hess Corporation,23 before a reviewing court in
Oklahoma will order a forfeiture of an oil and gas lease for breach of a
condition subsequent it will examine the equities, because equity abhors a
The Oklahoma Supreme Court had previously stated in Stewart that the
habendum clause “is to be regarded as fixing the life of a lease instead of
providing a means of terminating it in advance of the time at which it would
otherwise expire . . . ,”24 an interpretation consistent with an interest subject
to a condition subsequent. More recently in Baytide Petroleum, Inc. v.
Continental Resources, Inc.,25 however, the court walked back that
statement holding that “it is the failure to produce in paying quantities
during the lease’s secondary term rather than the entrance of a court order
which terminates a lease.”26 So although a court order might be required to
18. 1-13 POWELL ON REAL PROPERTY §13.05. The modern oil and gas lease contains
other “special limitations” on the grant, such as the requirement to either drill or pay delay
rentals during the primary term. The special limitation is created by the use of the word
“unless,” namely that the lease will expire “unless” the lessee drills or pays delay rentals.
For proposed language to avoid the automatic termination of the delay rental clause, see
David E. Pierce, Incorporating a Century of Oil and Gas Jurisprudence Into the “Modern”
Oil and Gas Lease, 33 WASHBURN L.J. 786, 805-06 (1994).
19. The lessor under an oil and gas lease also reserves the right to a royalty and other
payments, such as delay rentals and shut-in royalty.
20. SUMMERS, supra note 11, at 299.
21. Id. at 311.
22. 3-20 POWELL ON REAL PROPERTY § 20.03 (2017).
23. 604 P.2d at 858.
25. 231 P.3d 1144 (Okla. 2010).
26. Id. at 1149.
adjudicate the rights of the parties under the habendum clause in Oklahoma,
the termination date once found will relate back to the date the lease is
deemed to have no longer produced in paying quantities.
It should be clear at this point why the “thereafter” clause in the oil and
gas lease has been viewed as a guillotine clause. Whether a determinable
interest or subject to a condition subsequent, without continuing production
sufficient to satisfy the habendum clause a lessee risks a complete loss of its
investment in a lease, including any bonuses and rentals paid and any
exploration, development, drilling, and operating costs incurred. At one
moment the lessee holds a property right. The next the lessee is treated as a
good faith trespasser, a holdover tenant, or a tenant-at-will.27
B. The Need for Production or Discovery
So unless a limited exception is applicable,28 the lease will only continue
into and during the secondary term so long as it produces oil and gas. The
general majority rule is that “production” means actual production.29 The
lessee must be actually producing oil and gas at the end of the primary
term; discovery alone accompanied by diligent operations to market the
product will not suffice. Many commentators have concluded that this is the
sound interpretation of the oil and gas lease; to require only discovery and
diligence is “an unwarranted interference of a court of equity in the
interpretation of a contract of plain meaning.”30
Nevertheless, Oklahoma and a few other states require only discovery of
oil and gas capable of production in paying quantities followed by a
diligent effort to market the production.31 Oklahoma reasons that
production and marketing are two separate activities. According to this
theory, to require “actual production” ignores a distinction between
production and marketing and the difference between express and implied
terms under the lease.32
C. Production Means Production in Paying Quantities
The word “production,” however, has a more restrictive meaning than is
evident on its face. Regardless whether the lease expressly requires
“production in paying quantities” or “production” alone, in all jurisdictions
the courts hold the meaning is the same and that to extend and continue the
lease production must be in “paying quantities.”33 Courts rationalize the
need for “paying quantities” in a lease that by its express terms only
requires “production” because a lease is executed for the mutual benefit of
both the lessor and the lessee.34 What “paying quantities” actually means
has evolved over time, the history of which is discussed in Part II.E below.
D. Exceptions to the Requirement for Production
There are some exceptions that may hold a lease in the absence of
sufficient production. For example, under the common law a temporary
cessation of production will not terminate the lease,35 and modern oil and
gas leases reinforce this exception with temporary cessation of production
and dry hole clauses.36 If a lessee is engaged in drilling operations at the
end of the primary term, then an express drilling clause will allow the lease
to continue into the secondary term if the lessee continues with diligence
until production in paying quantities is achieved. Other savings clauses
such as the shut-in royalty clause may also save a lease. Although a detailed
discussion of these savings clauses is beyond the scope of this paper, these
clauses have limited application when a lessee shuts in a well to wait for a
better market or continues to produce under a lease that does not produce in
For example, courts may find that the temporary cessation of production
doctrine only applies when a lease stops producing because of some
mechanical failure,37 lack of a market,38 a fire,39 or maybe even reworking
operations,40 but not for an unfavorable market. And a modern temporary
cessation of production clause will usually only allow a lessee a very short
period of time, such as 30, 60, or 90 days, to commence reworking
operations or commence the drilling of a new well.41 The common law
allows a lessee a reasonable time to recommence production but this
reasonable time may be longer than the express time in the cessation of
production clause. And virtually all courts will enforce the lease as written
so as to disallow any cessation longer than the agreed upon time period in
The shut-in royalty clause presents similar problems. Most shut-in
royalty clauses are drafted so that the payment of royalty is a substitute for
production in paying quantities. If the “substitute” is not provided then the
lease will automatically terminate for failure of a special limitation just as it
would under the habendum clause. As such, the general rule is that the
clause must be strictly complied with such that shut-in royalty must be paid
timely in accordance with the clause, or absent a contractual grace period,
immediately upon or before the well is shut-in.43 Further, most shut-in
royalty clauses are drafted to apply only to gas, not oil, and a court may
determine that the clause only allows shut-in for a complete lack of a
market such as a pipeline connection, but not for a bad market.44
In the 1980s, deregulation caused some markets for gas to disappear, a
situation that better justified application of the shut-in royalty clause or the
extension of the lease on other grounds.45 Oil price regulation in the 1970s
and into the 1980s also distorted market prices.46 In contrast, the current
price collapse is due to simple economics of supply and demand.47
Purchasers are still willing to purchase gas and oil but the price for some
producers is too low to support current profitable operations.
E. Evolution of the Meaning of Paying Quantities
At one time the “paying quantities” requirement was a shield for lessees
because a lessee would prefer that an unprofitable lease disappear rather
than pay rent to retain the lease.48 As the case law indicates, however, it has
been used more recently as a sword for a lessor to rid himself of a lessee.
Although a lessee might realize a gain by retaining leases for speculation, a
lessor only receives the benefit of a lease when the product is produced and
45. See Barby v. Singer, 648 P.2d 14, 17 (Okla. 1982) (holding that the lease in dispute
extended because price increase reasonably anticipated after deregulation). In the late 1970’s
and early 1980’s, a supply shortage of natural gas sold in interstate markets resulted from
Federal Power Commission’s regulation of natural gas prices at “just and reasonable” rates
under the Natural Gas Act. 15 U.S.C. §§ 717-717w (1982). Because of the shortage, pipeline
and utility company purchasers agreed to take-or-pay provisions in gas purchase contracts to
entice producers to dedicate their production. In 1978, the Congress enacted the Natural Gas
Policy Act, 15 U.S.C. §§ 3301-3432 (1982), to stimulate production and development of gas.
The act worked by deregulating prices subject to price ceilings with higher ceilings for “new
gas” (as opposed to “old” gas or “difficult to produce gas”) in order to stimulate production
of new sources of supply. See Richard J. Pierce, Jr., Reconsidering the Roles of Regulation
and Competition in the Natural Gas Industry, 97 HARV. L. REV. 345 (1983). The result,
however, was a supply glut. When oversupply caused prices to fall, pipeline companies and
utilities refused to honor take or pay arrangements and refused to take gas at these higher
prices, since gas was widely available at lower prices. See Richard J. Pierce, Jr.,
Lessor/Lessee Relations in a Turbulent Gas Market, 38 INST. OIL & GAS L. & TAX’N 8-1, 8-4
(1987) [hereinafter, Turbulent Gas Market]. Under current market conditions, oil and gas
purchasers will usually purchase at spot prices. Unfavorable long-term contracts at
abovemarket prices protected some producers for a while but have now virtually disappeared. As
such, purchasers are not completely eliminating existing markets by refusing to purchase
46. See Energy Policy and Conservation Act of 1975, Pub. L. No. 94-163, §§ 1-552, 89
Stat. 871 (codified in 15, 42, and 50 U.S.C.) (controlling the weighted average price of first
sales of domestic crude oil through May 31, 1979); Crude Oil Windfall Profit Tax Act of
1980, I.R.C. §§ 4986-4998 (1980); see also Ligon, Crude Oil Pricing: Current Regulations
and the Shift to Decontrol, 31 INST. OIL & GAS L. & TAX’N 1, 19-20 (1980); Weaver, supra
note 8, at 1474-80 (1981).
47. See Part I, supra.
48. Swiss Oil Corp. v. Riggsby, 67 S.W.2d 30, 31 (Ky. 1993).
marketed from the premises.49 As such, the word “produce,” has come to
“mean something more than mere discovery of a trace of oil or gas, or the
discovery thereof in quantities so small as to render operation of the well
unprofitable. . . . ”50
The modern paying quantities formulation seems to have its roots in
Young v. Forest Oil Co.,51 an 1899 decision of the Supreme Court of
Pennsylvania. The plaintiff lessor claimed inter alia that the defendant
Forest Oil Company’s lease had expired for lack of production in paying
quantities. The court found for the defendant which had drilled five wells,
four of which produced oil at a time. The court stated:
If oil has not been found, and the prospects are not such that the
lessee is willing to incur the expense of a well (or a second or
subsequent well as the case may be), the stipulated condition for
the termination of the lease has occurred . . . . But if a well,
being down, pays a profit, even a small one, over the operating
expenses, it is producing in “paying quantities,” though it may
never repay its costs, and the operation as a whole may result in
a loss . . . . The phrase, “paying quantities,” therefore is to be
construed with reference to the operator, and by his judgment
when exercised in good faith.52
This excerpt sets forth only one element for paying quantities with
respect to a lease where oil or gas has been found—that the well must pay a
profit over operating expenses; but in making that determination, the court
is to defer to the good faith subjective judgment of the lessee. This
conclusion, that the subjective good faith of the lessee is the focus under
Young, was bolstered by Colgan v. Forest Oil Co.,53 a decision issued by
the Pennsylvania Supreme Court on the same day it issued Young.54
This has not, however, been the universal interpretation of the Young
decision. In the recent case of T.W. Phillips Gas & Oil Co. v. Jedlicka,55 the
Supreme Court of Pennsylvania interpreted Young more than 110 years
after it was decided. The majority gleaned from Young a two-part test: (1)
whether the well pays a profit over operating costs, and if not (2) whether
the operator exercised in good faith his judgment to continue operations. If
either element is satisfied then the lease will be considered to produce in
paying quantities. But the court then grafted an objective reasonableness
test onto the second element, that whether the operator acted in good faith
depends on “the reasonableness of the time period during which the
operator continued his operation of the well in an effort to establish the
well’s profitability.”56 And the court implies that the second element, the
operator’s good faith, is more important than the first.57 Because the trial
court found that the operator acted in good faith, satisfying the second
element, there was no need to consider the first.58
In dissent, Justice Saylor also argued that Young required a substantially
similar test, but rather than an either/or test where paying quantities will be
found under either prong, his test would require both prongs, viz., the court
must find both that the well pays a profit and that the lessee acted in good
faith.59 Judge Saylor acknowledges, however, that one might rationally
dispute whether Young requires two elements or only subjective good
Taking a step back, almost 90 years before T.W. Phillips was decided,
Young was cited approvingly in the 1926 Oklahoma case of Gypsy Oil Co.
judgment on him, however erroneous it may deem his to be. Its right to interfere does not
arise until it has been shown clearly that he is not acting in good faith on his business
judgment, but fraudulently, with intent to obtain a dishonest advantage over the other party
to the contract.” Id. at 121.
55. 42 A.3d 261 (Pa. 2012).
56. Id. at 276.
57. Id. at 277 (“As explained above, pursuant to Young, the operator’s good faith
judgment is the principal focus in determining whether a lease has produced in paying
58. Id. at 278.
59. Id. at 283 (Saylor, J. dissenting).
60. Id. at 287 (Saylor, J. dissenting).
Then in 1942
both Young and Gypsy were cited by the Texas
Supreme Court in Garcia v. King.62
In Gypsy, the parties both argued as to the equities, but the court thought
the “only question to be considered is whether or not the Gypsy Oil
Company discovered oil in paying quantities within the life of the lease.”63
Applying the Young test, the lessee’s claim that it had discovered oil in
paying quantities was not made in good faith where the sole well on the
property could only be operated at a loss.64 Although the court reviewed the
past performance of the well, the court’s statement as to the test was
forward-looking: “Will the production of the oil discovered during the life
of the lease [primary term] yield the Oil Company a profit, though small,
over operating expenses?”65
In Garcia, the wells were producing in paying quantities from shallow
sands when the leases were executed. The lessees thereafter abandoned the
shallow producing wells, unsuccessfully explored the deeper sands, and
then began to drill shallow wells again. The revenue from the wells was
barely sufficient to pay the contract operator for his labor and it was clear
that production was not in paying quantities when the primary term
expired.66 The Garcia court quotes from Gypsy the same test announced in
Young that a well must pay a small profit over operating expenses, even
though the well may prove unprofitable, and that “[o]rdinarily, the phrase is
to be construed with reference to the operator, and by his judgment when
exercised in good faith.”67 The court then states in conclusion:
It should be noted that we are dealing with a situation in which,
under normal conditions, all of the producing wells on the lease
in question at the time of the termination of the primary period
were not producing enough oil or gas to pay a profit over and
above the cost of operating the wells . . . . So far as the lessees
were concerned, the object in providing for a continuation of the
lease for an indefinite time after the expiration of the primary
period, was to allow the lessees to reap the full fruits of the
61. 248 P. 329, 334 (Okla. 1926) (citing Lowther Oil Co. v. Miller-Sibley Oil Co., 44
S.E. 433 (W. Va. 1903); Aycock v. Paraffine Oil Co, 210 S.W. 851 (Tex. Civ. App.—
62. 164 S.W.2d 509 (Tex. 1942).
63. Gypsy, 248 P. at 334.
66. Garcia, 164 S.W.2d at 510.
67. Id. at 511-12.
investments made by them in developing the property.
Obviously, if the lease could no longer be operated at a profit,
there were no fruits for them to reap. The lessors should not be
required to suffer a continuation of the lease after the expiration
of the primary period merely for speculation purposes on the part
of the lessees.68
The conditions under which the lessee in Garcia attempted to produce
were not abnormal. The meager amount of revenue was all he could expect
to earn in the future and this was not enough to sustain the lease. Phrased
another way, the lessee was not acting in good faith but attempting to hold
the lease for speculation.
The Texas Supreme Court revisited Garcia in Clifton v. Koontz,69
probably the most influential case to date on paying quantities. The
petitioners claimed the well at issue operated at a loss between June 1955
and September 1956 but the lessee had begun reworking operations on
September 12, 1956 that proved wildly successful. Because the temporary
cessation clause allowed the lessee 60 days to commence reworking
operations after the cessation of production, the court found that the
relevant period should have been through July 12, 1956—60 days before
the reworking operations commenced—rather than September 1956.
After analyzing the relevant dates, the court defines “paying quantities,”
adopting the test from Garcia that if a well pays a profit over operating
expenses the well produces in paying quantities. The court, however,
completely omits any reference to the good faith of the operator,
substituting in its place an objective reasonableness standard. The court
In the case of a marginal well, such as we have here, the standard
by which paying quantities is determined is whether or not under
all the relevant circumstances a reasonably prudent operator
would, for the purpose of making a profit and not merely for
speculation, continue to operate a well in the manner in which
the well in question was operated.70
After the court announces this new “reasonably prudent operator”
standard, it states that the trial court must take into account “all matter
which would influence a reasonable and prudent operator,” then lists
68. Id. at 512-13 (emphasis added).
69. 325 S.W.2d 684 (Tex. 1959).
70. Id. at 691.
“some” of the factors that may be relevant, including the price for which the
lessee may sell his product, also the depletion of the reservoir, a reasonable
period of time under the circumstances, and whether the lessee is holding
the lease for speculation.71 Again, the lessee’s net profit is only one of the
factors to be considered.72 The court then restates the test as “[w]hether
there is a reasonable basis for the expectation of profitable returns . . . .”73
Rather than consider all of these factors, however, the court relies solely
on the evidence before the trial court as to profit and loss figures. The court
never expressly ties the accounting performance of the well to the
reasonably prudent operator standard that it announced, and never discusses
the expectations for future profits. Presumably the court must have believed
that where past performance indicates a clear profit a reasonably prudent
operator would continue to operate the well. Or maybe because the lessee
so clearly complied with the express terms of the lease, a complete analysis
under the standard was unnecessary.
Further, according to the express holding of the court, the “reasonably
prudent operator” standard applies only in the case of a marginal well,
which is “[a] well incapable of production except by artificial lift (pumping,
gas lift or other means of artificial lift) and when so equipped, capable of
producing only a limited amount of oil.”74 But what if the facts involve a
well or multiple wells on a lease that are capable of producing vast amounts
of oil or gas but because of circumstances that are not “normal” to quote
Garcia, the well is not currently producing at a profit? Although past
performance might be indicative of future performance it might not be. In
that case, might we still consider the good faith of the operator as seemingly
mandated by Garcia?
Although the court in Koontz never really expands on the prudent
operator aspects of the paying quantities test, it has become an element unto
itself. In Pshigoda v. Texaco, Inc.,75 the paying quantities analysis was
framed by the Texas appellate courts as a two part test: (1) whether the
lease pays a profit after deducting operating and marketing expenses over a
reasonable period of time, and (2) if not, whether a reasonably prudent
operator would continue to operate the lease for profit and not for
speculation. The Texas Supreme Court recently endorsed this approach in
73. Id. (emphasis added).
74. 8-M WILLIAMS & MEYERS, supra note 9, M Terms.
75. Pshigoda v. Texaco, Inc., 703 S.W.2d 416, 418 (Tex.App.—Amarillo 1986, writ
its 2017 opinion in BP American Production Company v. Laddex, Ltd.,
stating that Koontz required two prongs all along.76
Oklahoma has followed a different path since Gypsy. Oklahoma omits
the prudent operator standard and rather adds to the mathematical first
prong whether “compelling equitable considerations” will save a lease from
termination even though well operations are unprofitable.77 Some of these
considerations include the reasonableness of the period of cessation of
unprofitable production, the lessee’s diligence as operator, and whether the
cessation was voluntary.78
Some of the “equitable considerations” that have justified a cessation of
production have included the inability to market product without a
pipeline,79 ceasing to produce while resolving partnership differences,80 and
waiting for the passage of the Natural Gas Policy Act of 197881 which
might result in a price increase.82 An expected price increase alone,
however, is not a sufficient equitable consideration, at least without more
evidence than a mere “hope.” In Smith v. Marshall Oil Corporation,83 the
Oklahoma Supreme Court affirmed the trial court’s conclusion that a dearth
of equitable considerations existed in the case where the lessee testified, “I
produced them when I felt like producing them. And I turned them off
when I felt like turning them off.”84 The only justification offered by the
lessee was that he hoped oil and gas prices would rise, offering no factual
support other than his “hope.”85
That said, equitable considerations may apply in Oklahoma based on an
anticipated price increase, even though the prospect of the increase may be
remote, as long as the lessee can point to a reason to justify its hope.86 And
if the reason is sound, an operator should satisfy the second prong whether
the prong is grounded in equity or the Koontz “reasonable prudent operator”
76. 513 S.W.3d 476, 482-83 (Tex. 2017).
77. Smith v. Marshall Oil Corp., 85 P.3d 830, 834 (Okla. 2004); Barby, 648 P.2d at 17.
78. Smith, 85 P.3d at 834 (citing Hunter v. Clarkson, 428 P.2d 210, 212 (Okla. 1967);
Kerr v. Hillenberg, 373 P.2d 66, 69 (Okla. 1962)).
79. State ex rel. Comm’r of Land Office v. Carter Oil Co. of W. Va., 336 P.2d 1086,
1095-96 (Okla. 1958) (implied covenant case).
80. Cortner v. Warren, 330 P.2d 217 (Okla. 1958).
81. Act Nov. 9, 1978, 92 Stat. 157, 15 U.S.C. § 3301 et seq.
82. Barby, 648 P.2d at 17.
83. 85 P.3d 830 (Okla. 2004).
84. Id. at 835.
86. Barby, 648 P.2d at 17.
standard.87 In other words, if a “hope” is based on a reasonable justification
supported by evidence, then a court should allow anticipated future revenue
to count towards a well’s profitability. However, in the only case in
Oklahoma to approve the lessee’s waiting for a price increase as an
equitable consideration, the justifiable reason to wait actually occurred.
Congress passed the Natural Gas Policy Act and a price increase resulted
therefrom.88 Because hindsight is 20/20, we have no way of knowing
whether the case would have come out differently if the act was not passed
or the price did not increase.
In contrast to the above cases, the Kansas Supreme Court in Reese
Enterprises, Inc. v. Lawson89 expressly rejected the idea of a “subjective”
second prong in the test, refusing to consider either the good faith of the
lessee or what an objectively reasonable prudent operator would do. The
Kansas Supreme Court applies an approach that ignores economic
principles and considers only the mathematical computation.90 The court
If the lease ceased to be a profitable operation it would appear to
be to the interest of the lessee to abandon the project, and it
would appear to be unlikely that the lessee would have any
interest in continuing to operate at a loss. This conclusion,
however, does not take into account the very real factor that the
lessee may be interested in preserving his interest for speculative
Alternatively, of course, the lessee may have a sound basis to continue to
operate the lease based on a reasonable expectation of future profits. But for
the Reese court, “speculation” includes not only the lessee’s interest in
preserving a marginal operation in the hopes of making discoveries in other
formations, but also changes in marketing conditions or the market prices of
oil and gas.92 As discussed below, changes in market conditions or the price
87. Id. (quoting the testimony of a petroleum engineer when asked whether he would
have plugged the well or waited, answered, “Yes, I have an opinion. I believe a prudent
operator, my recommendation if I were ask would be to [sic] upon the passing of the law see
how it would affect the income for this unit or this well. I would continue in operation.”
(internal quotations omitted)).
88. Id. (“The fact that production income was received retroactively does not convert it
into something other than what it is, production income.”).
89. 553 P.2d 885 (Kan. 1976).
90. Id. at 897.
of oil or gas might be speculation or it might not, depending on the
diligence and sincerity of the lessee regarding its consideration of changing
conditions and how one defines the term “speculation.”93
III. Reexamining the Mathematical Prong
The first prong of the Koontz test, which requires the lessor to satisfy its
burden of proof that the lease does not pay a profit to the lessee after
deducting operating and marketing expenses over a reasonable period of
time, suffers from two intractable economic difficulties that will be
explored in this Part: (1) the transaction costs arising from the uncertainty
of the calculation that impede bargaining, and (2) the backward-looking
temporal nature of the test that results in the loss of aggregate profit
surpluses for the parties.
A. Transaction Costs and the Mathematic Prong
In the absence of development of the mineral interest there are no profits
for either the lessor or the lessee. But when a lessee and a lessor enter into
an oil and gas lease their intent is to create a cooperative surplus from the
bargain. The lessor stands to earn a surplus in the amount of the discounted
present value of its bonus, rentals, and royalties. If we assume a royalty rate
of 20%, then the lessee might earn a surplus as well, but only if the
discounted present value of its 80% share of the revenues from the lease
exceed the discounted cost of its initial investment, its exploration,
development and drilling costs, and its operating costs.94 In the absence of
uncertainty costs and transaction costs, lessees and lessors should be able to
handle their paying quantities disputes among themselves. If the influential
“Coase Theorem” is applied, then private bargaining will result in an
efficient allocation of resources.95
Assume, for example, a very clear rule for the paying quantities analysis.
Under this rule, a specified quantity of production is required by the end of
the primary term and the lessee must show an operating profit for the two
year accounting period that begins at the end of the primary term and ends
93. See supra notes 148-150 and accompanying text.
94. The discount rate will include a rate for the cost of capital and a rate for the risk.
The risk and the attendant discount rate will change over time as the lessee reevaluates the
risk of its investment when it obtains new information. See NICK ANTILL & ROBERT ARNOTT,
VALUING OIL AND GAS COMPANIES 136 (2000).
95. See Ronald H. Coase, The Problem of Social Cost, 3 J. LAW & ECON. 1, 15 (1960)
(arguing that rearrangement of legal rights through the market will result, but only assuming
costless market transactions).
two years later. Thereafter under the rule the lessee must show an operating
profit for each successive two year period. Further suppose that profits and
operating costs over any particular two-year period are easy for the lessee to
calculate because the parties have specifically negotiated how the amounts
are to be calculated. Also assume that bargaining costs between the parties
are zero and that other transaction costs, such as the cost of capital, are also
If the lessee obtains the required production by the end of the primary
term, but then determines towards the end of any two year accounting
period that its operating costs will exceed its revenue for that period, then it
has a decision to make. The lessee might decide to abandon the lease, in
which case the property will revert to the lessor without litigation. Or the
lessee might decide to bargain with the lessor. If the rule is clear and
operating profit is easy to calculate, then arguably there is no impediment to
bargaining. In that case, the lessee may be willing to pay the lessor for an
extension of the lease. The most efficient outcome is achieved.
The problem of course is that the parties do not negotiate clear formulas
for paying quantities. Presumably this is because the oil and gas industry
has determined that the costs of negotiating a clear paying quantities rule
would make the overall leasing process too costly in light of the risk.96
Because the parties fail to specify the terms for calculating paying
quantities, when a dispute arises the costs of negotiating a resolution are
high. Economists would say that when such transaction costs impede
bargaining, courts should remove impediments and lubricate bargaining by
96. In other mineral exploitation contexts, where the initial overall risk of the
transaction is perceived as being higher, the parties often attempt to negotiate the details of
revenue and expense calculations. Standard industry forms have made this process less
costly. For joint operations, the oil and gas industry relies heavily on a standard form joint
operating agreement. See AM. ASS’N PROF. LANDMEN, FORM 610-2015 JOINT OPERATING
AGREEMENT, available at http://www.landman.org/resources/forms-contracts (last visited
Mar. 22, 2017). The parties typically attach to the joint operating agreement a detailed
accounting procedure that has been developed by the Council of Petroleum Accountants
Societies. COUNCIL OF PETROLEUM ACCOUNTANTS SOCIETIES, MF-6 2005 ACCOUNTING PROC.
JOINT OPERATIONS, available at
http://www.copas.org/index.php/publications/model-formaccounting-procedures-mfs/mf-6-2005-accounting-procedure-joint-operations-from-formson-a-disk-detail (last visited Nov. 18, 2017). For mining joint ventures, the parties may
similarly use a standard form that contains detailed accounting procedures. See ROCKY
MOUNTAIN MINERAL LAW FOUNDATION, FORM 5 LLC: EXPLORATION, DEVELOPMENT AND
MINING LIMITED LIABILITY COMPANY (2015), available at http://www.rmmlf.org/
publications/forms-and-agreements/form-5-llc-single-license (last visited Mar. 22, 2017).
adopting a rule that will tend to lower transaction costs and provide more
certainty.97 The courts have not done this with paying quantities.
In particular, the mathematical first prong of the Koontz paying
quantities analysis is inherently elusive. Commentators and courts often
label this first prong as the “objective” prong and wrongly label the second
Koontz prong as the subjective prong,98 but the mathematical prong
arguably is the more unpredictable and subjective prong.
Disputes generally only arise as to the secondary term when the lease is
marginal. But when the lease is marginal the lessor will not have an
effective way to evaluate paying quantities until after it files suit because he
is not in possession of the relevant data.99 Unfortunately, the lessee too will
lack an effective means to ascertain before the end of litigation whether the
lease satisfies the mathematical prong. Consider just a few of the intractable
difficulties: the accounting period, lifting costs and depreciation, and
1. Accounting Period
The accounting period applied varies significantly from case to case and
is almost impossible to predict. The court in Barby v. Singer100 stated that
“the appropriate time period is not measured in days, weeks, or months, but
by a time appropriate under all of the facts and circumstances of each
case.”101 Unfortunately, this accounting period is selected by the litigators
ex-post, rather than by the parties ex ante. Although most courts would
agree in principal that profitability should be determined over a relatively
long period of time,102 the parties really have no idea how long is long or
whether the long period will include only unprofitable periods or both
profitable and unprofitable periods where the net result is a profit. Courts
have examined evidence and entertained claims for one month,103 fifteen
unprofitable months,104 one unprofitable year out of more than fifty
years,105 two unprofitable months out of fifteen,106 two years,107 and even
profits realized after the commencement of litigation.108
While courts eschew any specific accounting period as a matter of law,
someone ultimately picks an accounting period, be it a judge or a jury,
because that is what the test requires. For example, in the recent Texas
Supreme Court opinion issued in BP American Production Company v.
Laddex, Ltd.,109 the court rejected the plaintiff’s contention that the trial
court properly instructed the jury to consider only a fifteen-month
slowdown period and also rejected the defendant’s argument that as a
matter of law the jury should have been instructed to consider several
months before and after the slowdown.110 The court agreed with the court of
appeals (and Professors Smith and Weaver) that the jury must be allowed to
evaluate the cessation of paying production with no limit as to time taken
into consideration.111 The court says that “[n]arrowing the question on
paying production to any particular time period is necessarily
‘arbitrary.’”112 So rather than the court pick an arbitrary period, that task is
given to the jury. With no limit, there is no standard, meaning efficient
bargaining is virtually impossible.
2. Lifting Costs and Depreciation
Only lifting expenses (i.e. the operating costs to “lift” oil and gas to the
surface) and marketing expenses are considered in the calculation; drilling
and completion costs are not lifting expenses and thus are excluded.113 The
103. See id.
104. See BP Am. Prod. Co. v. Laddex, Ltd., 513 S.W.3d 476 (Tex. 2017) (rejecting 15
month period as arbitrary).
105. T.W. Phillips Gas & Oil Co. v. Jedlicka, 964 A.2d 13 (Pa. Super. Ct. 2008)
(concerning a claim based on one unprofitable year more than fifty years earlier rejected).
106. Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959) (holding that well was unprofitable
over 15 months but profitable over 13 months excluding months during reworking
107. Ross Expls., Inc. v. Freedom Energy, Inc., 8 S.W.3d 511 (Ark. 2000) (holding 24
month period reasonable).
108. Duerson v. Mills, 648 P.2d 1276 (Okla. Civ. App. 1982).
109. 513 S.W.3d 476 (Tex. 2017).
110. Id. at 484-85.
111. Id. at 485-86 (citing 1 ERNEST E. SMITH & JACQUELINE LANG WEAVER, TEXAS LAW
OF OIL & GAS § 4.4[a][b], at 4-40 (2009)).
112. Id. at 485 (internal citations omitted).
113. 3-6 WILLIAMS & MEYERS, supra note 9, § 604.6(b).
rationale for this rule is often stated that the lessee should be allowed to
operate a well to recover its drilling and completion costs. This dichotomy
makes economic sense. A lessee will continue to operate a lease as a
prudent operator for the benefit of both parties if it projects that its marginal
revenue will exceed its marginal costs. The costs of drilling and completion
are sunk costs and therefore do not enter into the lessee’s economic
decision to continue to operate after production is obtained.
Whether a cost is deducted, however, may depend on whether the court
views it as a recurring expense or a nonrecurring capital cost, which can be
an elusive distinction. The court in Pshigoda v. Texaco, Inc. held that
reworking expenses are not to be deducted because they are “analogous” to
drilling expenses in that they are one-time costs that the lessee ought to
have the opportunity to recover.114 Another court held that the recurring
costs of hauling saltwater away should be deducted, but the replacement
costs of converting an existing well to a saltwater disposal well should
not.115 The economic question, however, should not be whether a cost is
recurring or nonrecurring, but whether it would affect the decision of a
prudent operator in its decision to continue to operate the well.
As to depreciation, courts and commentators seem to agree that
depreciation of drilling and completion costs should be ignored,116 but
disagree how to handle depreciation of equipment used in “lifting”
operations. For example, in 1979, the Oklahoma Supreme Court adopted
the prevailing view that the original investment in the drilling of a well
should not be depreciated, but that depreciating equipment used in lifting
operations was proper because “production-related equipment does have
value that is being reduced through its continued operation.”117 But how
does one distinguish between original equipment and production-related
equipment?118 Casing, tubing, and Christmas trees are integral for lifting
114. 703 S.W.2d 418-19.
115. Lege v. Lea Expl., Inc., 631 So. 2d 716, 719 (La. Ct. App. 3d Cir. 1993).
116. See, e.g., Clifton v. Koontz, 325 S.W.2d 684, 692 (Tex. 1959).
117. Stewart v. Amerada Hess Corp., 604 P.2d 854, 857 (Okla. 1979). For a case that
confuses the treatment of depreciation, see Texaco, Inc. v. Fox, 618 P.2d 844, 849 (Kan.
1980), where the court expressly rejects the rationale of Stewart, then seemingly adopts its
rule that the direct costs of the initial cost of drilling and equipping the well and the
depreciation thereon are excluded.
118. To deal with equipment that is used in both drilling or completion operations and
production operations, Kuntz proposes first identifying drilling and completion costs and
then eliminating those costs from consideration in determining paying quantities. 2-26
EUGENE KUNTZ, A TREATISE ON THE LAW OF OIL & GAS § 26.7[l] (2016) [hereinafter,
product to the surface, and yet the Oklahoma Supreme Court concluded
these costs should not be depreciated.119 If reworking operations are
excluded as nonrecurring capital costs, should such costs not be
depreciated? The rationale in Pshigoda that the lessee ought to be able to
recover these nonrecurring costs would seem to argue against depreciating
nonrecurring costs, but there seems to be no economic reason to distinguish
between equipment costs and other nonrecurring expenses where
depreciation is concerned. Both are capital costs and both may or may not
affect the decision whether a reasonable prudent operator would continue to
operate the well.
Further, once depreciation is held to apply, in what manner is it
determined? Some have applied accounting120 or tax depreciation,121 while
the prevailing view seems to endorse “actual” depreciation.122 No method,
however, has been accepted for calculating actual depreciation. To the
detriment of certainty, the courts seem reluctant to endorse any particular
method at all, although courts sometimes note the arduous burden of the
lessor to show actual depreciation.123 Using actual depreciation would seem
to require an appraisal of the value of the equipment at the beginning and
end of the undefined accounting period to determine the loss in the value of
119. Mason v. Ladd Petroleum Corp., 630 P.2d 1283, 1286 (Okla. 1981).
120. In Stewart v. Amerada Hess Corp., 604 P.2d 854 (Okla. 1979), the court stated,
“The base and the period of depreciation should be determined by reference to currently
prevailing accounting standards.” Id. at 858-59.
121. See, e.g., Underwood v. Texaco, Inc., 590 F. Supp. 289, 289 (W.D. Okla. 1981)
122. See Bales v. Delhi-Taylor Oil Corp., 362 S.W. 388, 392 (Tex. Civ. App.—San
Antonio 1962, writ denied) (appellants failed to establish depreciation as a matter of law
because testimony related to bookkeeping entry rather than actual depreciation); Edwin M.
Cage, Production in Paying Quantities: Technical Problems Involved, 10 INST. OIL & GAS L.
& TAX’N 61, 90 (1959) (“[T]he bookkeeping entry of depreciation is in no sense an
‘out-ofpocket’ lifting expense and it should never be included as an item to be deducted from
revenue to determine whether a lease is still producing in paying quantities.”).
123. “There is a possibility, however, that the lessor in a carefully prepared case could
establish ‘actual depreciation’ (as distinguished from the bookkeeping entry) as a legitimate
charge to lifting expense. For example, in a pumping well the lessee may be using some
equipment which has been ‘written off’ completely and on which lessee is no longer taking
any depreciation. Still that piece of equipment may have a current salvage value. To some
extent continued operations are wearing out that equipment and reducing its salvage value.
The proof may be difficult and the reduction in value may be slight, but the fact remains that
there is ‘physical depreciation’ which is properly chargeable to lifting expense.” Evans v.
Gulf Oil Corp., 840 S.W.2d 500, 505 (Tex. App.—Corpus Christi 1992, writ denied).
the equipment.124 Alternatively, actual depreciation might be calculated as
the fair rental value of the equipment attributable to the lease while used in
lifting operations.125 Because there is no way to know in advance the
accounting period, however, there is no way to conduct ex ante such an
appraisal or to calculate the fair rental value. Accounting or “book”
depreciation would certainly be easier to calculate, but bears little relation
to the actual cost of operations.
Overhead is equally precarious. Arguably, the portion of overhead that is
attributable to lifting and marketing production is an applicable operating
cost and should be allocated to the lease.126 In fact, a few courts and
commentators postulate that the lessee has less of a case for excluding
overhead than it does for excluding depreciation.127 While courts and
commentators seem to agree that overhead that is remotely related to the
operation should not be allocated or considered,128 they do not agree as to
the categories of overhead that should be deducted or explain just how
remote overhead must be to exclude it. Some have asserted that an
overhead allocation paid to a third party operator should be deducted, but
costs incurred by the lessee itself should not.129 But is not a cost a cost?
The Oklahoma Supreme Court has ruled that indirect expenses, such as
“the cost of accounting, interest, postage, office supplies, telephone,
depreciation of office equipment, and all the other indirect expenses of the
124. This approach would be consistent with the damages available when chattels are
harmed in tort where there has not been a complete destruction in value. See RESTATEMENT
(SECOND) OF TORTS § 928 (Am. Law Inst. 1979).
125. Similarly, in tort the “rental value of property is the exchange value of the use of the
property.” Id. § 911(2).
126. See Richard D. Kolijack, Jr., Determination of Paying Quantities: An Accounting
Perspective, 18 TULSA L.J. 475, 485 (1983).
127. See Skelly Oil Co. v. Archer, 356 S.W.2d 774, 781 (Tex. 1961) (citing Cage, supra
note 122 (omitting references)). The court actually misapplies Mr. Cage’s analysis. Mr. Cage
does state that overhead is more difficult to “explain away” than depreciation, Cage, supra
note 122, at 91, but also argues that only “items which can be traced to direct lifting expense,
even though carried on the books as overhead, are legitimate charges.” Id. at 94. In Skelly,
the court states that only “those items of overhead charges which can be traceable to the
actual expense of production . . . should be considered in determining whether or not the
well is producing in paying quantities,” but then allows the allocation of district expenses on
a per well basis. 356 S.W.2d at 781.
128. See, e.g., Mason, 630 P.2d at 1285.
129. Menoah Petroleum, Inc. v. McKinney, 545 So. 2d 1216, 1221 (La. App. Ct. 1989).
oil company” should be excluded.130 The same court also held that district
expenses, i.e., the costs of a district office, should be excluded as simply a
“corporate convenience or necessity” and that to include such expenses
would “lead to the absurdity of determining a well to be a non-producer in
the hands of a corporate giant, yet a producer in the hands of a single
leaseholder owner-operator who is unfettered by such attendant
complexities.”131 Professor Kuntz, in contrast, would allow district and
camp expenses.132 He and others, however, would exclude an overhead cost
that would still be incurred in the absence of the lease.133
If the objective mathematical calculation is to be faithfully applied, it is
not clear why a large corporation with high district office costs should be
allowed to avoid overhead allocations simply because their offices are a
convenience. Similarly, the distinction between a cost billed by a third party
operator and a cost incurred directly by the lessee itself are without an
economic difference. From an economic perspective, the lessee should be
charged with overhead to the extent it is required to increase or maintain
production. In other words, overhead that is a marginal cost of one
additional unit of production should be deducted because those are the costs
that the lessee will consider when it decides whether to continue to operate
the lease. If the lessee must hire an additional accountant or marketing
executive to continue to operate a specific lease, then that is a marginal
cost. I realize this test will exclude most overhead allocations, including
most district office costs, but the mathematic prong, if applied at all (which
I argue in Part IV should not be applied), should examine whether a lessee
would continue to operate a lease, not whether a lessee would continue to
operate an oil company.
B. Backward-Looking or Forward-Looking
In my example in Part III.A of the hypothetical habendum clause that
clearly defines the parties’ rights, whether the lessee will negotiate for an
extension of the lease and how much it is willing to pay will be based
entirely on future expectations, not past results. This is not to say past
results will be irrelevant to the lessee, but only to the extent those past
130. Mason, 630 P.2d at 1286.
132. 2-26 KUNTZ, supra note 118, § 26.7[m].
133. Id.; see also Ladd Petroleum Corp. v. Eagle Oil & Gas Co., 695 S.W.2d 99, 108
(Tex. App.—Fort Worth 1985, writ ref’d n.r.e.).
results provide information about future projections.134 The lessee’s
anticipating drilling and completion costs informed the lease decision when
it was made, but not when a decision is made whether to seek an extension
because those costs are already sunk. Rather the lessee would examine the
present value of its projected future revenue stream less the present value of
its projected future operating costs.135 If the amount is positive and provides
a reasonable return to the lessee, then the difference is the maximum value
the lessee should be willing to pay for a lease extension. If the lessor’s
internal value of the lease extension is less than the maximum the lessee is
willing to pay, then a bargain will be struck. If not, then the lease should
C. The Costs of Uncertainty
Of all of the risks in the calculation previously discussed, perhaps the
most troubling when the market turns south is the lack of a set accounting
period. Without a predictable period, a lessee cannot analyze if it should or
should not hold on to a lease that begins to operate at a loss after a price
drop. Bargaining becomes extremely risky for the lessee when it has no
assurance that a judge or jury will view the appropriate accounting period
as the lessee sees the period. In comparison, it is not particularly risky for
the lessor to attempt to extract additional rents from the lessee by seeking to
cancel a lease, particularly if a new lessee or top lessee is willing to finance
the litigation. In this sense, the lessee may be deserving of some protection
for its investment.
Economists have postulated a corollary to the Coase Theorem,136 that
when transaction costs are high, the allocation of property rights under law
should determine the most efficient use of resources. As Coase stated:
Of course, if market transactions were costless, all that matters
(questions of equity apart) is that the rights of the various parties
should be well-defined and the result of legal actions easy to
forecast. But as we have seen, the situation is quite different
when market transactions are so costly as to make it difficult to
change the arrangement of rights established by the law. In such
134. ANTILL & ARNOTT, supra note 94, at 83 (“Moreover, for an economist, once a sum
of money has been spent, it becomes irrelevant, except to the extent to which it may impact
on the future. Evaluation is solely concerned with the future. (This is not to suggest that
history does not influence expectations of the future; clearly, it does.)”).
135. COOTER & ULEN, supra note 97, at 42 (theory of asset value pricing).
136. See supra note 95 and accompanying text.
cases, the courts directly influence economic activity. It would
therefore seem desirable that the courts should understand the
economic consequences of their decisions and should, insofar as
this is possible without creating too much uncertainty about the
legal position itself, take these consequences into account when
making their decisions. Even when it is possible to change the
legal delimitation of rights through market transactions, it is
obviously desirable to reduce the need for such transactions and
thus reduce the employment of resources in carrying them out.137
Replacing or renegotiating the standard habendum clause is the type of
market transaction where the costs are high and courts strongly influence
economic activity. While courts should no doubt consider the economic
implications of their paying quantities analyses on the lessor, who should
not be denied royalties for an unreasonable time period, should they not
also consider the implications of their decisions on the cooperative surplus
and on the U.S. oil and gas market more broadly?
What may have been a reasonable time during a boom market will not
necessarily be a reasonable time during a prolonged market downturn.
Although the parties could have negotiated ex ante for longer periods of
time to take into account the potential for market downturns, this assumes
perfect information. If the courts adhere to shorter accounting periods more
appropriate for better markets, then they are allocating the transaction costs
associated with the lack of perfect information to the lessee. Although the
lessee clearly has superior information about drilling prospects, their own
capabilities and risk tolerances, and even the price of oil during periods of
relative stability,138 there is little reason to believe lessees can predict
dramatic changes in prices that result from rebalancing supply and demand
after a disruption to the market.139
137. Coase, supra note 95, at 19.
138. Oil companies have developed a number of tools to evaluate price scenarios which
can identify trends over time. See ANTILL & ARNOTT, supra note 94, at 28-31. And yet the
market can still be highly volatile and unpredictable.
139. See U.S. Energy Info. Admin., What Drives Crude Oil Prices?, EIA,
http://www.eia.gov/finance/markets/crudeoil/spot_prices.php (last visited Sept. 10, 2017)
(“Both crude oil and petroleum product prices can be affected by events that have the
potential to disrupt the flow of oil and products to market, including geopolitical and
weather-related developments. These types of events may lead to actual disruptions or create
uncertainty about future supply or demand, which can lead to higher volatility in prices. . . .
Under such conditions, a large price change can be necessary to re-balance physical supply
and demand following a shock to the system.”).
The predictable result of this allocation of information costs is that a
large number of leases will change hands. During a downturn, lessors and
lessees that negotiate new leases would be expected to agree to lower lease
consideration than in a high price market because the expected present
value of the revenue stream will be lower.140 This lower consideration
might be in the form of lower bonuses and rentals, but it might also be in
the form of longer periods of time in which to produce or maintain
production in paying quantities. In either case, there will always be market
participants willing to pay depressed prices for top leases or new leases.
During boom times, lessors earn their contractual royalties under existing
leases. When the market falls, however, under the backwards-looking
mathematical paying quantities test some lessors will be allowed to cancel
their leases. These lessors might either re-lease when the market recovers or
they might negotiate for a lower bonus with a new lessee under continuing
poor conditions. Either way, if the first bonus paid by the original lessee
under good market conditions was $1,000 per acre, and the second bonus
paid by the new lessee under current poor conditions is $200 per acre, the
lessor has been paid $200 more than it would have received if the original
lease was allowed to continue. Or the former lessor that now once again
holds the fee interest might decide to operate the lease herself so that she
receives 100% of the production. In this respect, the speculators are not the
lessees whose leases have been cancelled; they are the lessors. The market
as a whole has suffered a loss of $200 that it would not have suffered if the
original lease were allowed to remain in effect.
Although the lessor in this scenario will receive what might be
characterized as a windfall, lease cancellations cost the industry and the
larger society and, in the long run, lessors will likely be worse off.
Commentators have variously argued for and against broader public
policy considerations when courts interpret leases.141 Those considerations
140. An exception is a market that provides short-term profits despite the lower price
projections. To expand and grow, or to survive, oil producers have flocked to the Permian
Basin because of its low cost to produce. As a result, the market for leases in the Permian
has arguably improved during the downturn because it is one of the few U.S. formations that
can still be produced with acceptable margins.
141. See, e.g., Weaver, supra note 8, at 1491-92 (“Given the importance of oil and gas to
the maintenance of our daily lives, the temptation to rely on public policy in making
decisions may be virtually irresistible. If so, a clear danger exists that the law of implied
covenants will become as unpredictable and irreconcilable as the energy policy that it
mirrors.”). Professor Weaver criticizes Williams & Meyers for their argument that public
policy supports exploration and development under implied covenants, see 5-8 WILLIAMS &
MEYERS, supra note 9, § 847, and Professor Patrick Martin for his argument that public
are outside the scope of this article. When I refer to the economic
implications on the broader society, I simply argue that, in general terms,
allowing an existing lessee to hold a lease during an economic downturn
benefits lessors in the long run and society in general so long as the lessee
is acting as a reasonable prudent operator—regardless of the outcome of
any mechanical accounting calculation.
The existing lessee may have incurred significant costs for air, water, and
waste permits, drilling and spacing orders, exploration, site development,
drilling, casing, cementing, completion, tanks, heater-treaters, gathering
equipment and arrangements, transportation arrangements, surface use
arrangements, treating and processing arrangements, and other marketing
arrangements. When the lease is in effect, these are assets in the hands of
the lessee. But when a lease is cancelled, the value of these assets is
reduced to whatever amount the lessee can salvage.
The new lessee or mineral owner must raise capital, reapply for permits
and orders, conduct at least some new exploration and planning, drill and
complete new wells, and negotiate its own arrangements for transportation,
processing, and marketing. Some of these costs may be lower for the new
lessee or mineral owner because they will be allowed to free ride off of
some of the work of the original lessee. But many of these costs will be
Duplicative costs, including the duplicative payments to lessors, raise the
overall cost of production. They may seem insignificant in an individual
case, but they multiply when applied across the industry. Any large increase
in the cost to produce will cause the domestic production of oil to fall. If
demand remains unchanged, consumers will simply switch to foreign
sources of supply, which harms not only the U.S. oil and gas industry but
the economy generally.
Similarly, although natural gas prices largely are determined by North
American supply and demand, natural gas competes with coal and
renewables, which are substitutes. If the cost to produce natural gas rises,
supply will decrease and the price will rise, causing electricity providers to
switch to coal and renewables. In either case, the domestic industry will
produce less, decreasing the wealth of both U.S. producers and U.S. lessors.
In the absence of transaction costs, the lessor would be better off by
sticking with the original lessee. As discussed in our previous example, the
policy in favor of conservation may support slower development. See Patrick H. Martin, A
Modern Look at Implied Covenants to Explore, Develop, and Market Under Mineral Leases,
27 INST. OIL & GAS L. & TAX’N 177 (1976); Weaver, supra note 8, at 1488-89.
existing lessee would pay for an extension if the difference between the
present value of its expected future revenue would exceed the present value
of its expected future operating costs. In contrast, a new lessee must cover
the present value of its drilling, completion, and operating costs for its
investment to be profitable. As such, the existing lessee should be willing to
pay more for an extension than a new lessee would be willing to pay for a
new lease. A new lessee may also be unlikely to drill for as long as possible
under the primary term of its new lease while it waits out the down market.
IV. Reformulating Paying Quantities
As discussed above, for property law purposes, the habendum clause
requires actual production (or in Oklahoma the capability of production)
before the expiration of the primary term.142 It is clear, therefore, that a
commercial discovery needs to have been made or the lease needs to be
producing something to save the lease. But once this requirement has been
satisfied, economics argues for a different paying quantities analysis. As
discussed above, the mathematic prong of the paying quantities analysis is
complex and uncertain, creates unnecessary economic costs, and does
properly account for the mutual interests of the lessor and the lessee in light
of their property rights, particularly during a down market. As such, I
propose its elimination.
The only relevant question for the determination of paying quantities
should be whether the lessee continues to hold the lease for the purpose of
making a profit and not merely for speculation. In Oklahoma, this test
would be a test in equity, and would essentially ask whether it is equitable
or not to cause a forfeiture of the lease taking into account the facts and
circumstances. The two-part test would thus collapse into a test focused
exclusively on the second Koontz prong (or the equitable prong in
Oklahoma) that should be applied during any market, with considerable
discretion afforded to the lessee as to whether the lease is being held for a
Recall that the Koontz test and the good faith test recently adopted in
Pennsylvania are couched as either/or tests. If the prudent operator would
continue to hold the lease for the purpose of making a profit and not for
speculation, the lessee will be allowed to hold the lease even though the
lease was unprofitable during a past period. Thomas Battle argued that “if a
lessee would reasonably believe in periods of low takes and depressed
142. See supra notes 29-32 and accompanying text.
prices that demand will likely increase and prices will likely rise to the
point that the lease will be profitable, the [second part of the Koontz test]
would be passed.”143 Similarly, Williams and Meyers argues that if a lease
would pay a profit under normal conditions, then so long as the lessee acts
in good faith as to whether he can better himself financially by holding the
lease during a period of depressed prices, then the court should essentially
defer to the lessee and allow the lessee to continue to hold the lease.144
Good faith alone, however, is not sufficient to protect the interests of the
In fact, the second prong of the Koontz test itself contains two parts.
Although part of a single prong, reasonable operation and speculation are
conjunctive. Both are required and they are certainly not correlative pairs.
To give meaning to these two clauses, my proposed single-pronged test
would have two components. It would ask both (1) whether a reasonable
prudent operator would continue to operate the lease, and (2) whether the
lessee at issue continues to hold the lease to operate for profit in good faith.
Although Williams and Meyers argued for consideration of good faith in the
143. Thomas P. Battle, Lease Maintenance in the Face of Curtailed/Depressed Markets,
32 ROCKY MTN. MIN. L. INST. 14-1 (1986).
144. “The lessee has a fairly strong argument for holding the lease by nonpaying
production during a period when temporary depression prevents paying production. Clearly
the lessee is not holding the land merely for speculative purposes, since under normal
conditions the lease is presently producing in paying quantities. If the lessor is receiving a
financial benefit from production, and if present production under normal conditions would
be in paying quantities, and if the lessee in good faith decides that he can better himself
financially in the long run from production at the present rate, the better rule would seem to
be to allow the lessee to continue to hold the lease, despite a current loss due to depressed
market conditions. Such a rule would not only avoid conflict with the policy against holding
leases for purely speculative purposes, but in periods of sharp depression in the oil and gas
industry, it would provide essential relief to all operators.” 3-6 WILLIAMS & MEYERS, supra
note 9, § 604.
145. Part of the difficulty with the standard of good faith rests with its definition. If it is
defined as only refraining from fraudulent conduct, then it will not be sufficient to meet the
objectives under the lease of mutual cooperation. 5-8 WILLIAMS & MEYERS § 806
(deficiencies of good faith standard in context of implied covenants). But the Restatement of
Contracts defines the concept more broadly to emphasize “faithfulness to an agreed common
purpose and consistency with the justified expectations of the other party . . . .”
RESTATEMENT (SECOND) OF CONTRACTS § 205 cmt. A (Am. Law Inst. 1979). In addition to
fraud and unconscionability, Black’s Law Dictionary also requires “(1) honesty in belief or
purpose, (2) faithfulness to one’s duty or obligation, [and] (3) observance of reasonable
commercial standards of fair dealing in a given trade or business . . . .” Good Faith, BLACK’S
LAW DICTIONARY (10th ed. 2014).
context of a down market,146 there is no reason to consider subjective good
faith only during down markets or to adopt a rule that would not be equally
applicable in both good and bad markets.
The word “speculation” in the second prong of the Koontz test connotes
a measure of subjective good faith even if not so stated. Has the lessee
carefully examined market conditions, the cost structure, and other
projected future events, to determine whether to shut in or operate the lease
at a loss? Or is the lessee continuing to hold the lease without any basis? As
Professor David Pierce has noted, “facts relevant to determining whether
the lessee owning the lease is improperly holding it for speculative
purposes is a much more individualized inquiry”147 than what the
hypothetical risk taker might do.
But a standard dictionary definition of speculation arguably is too broad.
Consider Professor Richard Pierce’s examination of the word “speculation”
in the context of the habendum clause. He argued that courts seem to
sanction many activities that are speculation under a dictionary definition,
which might include “the faculty, art, process or production of intellectual
examination or search.”148 Presumably, as he argues, courts have in mind a
more pejorative definition of speculation, such as “conjecture” or
“guesswork.”149 He concludes that courts have recognized the need for
lessee decisions about expected future events which is admirable behavior
and should not be considered speculation under the test. He states:
When a lessee is able to show a reasoned basis for an
expectation of production in paying quantities in the foreseeable
future because of expected changes in regulatory or market
conditions, a court should hold that the lease is capable of
producing in paying quantities.150
146. See supra note 144 and accompanying text.
147. David E. Pierce, Unresolved Implied Covenant to Develop and Paying Quantities
Issues: Defining Prudent Operator Obligations and Options During Good, and
Not-SoGood, Times, Paper Presented at Eugene Kuntz Conference on Natural Resources Law and
Policy, at 13 (2015) (on file with author).
148. Turbulent Gas Market, supra note 45, at 8-13.
150. Id. at 8-14; see also Weaver, supra note 8, at 1500 (arguing in the context of
statutory price schedules and market shortages that a lessee who waits to drill may be
speculating, but that a prudent operator might do the same thing).
Based on this argument, a distinction should be drawn between
permissible and impermissible speculation in the context of paying
Yet on the other side, a rule that does not consider subjective good faith
would allow the hypothetical prudent lessee to hold a lease indefinitely
even though the actual lessee involved in the case is incapable of operating
the lease for a profit when the market recovers, either because of the
lessee’s lack of expertise or precarious financial position, or because the
lessee is actually holding the lease based on a hope or guesswork. Such
activity does not mutually benefit the lessor and the lessee, which is the
overall purpose of the lease.152
Nevertheless, the two parts (reasonable prudent operator and good faith)
of my one prong test are necessarily inextricable. This is so because the
lessee should be allowed a degree of deference in determining whether a
reasonable prudent operator would continue to operate the lease. As
between the parties, the lessee is in a much better position to evaluate what
a prudent operator would or would not do.
The test may be an objective inquiry in the sense that it relates to what
the prudent operator would do, but what is “prudent” should to a great
extent depend on the lessee’s particular circumstances. When a lessee
makes business decisions as to a lease it will usually have a good sense or
the means to determine whether its operations are reasonable and prudent
under industry standards taking into account all of the applicable facts and
As Professor David Pierce has argued in the context of the implied
covenant to develop, courts rely on the profitability evidence submitted by
This reflects an individualized focus on what a particular lessee’s “sound economic judgment” yields given all the facts and
151. But see Gary B. Conine, Speculation, Prudent Operations, and the Economics of Oil
and Gas Law, 33 WASHBURN L.J. 670, 720 (1993-94) (arguing that the broad economic
definition of speculation, including delay until prices have made anticipated changes in
response to market factors, is part of the conduct targeted by the prudent operator standard).
Professor Conine, however, then proceeds to propose a modified test for the prudent
operator standard in the context of implied covenants that would require both an extensive
delay and an excessive aversion to risk. Id. at 742.
152. 2-26 KUNTZ, supra note 118, § 26.5 (“The view expressed is that the basic purpose
of the lease is to secure development of the property for the mutual benefit of the lessor and
lessee, and that the lessee should not be permitted to hold the lease for speculation.”).
153. Pierce, supra note 147, at 14.
circumstances. Competing evidence presented by the lessor will
either be designed to establish what a prudent operator would do
on the riskier outer limits of “sound economic judgment” or,
more appropriately, to try and establish a baseline or range from
which the lessee’s economic requirements can be measured.”154
In other words, a lessor tends to have a higher risk tolerance with the
lessee’s money than the lessee does.155 Professor Pierce further argues that
this disparity might be handled by looking at a range of reasonable
alternative projections. He explains that this range of acceptable cost
estimates can be analogized to the deferential standards that have been
articulated by the United States Supreme Court in public utility ratemaking
cases.156 Under these standards, the Supreme Court focuses on the “end
result” for the utility, recognizing that just and reasonable rates might fall
within a range that it terms the “zone of reasonableness.”157
Under this approach, a lessee that puts forth evidence that it continues to
hold the lease in good faith based on its profitability projections should
prevail so long as those projections fall within a reasonable range of
alternatives, even if that range is large. A lessee that takes the stand and
testifies, “I think prices will turn around,” without any other basis for
holding the lease is engaging in impermissible speculation. But a lessee
who has a good faith business reason to continue to hold the lease for
development should be entitled to a presumption that a reasonable prudent
operator would do the same so long as the lessee’s judgment is within the
zone of what a reasonable operator might do given the circumstances.
Courts are not oil and gas development experts and should not interfere
with the transactional structure created under the oil and gas lease that
allows the lessee to make development decisions. Because the lessee has
access to much better information as to the economic viability of a well and
to future markets, and because development decisions are within the
business judgment of the lessee, there should be a presumption that
154. Id. at 15.
155. See id. at 14 n.50 and accompanying text (quoting Apache Tribe v. Supron Energy
Corp., 479 F. Supp. 536, 546 (D.N.M. 1979) (“While the criteria established by defendants
concerning the economics of any particular individual well are admittedly conservative, the
speculative nature of the oil and gas business may in fact require that conservatism temper
and inform sound business decisions.”)).
156. Id. at 21.
157. Id. (citing Fed. Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591 (1944);
Permian Basin Area Rate Cases, 390 U.S. 747, 797 (1968)).
evidence put forth by the lessee as to the future economics of a lease are
valid absent strong evidence to the contrary.158
In a sense this is a business judgment rule standard akin to the corporate
law standard. The business judgment rule is both a rule of abstention and a
rule of non-liability, whereby a court refuses to second-guess the business
judgment of corporate directors in the absence of a showing of gross
negligence.159 The business judgment rule does not, however, protect a
decision that the plaintiff can show was uninformed,160 or if the plaintiff can
show that a board fails to make a decision altogether when a decision is
Admittedly, the corporate business judgment rule is not a perfect analogy
because it is a standard relating to liability, not the arrangement of property
rights. As such, a prudent operator standard, rather than a gross negligence
standard, is a more appropriate standard. For many of the same reasons
justifying the business judgment rule, however, a deferential standard
should apply to the prudent operator inquiry. As described above, the
prudent operator standard is a business judgment standard that takes into
account the lessee’s particular circumstances and the circumstances of the
market. When a court considers the lessee’s business judgment as to its
future plans and the market, the court should allow the lessee an extended
period of time, particularly during a down market, in which to recover its
Further, courts should avoid asking whether another particular lessee
might earn a higher profit than the current lessee or earn a profit more
quickly. In the corporate context, consideration of what another particular
158. This is not to say that the interests of the lessor and the lessee necessarily coincide.
On the contrary, their interests will often conflict. The lessee will naturally be more risk
averse because it bears no portion of the costs of development. 5-54 KUNTZ, supra note 118,
§ 54.2. But this article is not concerned with implied covenants to prevent drainage, further
develop, or explore where the disparity in risk aversion is great. The question at issue is
whether a prudent operator would continue to operate the well. That question is one of
business judgment that is not so severely tainted by the inherent conflict of interest between
the lessor and the lessee because the lessee has already incurred the sunk capital costs of
exploration and development and obtained production.
159. See Omnicare, Inc. v. NCS Healthcare, Inc., 818 A.2d 914 (Del. 2003); 3A
FLETCHER CYC. CORP. § 1036 (2016).
160. See Smith v. Van Gorkom, 488 A.2d 858 (Del. 1985) (overruled on other grounds);
Gantler v. Stephens, 965 A.2d 698 (Del. 2009); Hanson Tr. PLC v. ML SCM Acquisition,
Inc., 781 F.2d 264, 274 (2d Cir. 1986) (holding that duty of care requires reasonable
diligence in gathering and considering material information).
161. See Aronson v. Lewis, 473 A.2d 805, 813 (Del. 1984).
director might have done would be antithetical to board discretion.
Similarly, witness testimony presented by a lessor that a specific operator,
maybe one with a lower cost structure, would produce during a down
market or produce more profitably has little relevance, without more, to
whether the hypothetical prudent operator would continue to hold the lease
for a profit.
Finally, even though the mathematical prong should be eliminated, past
performance might still be relevant as tending to show the presence or
absence of good faith on the part of the lessee. A lessee who has failed to
operate the lease to produce a profit for a particular period during a good
market might be unwilling or unable to operate a lease after a downturn for
a profit or even to survive a downturn. “Fluctuations in the price of oil
might justify the lessees in ceasing operations for a reasonable time, but”
where “there has been no operation and no pumping of the wells to
demonstrate what the product of the wells might be[,]”162 then the lessee
undoubtedly is not entitled to hold the lease.
In many cases, however, the failure to operate at a profit for a period of
time will not establish bad faith or establish that a reasonable prudent
operator would not continue to hold the lease for a profit. For example,
reworking operations might be required to increase production to profitable
levels, and the lessee may have the necessary expertise and financing to
conduct those operations. In fact, the lessee may have considered
conducting the operations, but the operations may not be justified during
the current price environment.163 If the lessee makes such a determination in
good faith and a prudent operator would make the same determination,
there is no reason to strip the lessee of its lease.
The Koontz standard as originally stated by the Texas Supreme Court has
lost its way. It has evolved into a two-prong test that wrongly focuses on
past performance based on arbitrary and uncertain accounting calculations
rather than future projections. The paying quantities analysis will better
reflect the economics of oil and gas operating decisions and encourage
more efficient bargaining if the test is refocused on what a reasonable
162. Collins v. Mt. Pleasant Oil & Gas Co., 118 P. 54 (Kan. 1911).
163. See Weaver, supra note 8, at 1506 (stating in the context of implied covenants to
further develop and explore during the low price en
vironment of the 1980
s, that “a delay in
drilling for purposes of speculation in the new pricing context may no longer reflect the
lessee’s idle management of resources”).
prudent operator would do and whether the operator is acting in good
Lessees might initially react to the test proposed in this article by
complaining that the proposed test is less favorable to the lessee than the
current two-pronged approach. Under the current test the lessee
theoretically has two chances to save its lease—either because it has
operated at a profit in the past or because a prudent operator would continue
to operate for a future profit. This might theoretically be true, but by putting
the focus where it belongs, on future prospects rather than past results, a
prudent lessee who acts in good faith is more likely to avoid lease
cancellation during a prolonged period of unprofitable operations. And yet
there is no reason to allow a lessee to continue to hold a lease simply
because it has made a profit in the past over some arbitrary accounting
period. As articulated above, the relevant question is not what has occurred
in the past, but the prospects for the future.
164. Coase recognized that when courts use the word “reasonable” they often take into
account economic considerations. Coase, supra note 95, at 22 (“The courts do not always
refer very clearly to the economic problems posed by the cases brought before them but it
seems probable that in the interpretation of words and phrases like ‘reasonable’ . . . there is
some recognition, perhaps largely unconscious and certainly not very explicit, of the
economic aspects of the questions at issue.”).
I. Introduction ........................................................................................... 978
II. Paying Quantities ................................................................................. 981
A. The Habendum Clause..................................................................... 981
B. The Need for Production or Discovery............................................ 984
C. Production Means Production in Paying Quantities ........................ 985
D. Exceptions to the Requirement for Production................................ 985
E. Evolution of the Meaning of Paying Quantities............................... 987
III. Reexamining the Mathematical Prong................................................ 995
A. Transaction Costs and the Mathematic Prong ................................. 995 1 . Accounting Period........................................................................ 997 2 . Lifting Costs and Depreciation .................................................... 998 3 . Overhead .................................................................................... 1001
B. Backward-Looking or Forward-Looking....................................... 1002
C. The Costs of Uncertainty ............................................................... 1003
IV. Reformulating Paying Quantities...................................................... 1007
V. Conclusion ......................................................................................... 1013 6. See Heather Long, It's OPEC vs . Trump on Oil, CNN MONEY (Nov. 29 , 2016 , 5 : 09
PM) , http://money.cnn.com/ 2016 /11/29/news/economy/donald-trump - opec-oil/. 7. ENERGY OUTLOOK , supra note 3, at 3. 8. The other lease provision that has received the most scrutiny by commentators
Williams , Implied Covenants in Oil and Gas Leases: Some General Principles , 29 KAN. L.
REV. 153 ( 1981 ) ; Stephen F. Williams , Implied Covenants for Development and Exploration 27. 3-6 WILLIAMS & MEYERS, supra note 9, § 604.9 . 28. See infra Part II .D. 29. See , e.g., Stanolind Oil & Gas Co. v. Barnhill , 107 S.W.2d 746 (Tex . Civ. App .-
Amarillo 1937 , writ ref'd); Natural Gas Pipeline Co. of Am. v. Pool , 124 S.W.3d 188 , 192
(Tex . 2003 ); Baldwin v . Blue Stem Oil Co. , 189 P. 920 ( Kan . 1920 ). 30 . See , e.g., SUMMERS, supra note 11 , at 312 (citing J.W. Simonton , Extension of Term
of Oil Lease Through Discovery of Oil in Less Than Paying Quantities , 26 W. VA . L. Q. 79 ,
82 (“The rule that, where the parties have expressly covered a point, there can be no
implication ought to apply here as in other cases .”)) ; see also 3-6 WILLIAMS & MEYERS,
supra note 9, § 604 (interpretation that requires only discovery is contrary to the manifest
intent of the parties and not justified by equities , which are irrelevant) . 31 . Gard v. Kaiser , 582 P.2d 1311 , 1314 (Okla. 1978 ). 32. McVicker v. Horn, Robinson & Nathan, 322 P.2d 410 , 413 (Okla. 1958 ). 33. SUMMERS, supra note 11, at 316 . 34. See , e.g., Benedum-Trees Oil Co. v. Davis , 107 F.2d 981 , 985 ( 6th Cir . 1939 );
accord Garcia v. King , 164 S.W.2d 509 , 512 (Tex. 1942 ). 35 . See , e.g., Bryan v . Big Two Mile Gas Co., 577 S.E.2d 258 , 266 ( W. Va . 2001 ). 36 . See 3- 6 WILLIAMS & MEYERS, supra note 9, § 615 . 37. See , e.g., Watson v . Rochmill , 155 S.W.2d 783 , 784 (Tex. 1941 ) (stating that
the equipment used in connection therewith , or the like”) . 38 . See , e.g., Stimson v . Tarrant , 132 F.2d 363 ( 9th Cir . 1942 ). 39 . See Saulsberry v. Siefel , 252 S.W.2d 834 ( Ark . 1952 ). 40 . See , e.g., Reynolds v . McNeill , 236 S.W.2d 723 ( Ark . 1951 ). 41. A representative clause might provide, “If after the discovery of oil or gas the
lessee commences drilling or reworking operations within sixty (60) days thereafter or (if it
before the rental paying date (if any) next ensuing after thirty (30) days following the
cessation of production.” 3-6 WILLIAMS & MEYERS, supra note 9 , § 615 . 42. See , e.g., McCullough Oil , Inc. v. Rezek, 346 S.E. 2d 788 ( W. Va . 1986 ); Geo-
Western Petroleum Dev. , Inc. v. Mitchell, 717 S.W.2d 734 ( Tex. App .-Waco 1986 ); Hoyt
v. Continental Oil Co., 606 P.2d 560 , 563 - 64 (Okla. 1980 ); Greer v . Salmon , 479 P. 2d 294,
297 (N.M . 1970 ); Gulf Oil Corp . v. Reid, 337 S.W.2d 267 ( Tex . 1960 ). 43 . Id. at 270 . 44. See Tucker v. Hugoton Energy Corp ., 855 P. 2d 929 ( Kan . 1993 ). For an example of
and sets forth a broader list of events that justify shutting in a well, see Pierce , supra note 18,
at 812 n.105 . 49. Garcia v. King , 164 S.W.2d 509 , 512 (Tex. 1942 ) (quoting Bendum-Trees Oil Co . v.
Davis , 107 F.2d 981 , 985 ( 6th Cir . 1939 )). 50 . Gypsy Oil Co. v. Marsh, 248 P. 329 , 333 (Okla. 1926 ). A contrary holding was
reached in Illinois in Gillespie v . Ohio Oil Co., 102 N.E. 1043 ( Ill . 1913 ) and McGraw Oil &
Gas Co . v. Kennedy, 64 S.E. 1027 ( W. Va . 1909 ), that any production that is capable of
division is sufficient to constitute production . 51 . 45 A. 121 (Pa. 1899 ). 52 . Id. at 122-23 (emphasis added) . 53 . 45 A. 119 (Pa. 1899 ). 54 . The court in Colgan states, “So long as the lessee is acting in good faith on the
being able to conduct it in his own way. No court has any power to impose a different 97. The goal of courts to lubricate bargaining might be called the “normative Coase
theorem.” ROBERT COOTER & THOMAS ULEN , LAW & ECONOMICS 97 (5th ed. 2008 ). 98 . See T.W. Phillips Gas & Oil Co . v. Jedilicka, 42 A.3d 261 , 284 n.8 ( Pa . 2012 )
Primer on Oil and Gas Law in the Marcellus Shale States, 4 TEX . J. OIL, GAS , & ENERGY L.
155 , 161 - 62 ( 2008 -09)). 99 . Patrick S. Ottinger , Production in “Paying Quantities” -A Fresh Look , 65 LA. L.
REV. 635 , 644 - 45 ( 2005 ). 100 . 648 P. 2d 14 ( Okla . 1982 ). 101 . Id. at 16- 17 . 102 . See Transp . Oil Co. v. Exeter Oil Co., 191 P.2d 129 , 134 (Cal. Dist. Ct. App. 1948 ).