VOLUME 38, NUMBER 2 | WINTER 2014
OFFICERS
M.C. Cottingham Miles, Chair
300 Convent Street, Suite 2500
San Antonio, Texas 78205
(210) 220-1354
David M. Patton, Chair-Elect
3400 JPMorgan Chase Tower
600 Travis
Houston, Texas 77002
(713) 226-1254
Ricardo E. Morales, Vice-Chair
P.O. Box 6668
Laredo, Texas 78042
(956) 727-4441
Charles W. Gordon, Secretary
800 N. Shoreline Blvd., Suite 800
Corpus Christi, Texas 78401
(361) 880-5858
Peter E. Hosey, Treasurer
112 E. Pecan Street, Suite 2400
San Antonio, TX 78205
(210) 228-2423
Timothy R. Brown, Immediate Past Chair
1201 Lake Robbins Drive
The Woodlands, Texas 77380
(832) 636-7560
COUNCIL
TERMS EXPIRE 2014
Doug Dashiell, Austin
Kathleen E. Magruder, Houston
Mark C. Rodriguez, Houston
TERMS EXPIRE 2015
Prof. Owen Anderson. Oklahoma City
Michael D. Jones, Houston
Lisa Vaughn Lumley, Fort Worth
TERMS EXPIRE 2016
Chris Aycock, Midland
John Bowman, Houston
Mike McElroy, Austin
SECTION REPORT EDITOR
Doug Dashiell
Scott Douglass & McConnico LLP
600 Congress Ave, Suite 1500
Austin, TX 78701-3236
(512) 495-6300
[email protected]
Dr. Daniel Yergin Speaking at the
75th Anniversary Gala of the
Oil, Gas and Energy Resources Law Section
IN THIS ISSUE
Click on title to jump to page
Chair’s Message ........................................................................................................................ 4
By:
M.C. Cottingham Miles
San Antonio, Texas
Editor’s Message ........................................................................................................................ 6
By:
Doug Dashiell
Austin, Texas
The AAPL Operating Agreement and the Deadbeat Non-Operator ............................................. 7
By:
Paul G. Yale
Houston, Texas
Surface Use Agreements: Multijurisdictional Considerations in Negotiating
and Drafting Agreements for Use of Surface Estates in Oil and Gas
Exploration, Production and Development ................................................................................ 24
By:
Randall K. Sadler
D. Bradley Gibbs
Michael P. O’Connor
Michael A. Mulé
Travis Crawford
Brian T. Wittpenn
Austin W. Brister
Joseph “Joey” L. Breitenbach
Daniel Tyson
Houston, Texas
Recent Texas Oil and Gas Cases ............................................................................................. 66
By:
Richard F. Brown
Amarillo, Texas
Correction: In the Fall 2013 Section Report, one of the authors, Thomas R. Dixon, Jr. of
Amarillo was inadvertently omitted from this page of the report. Mr. Dixon co-authored
Pickering Your Poison – the Effects of Electronic Negotiations on Oil and Gas Agreements. We
apologize for that omission.
State Bar of Texas
Oil, Gas and Energy Resources Law Section’s
75th Anniversary Gala
Houston, Texas
October 3, 2013
i
CHAIR'S MESSAGE
The year 2013 was an exciting time for our Section as 2013 marked the 75th Anniversary
of the Oil, Gas and Energy Resources Law Section of the State Bar of Texas (the "Section"),
which was founded in 1938. The Section celebrated this milestone at the 75th Anniversary Gala
on October 3, 2013 in Houston, Texas with a keynote address by Dr. Daniel Yergin, Pulitzer
Prize winning author of The Prize and author of The Quest. Selected photographs from the Gala
that evening are included in this edition of the Section Report.
The year 2014 promises to be a busy and exciting time for oil and gas lawyers in Texas
as well. The fast pace of activity along with developments in exploration and production
techniques have brought with them new legal challenges and the need for practitioners to keep
up to speed with legal developments within the oil, gas and energy resources industry because
we practice in an area of law which includes two very important topics near and dear to all
Texans: (i) the State's natural resources, and (ii) our country's insatiable need for energy. To
this end, we hope that the continuing legal education courses offered by the Section and the
Section Report will keep our membership current so that we, as lawyers, may do our part to
provide a just and rational framework for these challenges to promote a better future for all
within the oil, gas and energy resources industry.
The Council is continuing to work to achieve its goals this year, including revamping and
improving the search engine for legal research on the Section website to better assist you, our
Section members. We also hope to have completed by the State Bar Annual Meeting in June
our analysis of the Section-wide survey completed last year so that we may determine how best
to serve you by recognizing the current needs of the Section membership. Finally, we are
expanding the size and scope of our Young Professionals Program throughout Texas to better
serve the younger members of our Section, having recently identified young energy lawyers in
Austin and San Antonio who want to help with the organization and start-up of this program in
these cities. Please let me or any other member of the Council know if you have an interest in
assisting with the Young Professionals Program.
The 40th Annual Ernest E. Smith Oil, Gas and Mineral Law Institute, co-sponsored by the
Section and the University of Texas School of Law CLE Program ("UTCLE"), will be held on
Friday, March 28, 2014, at the Royal Sonesta Hotel in Houston, Texas. The Fundamentals of
Oil, Gas and Mineral Law Course, featuring oil and gas law primer topics, will take place on the
preceding day, Thursday, March 27, 2014. The Fundamentals course is designed for the legal
practitioner who is new to, or is thinking of entering, the oil, gas and energy law practice, or for
the experienced practitioner who desires a refresher.
I always enjoy attending the
Fundamentals course, as I learn something new every time. We hope that these courses are
useful to our members who are able to attend as both Council Member Michael Jones, the
Course Director for the Institute, and Council Member Chris Aycock, the Course Director for the
Fundamentals course, along with their planning committee, have been busy booking quality
speakers to ensure stellar programs again this year. The Section also co-sponsored in January
with (i) UTCLE, the International Upstream Energy Transactions course, and the Renewal
Energy Institute, and (ii) the State Bar of Texas, the Environmental Impacts of Oil and Gas
Production course, continuing to offer high-quality programs for the Section membership
through these programs.
Later this month, you will be receiving in the mail a complimentary publication, Ernest E.
Smith Selected Works, a special project of the Texas Journal of Oil, Gas and Energy Law of the
University of Texas School of Law, co-sponsored by the Section. It is my expectation that this
iii
book will be located near your copy of the Selected Works of A. W. Walker, Jr., which was
sponsored by the Section in 2001, as the timeless writings of Professor Smith with respect to oil,
gas and mineral law, like the writings of A. W. Walker, Jr., are well known and often cited by
Texas courts. I hope you enjoy reading it.
All members of the Section are invited and encouraged to attend the Annual Meeting of
the Section, which will be held in conjunction with the State Bar Annual Meeting in Austin on
Friday, June 27, 2014, at the Austin Convention Center. We will elect officers and council
members for the coming year and present an overview of the Section’s activities for the 20132014 year and what to expect for the 2014-2015 year as well.
Thank you for your continued support of the Section, and if you have any questions or
comments regarding the Section, or suggestions to improve the Section and its member
services, I encourage you to contact me.
M. C. Cottingham "Cottie" Miles
iv
EDITOR’S MESSAGE
The 75th Anniversary Gala held October 3, 2013 provided a unique opportunity for the
section members to gather, share their experiences, and listen to an outstanding talk by Dr.
Daniel Yergin, the Pulitzer Prize winning author and preeminent expert on global energy
resources. The cover of this report features a photo of Dr. Yergin at the Gala. Some selected
photos from this memorable night are also shown in the report.
In this edition, I am pleased to include a very entertaining and practical article written by
Paul Yale of Houston entitled The AAPL Operating Agreement and the Deadbeat Non-Operator.
The problems Mr. Yale describes with non-operators, portrayed as the fictional character “Mr.
Green Leisure Suit” in the paper, are recurring problems. The tools he describes for operators
to address these problems are extremely useful and relevant. Thank you Paul for this fine work.
This edition also includes a very thorough treatment of surface use agreements entitled
Surface Use Agreements: Multijurisdictional Considerations in Negotiating and Drafting
Agreements for Use of Surface Estates in Oil and Gas Exploration, Production and
Development. This is the work of nine current or former attorneys with the Sadler Law Firm,
LLP, in Houston. The paper contains an excellent foundation of the legal principles governing
surface use agreements and, true to its name, addresses surface use and accommodation
developments in a variety of jurisdictions. Thanks to each of these authors for a very useful and
comprehensive paper.
Once again, Richard Brown of Amarillo has prepared his analysis of Recent Texas Oil
and Gas Cases. Richard continues to provide this valuable resource to the report and I
sincerely appreciate his dedication and recurring work.
In future reports, we will feature papers authored by several members of the current
council, and hope to provide the members with varied and practical topics that can be useful in
your practice. I once again invite any potential authors to consider offering your works in the
field of oil, gas, or other energy resources to submit papers to me for future publication.
Doug J. Dashiell
v
well known, wealthy, Houston businessman
which was a fact that I, having recently
moved to Colorado from Texas, was unduly
impressed by.
THE AAPL OPERATING AGREEMENT
AND THE DEADBEAT NON-OPERATOR 1
Paul G. Yale
Houston, Texas
I.
Mr. Green Leisure Suit told me that
he was in town to snow ski but wanted to
respond to my farmout request in person
while he was here. He then told me he
wanted to join in the wells, not farmout. I
explained to him that even a 10% interest
could cost him millions of dollars given how
expensive the wells were and the number of
them that Exxon planned to drill. I also
warned him about Exxon’s propensity at the
time for significant cost overruns. His
response was something like, “Not a
problem, I’m ready to run with the big dogs.
So let’s drill these suckers, where do I
sign?”
INTRODUCTION
“Mr. Green Leisure Suit,” as I will call
him, dropped in on me unexpectedly in my
Denver office where I was employed as a
near entry-level landman by a major oil
company (Exxon) in the early 1980s. The
passage of time has obscured some details,
but I recall most. He entered my office in a
pastel green, bell-bottomed leisure suit with
a gold puka shell necklace adorning his
well-tanned, very hairy chest. His girlfriend
was dressed in a tight fitting, memorably
scant outfit similar to what might be worn
today by a “Zumba” dance fitness instructor
in a women’s workout studio. Her attire was
certainly not business dress, even by
business casual dress standards to the
extent such standards existed in the early
1980s;
but
no
matter,
she
was
accompanying him for no apparent business
reason.
I then had my secretary prepare a
stack of authorities for expenditure (AFEs)
and signature pages to a Model Form
American Association of Professional
Landmen (AAPL) 610 Operating Agreement
(probably the 1977 version) all of which Mr.
Green
Leisure
Suit
enthusiastically
executed. The deal with Mr. Green Leisure
Suit
having
been
closed,
Exxon
commenced its exploration program. We
drilled six or seven dry holes in a row before
abandoning the play. There were significant
cost overruns. Mr. Green Leisure Suit’s final
share of costs was $2-3 million, a fair
amount of money today, even more so in
the early 1980s.
I had been assigned the task of
putting a lease play together in
Northeastern Colorado, in the same area
that today is seeing large scale horizontal
drilling and development in the Niobrara
formation. But this was long before
horizontal fracking had come of age, Exxon
wanted to drill vertical test wells, perhaps as
many as a dozen, at a drilling and
completion cost per well of several million
dollars. I had contacted “Mr. Green Leisure
Suit” for a farmout of his approximately 10%
leasehold position on the prospect. Mr.
Green Leisure Suit was the son of a very
A month or so after we shut the
program down, I was contacted by our
accounting department. As it turned out,
Exxon had billed Mr. Green Leisure Suit for
his share of costs, but he never paid
anything. I was asked to contact him about
the overdue bills. I tracked him down to a
hotel room in Las Vegas where the phone
was answered by a woman, a different one
than the first, made obvious by a very thick
foreign accent. She explained to me that Mr.
Green Leisure Suit was not able to come to
1
Special thanks to Brooke Sizer, an Associate
with Gray Reed & McGraw, for her assistance
with the citations and research for this article.
Further thanks to Jason Brookner, a Gray
Reed & McGraw Member for his suggestions
regarding bankruptcy issues and to Charles
Sartain, a Gray Reed Shareholder, for his
comments on general matters.
1
the phone, but he wanted me to know his
“check was in the mail.”
So why do you need an operating
agreement? In a sense you do not, or at
least you do not need one in writing. The
Statute of Frauds requires that agreements
providing for the transfer of land be in
writing, but it does not apply to oral
agreements providing for the operation of
an oil and gas well.4 In my own practice I
regularly observe situations where parties
operate oil and gas wells with no written
operating agreement. In fact, my perception
is that this phenomenon may actually be
increasing, which is an unexpected
development, given that that the AAPL
Form 610 Operating Agreement has been in
widespread use for almost sixty years (more
on this phenomenon later).
A month or so later I received a
letter in the mail, but no check was
enclosed. Instead, I found Mr. Green
Leisure Suit’s notice of personal bankruptcy
filing in federal bankruptcy court in the U.S.
Southern District of Texas (Houston).
Exxon, as an unsecured creditor, was to
stand in line behind scores of secured
banks and lending institutions, and
ultimately had to write off the $2-3 million.
But somehow my career survived, probably
because in the early 1980s Exxon was
enjoying record gross annual corporate
revenues in the billions upon billions of
dollars range so a $2-3 million write-off was
insignificant; plus my old boss transferred to
a new job and my new boss did not connect
the dots. So it happened that I had my first
encounter with a deadbeat non-operator. It
was not to be my last.
II.
So what do parties do if there is no
written operating agreement? By and large,
they simply act like one is in place. One of
the parties obtains a permit to operate the
well or wells, and then it sends joint
interests billings (JIBs) to its partners for
payment. Courts have found such
arrangements legally enforceable.5
A BRIEF OVERVIEW OF HISTORY
AND
USE
OF
OPERATING
AGREEMENTS
IN
THE
UPSTREAM EXPLORATION AND
PRODUCTION
distinctions between true oil and gas leases
(contracts with property rights attached) and
mineral fee (property rights only).
It has been said that “history is more
or less bunk.”2 Nevertheless, a bit of history
may be helpful in putting in perspective the
issue of the deadbeat non-operator and how
operating agreements have evolved to
address the problem.
4
However, those portions of a standard
operating agreement which relate to sales of
interests in real estate would come within the
Statute of Frauds. “While no case was found
holding an operating agreement to be within the
Statute [of Frauds], consider the following
attributes of an operating agreement: [followed
by list of eleven different provisions including
those covering lien rights, preferential rights to
purchase, maintenance of uniform interest,
waiver of right to partition and other provisions
which arguably come within the ambit of the
Statute of Frauds],” Michael E. Smith, Joint
Operating Agreements, an Overview, in OIL AND
GAS AGREEMENTS: JOINT OPERATIONS 12-3
(Rocky Mt. Min. L. Fdn. ed., 2007).
Let us start with the basic question
of what is an operating agreement and why
is it needed? In an oil industry context a
joint operating agreement (often referred to
by its abbreviated form, “JOA”) can be
defined as an agreement between one or
more parties to jointly develop an oil and
gas lease.3
5
See Exchange Oil & Gas Corp. v. Great
American Exploration Corp., 789 F.2d 1161,
1163–64 (5th Cir. 1986) (applying Louisiana law
to find a non-operator liable to an operator when
the
operator
detrimentally
relied
on
representations of the non-operator that it pay its
2
Interview by Charles N. Wheeler, Chicago
Tribune, with Henry Ford, Ford Motor Company.
(May 25, 1916).
3
“Oil and gas lease” is referred to in a very
generic
sense
without
worrying
about
2
But operating a well without a written
agreement involves risks as well as missed
opportunities. First of all, the legal status of
the parties under such an oral arrangement
might be construed as a common law
mining partnership. What is a mining
partnership?
A mining partnership is
created where co-owners unite to operate a
property and share in profits earned.6
Courts have found that a mining partnership
exists with or without a written agreement in
situations where each party to a mining
situation has the requisite “mutual control”
or “active participation” in operations.7 A
mining partnership can therefore be
imposed by law whether or not the parties
have expressly agreed. As Professor Ernest
Smith8 has stated:
[T]he mining partnership can be
described more accurately as a legal
concept, rather than a legal
arrangement. Unlike the partnership
or the tenancy in common, persons
rarely knowingly enter in a mining
partnership; rather, one party to
litigation seeks to have a relationship
characterized
as
a
mining
partnership so that certain favorable
legal consequences will result.9
What happens when a mining
partnership is imposed by law? First, a new
entity has been created for tax purposes
which can potentially lead to double or triple
taxation. (Once at the partnership level,
then again at a corporate level on
partnership distributions, and then again
when the corporation declares dividends
and its shareholders must report the income
on their individual returns.)
share in the costs of the well despite there being
no written operating agreement); William W.
Pugh and Harold J. Flanagan, Don’t Get Stuck
with the Dinner Check When It’s Not Your
Dinner: Indemnity and Insurance Issues Under
Joint Operating Agreements, in OIL AND GAS
AGREEMENTS: JOINT OPERATIONS, Part I.1(Rocky
Mt. Min. L. Fdn. ed., 2007) (citing Exchange Oil,
789 F.2d at 1164). See also Hunt Energy Corp.
v. Crosby-Mississippi Resources, Ltd. 732 F.
Supp. 1378, 1384 (S.D. Miss. 1989) (cited by
Pugh and Flanagan in the same article and
dealing with a situation where there was no
signed JOA but the non-operator had signed a
written AFE.).
Second, partnership liability is joint,
not several. For this reason practically all
form written operating agreements since the
1950s, at least, include a specific disclaimer
that a mining partnership is not being
created and that liability is several, not joint
and collective.
The
BP
Deepwater
Horizon/
Macondo disaster is a reminder why this is
important. If BP were to be pulled into
bankruptcy and if joint liability was to be
found, then BP’s partners would still be
liable for BP’s share of all damages,
consequential or otherwise. The theory
behind
modern,
written
operating
agreements such as the AAPL Model 610
6
The three essential elements of a mining
partnership are: (1) joint ownership; (2) joint
operation (or right to participate in management)
and (3) an express or implied agreement to
share in profits or losses. Andrew Derman and
Isabel Amadeo, The 1989 AAPL Model Form
Operating Agreement; Why Are You Not Using
It?, Landman Magazine, March/April 2004, at 33
(citing Fiske, Mining Partnership, 26 INST. ON OIL
& GAS L. & TAX’N, 187, 193 (1975)).
9
Ernest E. Smith, Duties and Obligations Owed
by an Operator to Non-Operator Investors and
Other Interest Owners, 32 ROCKY MT. MIN. L.
INST., 12-1, 12-5 (1986) (quoted by Milam
Randolph Pharo and Constance L. Rogers,
Liabilities of the Parties to a Model Form Joint
Operating Agreement: Who is responsible for
what?, in OIL AND GAS AGREEMENTS: JOINT
OPERATIONS (Rocky Mt. Min. L. Fdn., 2007)).
7
Id. (citing Dresser Industries, Inc. v. Crystal
Exploration and Production Co., No. 83-1275-W
(D. Okla. Jan 17, 1984), aff’d 1985 U.S. App.
Lexis 27084, No. 84-1160 10th Cir. July 12,
1985).
8
Rex G. Baker Centennial Chair in Natural
Resources Law and former Dean at the
University of Texas Law School.
3
Form is that liability is several, not joint;
therefore the non-operators are liable only
for their proportionate shares.
Given this perspective, it is easier to
understand the industry adage that
operating agreements exist primarily to rein
in the operator. They do this by providing
that liability is to be several, not joint; by
ensuring that parties have adequate
response time to AFEs; by incorporating
highly detailed accounting procedures; and
by otherwise imposing duties and
obligations on the operator for the benefit of
the non-operators.
you need an operating agreement? In shale
plays like the Bakken in North Dakota, for
example, it is very common place for
operators to simply ignore the numerous
small working interest owners and corral
them under a forced pooling order rather
than expend the time and effort required to
get all parties to execute an operating
agreements.
This is why some operators seem
indifferent to whether or not a JOA is
entered into. They view a JOA as giving up
an operator’s otherwise near total control
over the pace and scope of development.
First, in Texas and oftentimes in
other states forced pooling can be
problematic. Without force pooling, and in
the absence of a written JOA providing for
sole risk penalties, you are at risk of having
to carry a non-operator with no assurance of
recouping any more than the non-operator’s
share of well costs which is all that you
would be entitled to in the absence of forced
pooling or a written JOA.
But, generally speaking, not having
a written operating agreement is not a best
practice. There are at least five significant
advantages to having a written JOA.
But in what other industry would
millions of dollars be invested in joint
ventures with no controlling, written,
document? In some oil and gas companies,
particularly the majors, drilling a well without
an operating agreement violates delegation
of authority guidelines and leads to career
limiting (or ending) audit exceptions.
Second, JIBs are easily ignored and
often difficult to collect in the absence of
written agreements.11 Furthermore, in the
absence of a written agreement, attorney’s
fees are generally not recoverable when
suing on a debt.
Other oil and gas companies have a
more casual attitude, particularly in states
which, unlike Texas, have adopted
comprehensive and frequently-used force
pooling laws.10 If you can force pool another
party and enjoy a statutory non-consent
penalty (also called a “sole risk” penalty) for
doing so, or alternatively, if you can send
JIBs and receive payments anyway, why do
Third, a written operating agreement
can establish a contractual operator’s lien
on the non-operator’s share of production in
the event that JIBs are not paid. Though as
noted above an operating agreement per se
11
“Operators have generally been unsuccessful
in their attempt to collect ‘dry hole’ drilling costs
from a non-operator in the absence of an
operating agreement,” Pugh, supra note 5 (citing
Davis Oil Co. v. Steamboat Petroleum Corp.,
583 So. 2d 1139 (La. 1991); Zink v. Chevron
USA, Inc., No. 89-4923, 1992 WL 300816 (E.D.
La Oct. 8, 1992)). But in the same section of the
paper the authors also talk about cases
supporting the operator collecting against the
non-operator in the absence of a written
agreement. Id.
10
The Texas Mineral Interest Pooling Act
(MIPA), found at TEX. NAT. RES. CODE ANN. §
102 (Vernon 2011) has been characterized as
an Act to encourage voluntary pooling rather
than a true compulsory pooling act. Ernest
Smith, The Texas Compulsory Pooling Act, 43
TEX. L. REV. 1003, 1009 (1965). In any event it is
rarely used, at least in comparison with states
such as North Dakota or Oklahoma. See id. at
1011–1017 (explaining the requirements to use
the Texas statute to pool).
4
does not have to be in writing to comply with
the Statute of Frauds, the Statute of Frauds
would require a written agreement in order
to attach a contractual lien on real property.
are typically due within thirty (30) days
(more on advance payment requests later).
The fifth big advantage in having a
written JOA is that written operating
agreements are simply better suited than
oral agreements in developing large scale,
complicated, capital intensive oil and gas
fields which may be operated over long
periods of time. Back to my question, in
what other industry would millions of dollars
be invested in joint ventures with no
controlling, written, document?
An operator’s lien is the grant of a
security interest by a non-operator which
gives the operator the right to foreclose on
the non-operator’s interest for non-payment
of expenses due. Such liens in effect
collateralize the assets of the non-operators
and turn the operator into a secured
creditor. Though operator’s liens have been
known to have deficiencies depending on
the form of JOA used,12 they can provide a
useful tool in dealing with defaulting nonoperators which is not otherwise available
under an oral arrangement. 13
So, for a myriad of reasons, the oil
industry in the United States began using
written operating agreements in the early
20th century and by the 1930s and ‘40s
written operating agreements had become
very common. But each company tended to
use its own form as a starting point in
negotiations which was cumbersome and
inefficient. So in the early 1950s
representatives of oil and gas companies,
together with independent landmen and oil
and gas lawyers, began meeting to discuss
the creation of a model form operating
agreement. Early efforts in this regard
centered in the Oklahoma oil and gas
community. In 1956, the Ross Martin
Company of Tulsa, Oklahoma published the
Kraftbilt Form 610 JOA. About ten years
later
the
American
Association
of
Professional Landmen took the Kraftbilt 610
Form under its wing and renamed it the
AAPL Model Form 610 JOA. About ten
years after that, in 1977, the 1956 610 Form
was replaced with the 1977 AAPL 610
Form, and five years later with the 1982
AAPL Model 610 Form.
Fourth,
a
written
operating
agreement establishes the right of the
operator to ask for an advance (also known
as “cash call”) on funds needed for next
month’s operations. Advances under JOAs
12
See Gary B. Conine, Property Provisions of
the Joint Operating Agreement, in OIL AND GAS
AGREEMENTS: JOINT OPERATIONS (Rocky Mt. Min.
L. Fdn., 2007)(discussing some of the most
common deficiencies of JOA operator’s liens,
which include failure to adequately identify
collateral, failure to properly perfect, failure to
attach the lien to after acquired property, among
others).
13
There could be an exception, however. There
is some authority that a statutory mechanic’s
and materialman’s lien could work to the benefit
of an operator in a situation where there is no
written JOA. For example, an argument could
be made that the statutory Texas mechanic’s
and materialman’s lien (TEX. PROP. CODE ANN. §
56.001-56.003 (Vernon 2011)) extends to the
operator, because the operator is the person
with whom the contract with the mechanic or
materialman is made.
The statutory lien
provisions of Wyoming, Montana, New Mexico
and Colorado are similar to what exist in Texas.
See Andrew B. Derman and Isabel Amadeo,
The 1989 AAPL Model Form Operating
Agreement—Why Are You Not Using It?, in OIL
AND GAS AGREEMENTS: JOINT OPERATIONS
(Rocky Mt. Min. L. Fdn. ed., 2007).
It was one of those forms, the 1977
or the 1982 AAPL Form 610 Agreement that
I would have gotten Mr. Green Leisure Suit
to sign. My problems with Mr. Green Leisure
Suit were not isolated. As oil prices began
to slide in the mid-1980s and U.S.
Bankruptcy filings for defaulting oil and gas
companies occurred on a scale never
experienced before, shortcomings in the
provisions of the AAPL Model 610 Form
5
relative to deadbeat non-operators (and
operators) became increasingly apparent.14
To close the history lesson, it should
be noted that the AAPL Model 610 Form
has become the most widely used joint
operating agreement form in the domestic
USA, onshore, oil and gas industry.
Through the years competing forms have
been introduced17 but the AAPL 610 Form
has remained the most accepted model
form operating agreement for onshore US
oil and gas operations (at least during
primary recovery phases and for areas
outside the Rockies) and it has had a strong
influence on offshore operating agreement
forms as well, both domestically and
internationally.
The problem of dealing with
deadbeat participants was so severe that
the AAPL in the mid-1980s inaugurated still
another revision of the AAPL 610 Form
which was then released in 1989. The 1989
AAPL 610 agreement contained numerous
new provisions designed to better equip the
parties
in
dealing
with
defaulting
participants. These included expanded
advance payment (”cash call”) provisions,
provisions allowing the rights of a defaulting
party to be suspended, and provisions
deeming a party to be non-consent (and
subject to sole risk penalties) in the event of
default (more on these subjects later).
III.
At the time this paper is being
written, there is another revision of the
AAPL Form 610 Agreement underway, the
first effort in almost a quarter of a century
since the 1989 Form.15 This time one of the
principal drivers is to better adapt the form
to horizontal drilling operations. What will
likely be called the 2014 or 2015 AAPL
Model 610 Form is currently a work in
progress.16
As mentioned earlier, the desire to
have a contractual lien in place for
enforcement
against
deadbeat
nonoperators (and operators) was one of the
historical drivers for a written operating
agreement. The experience of the oil and
gas industry in the 1980s, however,
revealed that in many cases, the liens
provided for in the 1982 and earlier versions
of the AAPL 610 Form JOA were not worth
the paper they were written on. This was
because of the evolution of debtor/creditor
laws in the United States which by the
1980s had rendered unrecorded lien and
security interests significantly less valuable
and harder to enforce than they had been
before.
14
See David E. Pierce, Transactional Evolution
of Operating Agreements in the Oil and Gas
Industry, in OIL AND GAS AGREEMENTS: JOINT
OPERATIONS (Rocky Mt. Min. L. Fdn., 2007).
15
The AAPL released a version of the 1989
AAPL
610
JOA
with
new horizontal
modifications in December 2013. But the new
version of the AAPL 610 Form due out in 2014
or 2015 will address other issues as well. Jeff
Weems, AAPL Operating Agreement revision
committee member, address to the Houston Bar
Association Oil, Gas and Mineral Law Section
Luncheon: Changes Within the AAPL 610-1989
Model Form Operating Agreement—Horizontal
Modifications (Including a Discussion of
Anticipated Changes) (Sep. 24, 2013).
16
PROBLEMS WITH AAPL FORMS
PRIOR TO 1989 IN ENFORCING
OPERATOR’S LIEN
17
The Rocky Mountain Mineral Law Foundation
introduced its own Form 3 in 1959 and the
Canadian Association of Professional Landmen
has had various forms available since 1969.
Conine & Kramer, supra note 12. There are also
specialty forms such the Rocky Mountain
Mineral Law Foundation Model Form Operating
Agreement for Federal Exploratory Units or the
American Petroleum Institute Model Form for
Fieldwide Units.
Id.
6
Specifically, by the 1980s, the US
Bankruptcy Code had embedded within it
provisions whereby a trustee (or debtor in
possession)18 was vested with the rights of
a bona fide purchaser of real property
(BFP) if at the time the bankruptcy case was
commenced, a hypothetical purchaser could
have obtained BFP status. As a hypothetical
BFP, the trustee is deemed to have
conducted a title search, paid value for the
property, and perfected its interest as holder
of legal title as of the date the bankruptcy
case commenced. This allowed the trustee
to avoid any liens or conveyances that a
BFP could avoid.19 This would include
avoiding the operator’s lien in an
unrecorded AAPL 610 Form Operating
Agreement.
into bankruptcy is perceived to be relatively
small whereas the number of operating
agreements that would need to be recorded
is large. In addition, operating agreements
are often not acknowledged and therefore
would not qualify for recordation. Rather
than hassle with it, most operators just
threw the dice and took their chances.
Then, in 1987, the Oklahoma
Supreme Court ruled that the filing of a
Memorandum of a Joint Operating
Agreement would suffice to perfect an
operator’s
lien.20
Industry
reacted
immediately and many companies began
recording memoranda of JOA.21 The
Amarex case was highly influential on the
AAPL Committee tasked with revising the
1982 Model Form JOA, and the subsequent
1989 version of the AAPL JOA incorporated
for the first time a recording supplement.
The recording supplement was designed to
comply not only with the real property laws
of the states insofar as establishing lien
priorities but also with security interest
provisions of the Uniform Commercial Code
(UCC) which had been first introduced in
the United States in the early 1950s and
was eventually adopted in one form or the
other in all fifty states. The UCC greatly
expanded upon the breadth and scope of
state lien law and provided for the creation
and perfection of security interests through
use of financing statements normally filed in
the local Secretary of State office or
equivalent office.
This raises an issue that is
sometimes overlooked by landmen and
other industry professionals who work with
JOAs. Most landmen recognize that in order
to perfect the mineral lien provided for in a
Now, this problem had not arisen
overnight, and for many years before a
small minority of operators routinely
recorded joint operating agreements in
county and parish courthouses in an effort
to perfect their operator’s liens. But this was
much more the exception than the rule for
many reasons, including the per page cost
of recording lengthy documents such as a
JOA with all its exhibits in multiple counties
or even states if the contract area was very
large. The number of non-operators going
18
As a technical matter, the concept of a
“trustee” in a federal bankruptcy context exists,
for the most part, only in a Chapter 7 liquidation.
Most of the time, in Chapter 11, the debtor
remains “in possession” and in control of the
case and its business and its property (hence
the term of art, “debtor in possession” or DIP)
and the DIP is vested with, among other things,
the powers of a trustee to assume or reject
contracts (and avoid liens, etc.). On occasion a
Chapter 11 trustee is appointed to take over
operating the business where there has been
fraud, incompetence, etc.
20
Amarex, Inc. v. El Paso Natural Gas. Co, 772
P.2d. 905, 906–07 (Okla. 1987).
21
19
See Andrew B. Derman, Protecting Oil and
Gas Liens and Security Interests: Use of
Memorandum of Operating Agreements and
Financing Statements, ABA Natural Resources
Law Section Monograph Series (1987)
(demonstrating a recording memorandum in the
wake of the Amarex case).
The trustee (or DIP) can exercise the rights of
a bona fide purchaser (BFP) regardless of actual
knowledge, but the trustee’s rights as a BFP do
not override state recording statutes or allow
avoidance of an interest of which a trustee
would have had constructive notice under state
law.
7
JOA something must be filed in the real
property records of the county in which
operations occur. This is because prior to
extraction, oil, gas and other minerals are
real property.
provider against an oil and gas well operator
who is delinquent on his or her bills.22
A statutory mineral lien might create
a foreclosable interest in minerals in place
but in Texas, at least, arguably does not
attach to the proceeds of production.23 The
contractual lien and security interest
provided for in the AAPL 610 Operating
Agreement in Article VII B (1977, 1982 and
1989 versions) in contrast, creates both a
mineral lien and a security interest against
the non-operator’s share of production
which explicitly applies not only to oil and
gas rights in the ground but to the proceeds
from extracted oil and gas.
After extraction, however, oil and
gas become goods and are no longer real
property. Therefore the mineral lien would
no longer apply. This is why Article VII B of
the AAPL 610 Operating Agreement
establishes both a mineral lien and a
security interest in extracted oil and gas. For
those unfamiliar with the concept, a
“security interest” is a property interest
created by agreement or by operation of law
over assets to secure the performance of an
obligation, usually the payment of a debt.
So in this sense it is similar to a mineral lien.
It gives the beneficiary of the security
interest certain preferential rights in the
disposition of secured assets. Such rights
vary according to the type of security
interest, but in most cases, a holder of the
security interest is entitled to seize, and
usually sell, the property to discharge the
debt that the security interest secures.
Recording the JOA memo in the
county may suffice to perfect a mineral lien
in oil and gas when it is still in the ground.
But in order to perfect a JOA security
interest in extracted oil and gas, special
steps must be taken under Article 9 of the
UCC which go beyond recording the
memorandum in the county.
“Perfection” of a security interest is
UCC terminology for the process of
providing notice to all creditors of security
interests in property.24 Essentially this
involves filing a “financing statement” with
A type of security interest which is
commonly seen in oil and gas operations is
the one provided for by Article 9 of the UCC.
A UCC Article 9 security interest is different
from a mineral lien in that it is an interest in
personal property and fixtures only (i.e. the
proceeds of sales of extracted oil and gas
and the facilities needed to produce such as
well-heads, storage tanks, processing
facilities and so forth).
22
See e.g., TEX. PROP. CODE ANN. § 56.001
(Vernon 2011).
23
See Deborah D. Williamson & Meghan E.
Bishop, W HEN GUSHERS GO DRY: THE
ESSENTIALS OF OIL AND GAS BANKRUPTCY 117
n.337 (2012). But see id. at 116–123 (discussing
Abella v. Knight Oil Tools, 945 S.W. 2d 847
st
(Tex. App.—Houston [1 Dist.] 1997, no writ)
which discusses that even in Texas, mineral lien
claimants might have the right under state law to
commence a lien foreclosure action and request
the appointment of a receiver who could seize
and preserve the proceeds of production). See
also, id. at 121–122 (stating that Oklahoma is a
state where mechanic’s and materialman’s liens
by statute explicitly attach to the proceeds from
the sale of produced oil and gas); OKLA. STAT.
tit. 42, § 144 (2013).
Contractual security interests such
as the one provided for in UCC Article 9 are
therefore entirely different creatures than
mineral liens. Mineral liens are real property
interests. A mineral lien can either be
contractual (for example, the contractual
mineral lien provided for in the AAPL 610
Form JOA), or statutory. An example of a
statutory mineral lien would be a mechanic
and materialman’s lien recorded on the
county records by an oil field services
24
8
See Derman, supra note 20, at 10.
the Secretary of State in the jurisdiction
where the property is located.25
The
technical requirements of UCC financing
statements can vary from state to state and
a detailed discussion of what is required to
perfect a security interest under UCC Article
9 is beyond the scope of this article.
However, the authors of the 1989 AAPL 610
JOA recognized the issue and incorporated
the most common UCC financing statement
requirements into a Memorandum of
Operating Agreement and Financing
Statement normally attached to the
operating agreement as Exhibit H.26
marketers likewise might give their lenders
a lien and financing statement on extracted
oil and gas. So the operator under an AAPL
Model Form JOA must be prepared to
assert its mineral lien and security interest
against a variety of lenders and other lien
holders who will invariably have filed both
mineral liens and financing statements.
Battles between secured lenders
and mineral lien claimants over who is firstin-right to oil and gas leasehold collateral
and who has the best claim to proceeds of
production can be among the most divisive
issues in foreclosure, bankruptcy and other
creditor’s rights proceedings.27 Having
properly perfected a security interest by
filing a financing statement with the
Secretary of State may or may not lead an
operator to prevail over another secured
creditor; but not having properly perfected a
security interest by both recording a JOA on
the county record and filing a financing
statement at the Secretary of State’s office
seems a near certain path to defeat.28
So what happens if you are the
operator under an AAPL Model Form 610
JOA and you record the JOA on the county
(parish) records, but neglect to file a
financing statement with the Secretary of
State and the operator fails to pay and/or
goes bankrupt? First, it should be noted
that lenders financing oil and gas operations
usually take both a mortgage (or in Texas, a
deed of trust) on the real property and a
security interest that attaches to the
extracted oil and gas as they become
goods. First purchasers such as gatherers,
processors,
pipeline
companies,
or
27
28
Williamson and Bishop, supra note 21, at 71.
Filing a UCC financing statement should not
be looked upon as a one-time occurrence. A
UCC financing statement is normally effective
for a period of five years after the date of filing
and automatically lapses if a continuation
statement is not filed/recorded within six months
prior to the end of this five-year term. A
financing statement’s lapse does not terminate
the lien. Rather, upon lapse, any security
interest that was perfected by the financing
statement becomes unperfected. Such loss of
perfection renders the collateral clear of the
financing lien as against a purchaser of the
collateral for value. Therefore in the event a
decision is made to perfect a security interest
under an AAPL 610 JOA, a “tickler” file should
be set up to remind the operator to file a
continuation statement after a period of five
years. This, of course, requires discipline in
today’s world where constant churning of
personnel and/or overworked staffs tends
towards either ineffective follow up and/or or a
lack of accountability for failures.
25
So an operator’s security interest under the
AAPL 610 JOA is unperfected unless it is
recorded at the Secretary of State’s (or
equivalent) office. To further emphasize,
consider that in 1983 the Texas legislature
enacted a non-uniform, Texas specific UCC
article which gives a royalty owner a lien on
severed oil and gas and proceeds therefrom
without the necessity of filing a financing
statement. The thought was that royalty owners
are more apt to be unsophisticated when it
comes to compliance with UCC Article 9
financing statement provisions so an exemption
was given. No such exemption is provided for,
however, for an oil and gas operator. TEX. BUS.
& COM. CODE ANN. §9.343 (Vernon 2011).
26
See e.g., Andrew B. Derman, The New and
Improved 1989 Operating Agreement: A
Working Manual, ABA Natural Resources Law
Section Monograph Series (1991).
9
In addition to providing for a better
method of perfecting an operator’s lien, the
1989 AAPL Form JOA also provided that
future acquired personal property be
included and required the parties to make
representations about lien priorities. There
were other revisions as well. Overall, the
lien provisions in the 1989 Form are a
significant
improvement
over
prior
29
versions.
and extracted oil and gas junior to other
secured creditors. I would surmise this is
primarily for reasons of overworked and
understaffed legal, land and accounting
staff. This may be an area where either
reprioritization or an increase in staff may
yield dividends. Outsourcing the task to
private counsel, of course, is another option.
IV.
The 1989 AAPL Form JOA has not
been without controversy and despite
having had almost a quarter century pass
since the 1989 Form was released, some
operators either refuse to use it or use it
very reluctantly because of the perception
that it is more non-operator friendly,
particularly when it comes to removal of the
operator.30 I tell clients that if this is their
only objection, why not switch out the
operator provision and use the rest of the
1989 Form? But irrespective of what a
company may think about other parts of the
1989 AAPL JOA Form, not having a
recording
supplement
executed
and
properly perfected by recording in county
records and with the Secretary of State at
least in connection with new operating
agreements would appear to be a missed
opportunity to reduce risk. What bank or
other financial institution would not bother to
record a mortgage or deed of trust and
financing statement to secure an apartment
complex or an office building when rents are
due and used to secure the loan? Yet, I
constantly
see
situations
where
sophisticated oil and gas companies simply
do not take advantage of the opportunity to
record JOA supplements in the county
records and/or file financing statements with
the Secretary of State and thereby make
their lien and security interests in minerals
29
UNIQUE FEATURES OF THE 1989
AAPL MODEL FORM JOA IN
DEALING WITH DEADBEAT NONOPERATORS
As mentioned earlier, one of the
primary drivers behind the revisions to the
1989 Model Form JOA was to better deal
with the problem of the deadbeat nonoperator in the fallout of the oil price crash
of the mid-1980s. The recording supplement
was only one of the new features. Article VII
of the 1989 JOA, Expenditures and Liability
of Parties, was the most comprehensive rewrite of the section of the AAPL Model Form
610 Agreement dealing with defaults in
payment since the form first appeared in the
mid-1950s.
Three new provisions, in particular, if
properly implemented, eliminate or at least
severely mitigate the type of gaming of the
process that Mr. Green Leisure Suit was so
successful with at Exxon’s expense. These
three provisions, all found in Article VII D,
“Defaults and Remedies,” are “Advance
Payment,” “Suspension of Rights,” and
“Deemed Non-Consent.” As usual there is
strength in numbers and it is the interplay
between
these
three
complimentary
sections of the AAPL Form that can provide
such a powerful deterrent to deadbeat
behavior.
Some might say, why not perform a
credit check on the proposed non-operator
at the outset and use that data as the basis
for a “go” or “no-go” decision before getting
in further with a potential deadbeat nonoperator? A credit report may be interesting,
but as a practical matter, what happens if
the report comes back bad? In the case of
See Derman, supra note 25.
30
See Reeder v. Wood County Energy, LLC¸
395 S.W.3d 789 (Tex. 2012) (discussing
differences in operator removal provisions in the
1989 versus the 1982 versions of the AAPL 610
JOA).
10
Mr. Green Leisure Suit, for example, you
would still be stuck with a leaseholder who
owns a significant portion of your prospect
and who refuses to dilute his interest by
farming out. Your remaining alternatives
absent proceeding with an agreement with
Mr. Green Leisure Suit are: 1) to abandon
your prospect; 2) to drill the well and carry
him under either common law co-tenancy
principles; or 3) if you are in a state with a
strong force pooling regime, to attempt to
have a forced pooling penalty imposed.
Council of Petroleum Accountants Society
(COPAS) though COPAS provisions and
procedures
generally
reflect
and
complement advance payment provisions in
the AAPL 610 Form.31
Recall earlier that in the instance of
Mr. Green Leisure Suit, advance payment
was sought. The problem in that situation,
as well as under the earlier AAPL 610
Forms prior to the 1989 Form, was what
happens if the party ignores advance
payment requests and the operator drills a
dry hole? An operator’s lien in that instance
is not worth anything. The operator of
course can sue the defaulting non-operator
and attempt to collect the debt but that can
take years and as in the case of Mr. Green
Leisure Suit, can be thwarted by a
bankruptcy filing.
Even if the well is
completed as a producer, nothing would
have prevented Mr. Green Leisure Suit from
taking the wells logs to a bank (or his
daddy) and borrowing his share of the
drilling costs. He could then pay off any
arrearages or operator’s liens, and come
back into the well as if he had been
participating from day one with no penalty.
Common law co-tenancy principles
do not provide for sole risk penalties so
carrying a party under common law cotenancy rules is not always a viable
economic option. As for forced pooling,
under practically all forced pooling regimes
the party being forced pooled must be given
an opportunity to join the well in the first
instance. Having to give a party the
opportunity to join the well as a precondition
to forced pooling puts you back at square
one. What if he or she says “yes”?
So consider the other option—
holding your nose irrespective of the credit
report (or not even bothering with a credit
report), and proceeding to have the nonoperator execute a 1989 Model Form JOA.
Then what happens then if the non-operator
proves to be a deadbeat?
A.
The earlier versions of the AAPL 610
Agreement provided for such “free rides” for
the unscrupulous non-operators with no
penalty and or suspension of rights.
Perhaps even more galling is that the earlier
Form AAPL agreements still entitled the
ADVANCE PAYMENTS
The key to avoiding being taken
advantage of by deadbeat non-operators is
relatively simple: get your money up front. If
the non-operator does not have sufficient
funds to pay for operations, find out as early
as possible. The vehicle for doing this is a
JOA’s “Advance Payment” (cash call)
provision. This provision allows the operator
to demand advance payment for the next
succeeding
month’s
estimated
expenditures. Such provisions have been
incorporated in all versions of the AAPL
Model Form beginning with the 1956 Form.
They are also incorporated in the model
form accounting procedure published by the
31
The most recently published COPAS
accounting procedure for onshore operations is
the 2005 version, which was a revision of a prior
version, released in 1984. There was
substantially no difference between the 1984
and 2005 COPAS procedures with regard to
Advance
Payments.
See
Jonathan
D.
Baughman and J. Derrick Price, COPA and the
2005
COPAS
Accounting
Procedure—
Significant Changes for Changing Times, STATE
BAR OF TEXAS OIL, GAS AND ENERGY RESOURCES
BULLETIN, SECTION REPORT, Vol. 29, No. 3, at 28
(March 2005) (Appendix—Comparison of Major
Provisions in 2005 COPAS Accounting
Procedure with 1984 Onshore Accounting
Procedure).
11
defaulting party
information.
to
receive
full
well
reduce the administrative burden on all
parties to the operation by eliminating
multiple billing of thirty day increments
within the same operation.33 If a nonoperator was to object to having to prefund
such an operation on a time value of money
basis, a discount could be factored in. An
operator would normally be better off giving
a discount in order to get non-operators to
pay all estimated costs up front than to run
the risk of non-payment for succeeding
months after the operation is underway and
the operator has committed to its
completion.
The “Advance Payment” provision,
found at Article VII D 4 under the 1989
Form, itself was not conceptually new. What
was new about it was that it was tied to a
new provision within the same Article VII D
1, “Suspension of Rights.” Under the 1989
Form, the initial advance payment may be
requested as early as the first day of the
month preceding the operation. Once the
request for an advance is received, the
advance is due within fifteen days.32 If
payment is not received, the operator may
then send a 30 day Notice of Default. If the
Notice of Default period runs with no
response, then under the new Article VII D 4
of the 1989 Form the operator is entitled to
send further notice providing for an
immediate cash call of any expenses due
from the non-operator anywhere in the
contract area, and irrespective that they are
or are not related to the new operation. In
other words, the operator in this situation is
not limited to demanding only the next
succeeding month’s estimated expenses;
instead, the operator can cash call for all
remaining estimated expenses in the
proposed operation or any other operation
in the contract area. The expanded cash
call is in addition to any other remedies
provided for in Article VII, including
Suspension of Rights and Deemed NonConsent.
B.
If the non-operator does not respond
within the 30 day Notice of Default Period,
then in accordance with Article VII D 1, “all
of the rights of the defaulting party granted
by this agreement may upon notice be
suspended until the default is cured.” The
rights of the defaulting party that may be
suspended include (paraphrased):
1. The right to receive information as to
any operation (well logs, production
tests, etc.)
2. The right to elect to participate in
any operation under the agreement
3. The right to receive production
proceeds
from
any
currently
producing well (i.e. the right to set off
current liabilities against production).
In addition, though not in the 1989
JOA Form, I recommend that operators
attempt to negotiate a special provision
under Article XVI, “Other Provisions,” which
expands on the “Advance Payment”
provision in Article VII of the form to give the
operator the right to demand all estimated
well expenses for a proposed well (not just
the next succeeding month’s estimated
expenses). This not only reduces the
operator’s risk of being taken advantage of
by a defaulting non-operator, but can
32
SUSPENSION OF RIGHTS
Mr. Green Leisure Suit, therefore, would no
longer be getting the well logs to use for
loan purposes. Likewise, he forfeits his
rights to participate in any existing
production and any future operations. The
importance of not being able to participate
in future operations becomes apparent
33
See OIL AND GAS LAND, A REFERENCE VOLUME
CPL AND RPL EXAM STUDY GUIDE 171 (American
Association of Professional Landmen eds., 11th
ed. 2012).
Article VII C, 1989 AAPL Form 610 JOA.
12
when new provision VII D 3, “Deemed NonConsent,” is examined.
C.
special provision that can be added under
Article XVI, “Other Provisions.” That would
be to say that if “deemed non-consent”
provisions are invoked due to a nonoperator not paying its bills, that the normal
sole risk penalties in the JOA are doubled
(or even tripled).34
Now, what about the common law
rule that liquidated damages must constitute
a permissible forecast of damages rather
than an impermissible penalty? Would
doubling the sole risk penalty in a deemed
non-consent situation pass muster with a
court?
DEEMED NON-CONSENT
The last of the three new features of
Article VII D of the 1989 AAPL Form is
perhaps the most erosive one of all when he
comes to the rights of a deadbeat nonoperator. This is the “Deemed NonConsent” provision found in article VII D 3.
Had a 1989 Form AAPL Agreement
been in place for use with Mr. Green
Leisure Suit, immediately following the
expiration of the 30 day cure period after a
Notice of Default, Mr. Green Leisure Suit
could have been sent a Notice of NonConsent Election. At that point, Mr. Green
Leisure Suit would have been non-consent
subject to sole risk penalties and
irrespective of his earlier election to
participate.
Very significantly, his nonconsent status would be irreversible. No
more waiting the well down and then taking
the well logs to a friendly banker to borrow
money to get back into the well.
There is no Texas case directly on
point. There is authority in Texas, however,
for upholding non-consent penalties in a
JOA as permissible forecasts of damages.35
But a provision in a JOA doubling the
normal non-consent penalty in a deemed
non-consent situation might be pressing the
envelope. It is conceivable that a court
could find as a matter of law that such a
penalty bears no reasonable relation to
actual damages. On the other hand, one
could make the argument that such
doubling of the penalty is appropriate to
compensate not only for actual damages,
but for consequential damages as
contemplated by the agreement (see
discussion which follows). Until an appellate
court examines the issue, having additional
sole risk penalties in such situations might
At this point Mr. Green Leisure Suit
would have been much worse off than had
he farmed out irrespective of dilution
because he would get no overriding royalty
during payout as is typical under a farmout
and unless the well was extremely good,
would be unlikely to see any income for
years (if ever), waiting on multiple sole risk
payouts to occur prior to his interest
reverting. The operator, in other words, has
the last laugh.
34
In practice this would mean doubling, for
example, the 300% drilling non-consent penalty
(or whatever the number may be) due by a nonconsenting party to 600% if the party originally
claimed to be a fully participating operator.
All three of these provisions taken
together—“Advance
Payments,”
“Suspension of Rights,” and “Deemed NonConsent”—permit an operator to in effect
“Blitzkrieg” a non-operator with fast moving
notices of default, follow up notices of
suspension of rights, and deemed nonconsent which cumulatively serve to strip
the non-operator of practically all right, title
and interest in the contract area, at least
until the sole risk penalties pay out. As the
coup de gras, I recommend one more
35
Non-consent penalties have been viewed by
at least one court to be permissible as it was
held to be a “…mechanism utilized to allow the
consenting parties the opportunity to recover
their investments and receive defined returns
from future operations.” Valence Operating Co.
v. Dorsett, 164 S.W.3d 656, 664 (Tex. 2005).
This removed them from the context of an
analysis as a liquidated damages provision. Id.
13
at least cause a potential deadbeat nonoperator to think twice.36
There appears to be no case law
dealing with what types of consequential
damages might be available for recovery
against a non-operator in these situations
and given the exhaustive suspension of
rights and deemed non-consent provisions
that may be used against a defaulting nonoperator
fact
situations
calling
for
consequential damages may not be
common. Lost opportunities in losing a
lease by not drilling a well might be such a
fact situation if the operator could prove that
its line of credit was impaired, for example,
by having to cover for a deadbeat nonoperator leaving it short of funds to either
purchase a lease or perpetuate it through
drilling. This could theoretically make a
defaulting non-operator liable for the
reserve value of the lost lease which could
conceivably be tens or hundreds of millions
of dollars or more in consequential
damages. Again, the real power in the
consequential damages provision is that it
puts another element of risk on the nonoperator which in turn might cause it to
pause and reflect more before defaulting.
Something else that many operators
forget or at least fail to take action upon
when non-operators default is that if a party
defaults on its payments to the operator, the
remaining, non-defaulting parties may be
required by the operator to pay their
proportionate shares of the default amounts
due operator.37 In other words, the operator
does not have to be the only “banker” for a
defaulting non-operator—the other parties
to the JOA can be required to bear the
burden as well. This is an exception to the
normal rule under the JOA that liabilities are
several, not joint and collective. If a party
refuses to pay their share of the defaulting
party’s costs, that party can likewise be put
on notice of default, suspended, deemed
non-consent and so forth.
D.
ATTORNEYS FEES, LATE
PAYMENT INTEREST,
COURT COSTS,
CONSEQUENTIAL
DAMAGES
V.
Last, Article VII of the 1989 AAPL
Operating Agreement Form expands upon
prior versions of the 610 Agreement with
regard to suits for damages, attorneys’ fees,
late payment interest, court costs and
consequential damages. These are now all
available for recovery against a defaulting
non-operator irrespective of whether such
damages may already be provided for under
state law.
The drafters of the 1989 AAPL
Model Form 610 JOA have done such a
good job in addressing situations as the one
encountered with Mr. Green Leisure Suit
that I wonder if a more modern day Mr.
Green Leisure Suit (the older one having
obviously been much slyer than I had given
him credit for) would ever agree to sign a
1989 AAPL Form 610 JOA? His or her
attorney should certainly advise of the
potentially draconian consequences of
default under the 1989 Form with its
Suspension of Rights and Deemed NonConsent provisions. That in turn might make
the non-operator more seriously consider a
farmout, which is probably what any rational
individual or small non-operator should
consider doing before joining a company the
36
There has been a move to allow liquidated
damages to be judged reasonable or not at time
of breach, instead of just at the time of
contracting. Calamari and Perillo, THE LAW OF
CONTRACTS § 14.31 (5th ed. 2003). See also
Restatement (Second) of Contracts § 356
(1981). This trend might bode well for upping
liquidated damages when a party breaches a
JOA by non-payment.
37
CONCLUSION: BEST PRACTICES IN
AVOIDING ISSUES WITH DEADBEAT
NON-OPERATORS
Article VII B, 1989 AAPL Form 610 JOA.
14
size of ExxonMobil in a well and attempting
to “run with the big dogs.”38
before making a decision to pay or
not and thereby avoid taking the risk
of a dry hole if the well reaches
target depth soon enough.
The 1989 AAPL JOA Form therefore
has the potential of scaring away certain
non-operators. It might be speculated that
this may be an unintended consequence of
the introduction of the 1989 AAPL 610 Form
JOA—some non-operators may prefer not
to agree to it at all rather than risk being
made subject to the new “Suspension of
Rights” and “Deemed Non-Consent”
provisions. But does an operator really want
to do business with a non-operator
possessing such an attitude?
3. Cash Call as Early as Possible.
Exercise your rights to “cash call”
(call for advances) as early as
possible in the drilling cycle. Stay in
communication with your company’s
(or your client’s) accounting staff and
monitor the response of the nonoperators. Even if you are operating
under an earlier form JOA, a
demand letter can be sent (as a
prelude to a suit for damages) and
an operator’s lien invoked against
production should the non-operator
ignore the cash call. Also, do not
forget that the remaining, nondefaulting parties can be required to
cover their share of the amounts
defaulting parties owe the operator.
This is an area where engagement
and fast action by the operator in
taking administrative advantage of
all the provisions of the JOA can
yield large dividends.
Regardless, the following are what
the author would consider to be six best
practices in avoiding issues with deadbeat
non-operators.
1. Written JOA. Have a written Joint
Operating Agreement, always. Any
loss of control by the operator is
offset by the advantages of avoiding
mining partnership status and rights
in dealing with defaulting non
operators.
2. Make Finalization of the JOA a
Priority. Do not delay getting the
operating agreement finalized. If you
get nothing else out of this article,
come away with an appreciation of
the importance of getting your
money up front by invoking the cash
call provisions under the JOA. In
order to cash call under a JOA,
however, such that suspension of
rights and so forth can be a remedy,
the signed JOA must be in place.
Too often parties postpone the JOA
negotiation to a point so late in the
process that the well is spudded
before cash calls are made. At that
point the deadbeat non-operator can
wait out the notice of default periods
4. Record the JOA Memo and
Perfect the Financing Statement.
Timely execute and record a JOA
Recording Supplement at least in
the county, and preferably with both
the county and the Secretary of
State (for UCC Article 9 purposes).
This is a relatively easy process that
can reap dividends if a non-operator
becomes insolvent. In addition,
create processes that ensure
continuation statements are filed
after the requisite statutory period
(usually 5 years) for the previous
financing statement lapses.
5. Use the Most Recent JOA Form
(1989). Next, if you are not using the
1989 Model Form JOA, switch to it.
If the operator removal provision
cannot be lived with, then revert to
the 1982 Model Form JOA operator
38
Or if it does join ExxonMobil or any other large
oil company in a well, at least propose a cost
overrun provision.
15
removal provision by making a
modification to the 1989 Form under
Article XVI, “Other Provisions.” The
rest of the 1989 AAPL Model Form
JOA is so superior to prior versions
that not using it because of
objections to that one provision is
likened to throwing the baby out with
the bathwater. If a non-operator
were to push back on the 1989 JOA
Form because of the “Suspension of
Rights” and “Deemed Non-Consent”
provisions, it begs the question, why
the protest and do you really want to
do
business
with
them?
Furthermore, stay tuned to the AAPL
610 JOA revision which is currently
underway and when it comes out,
get familiar with it as soon as
possible. If history is any example,
the new JOA form will be superior to
the current JOA forms in use.
the time of this article well over $90 a
barrel and many observers bullish on
the long term demand outlook for crude
oil,40 how can the additional time and
expense required to record JOAs and
financing statements be justified?
Justification can be found by
reflecting on the experience of the oil
and gas industry in the United States in
the mid-1980s and comparing it with the
eerily similar situation that the industry
finds itself in at the time this article is
being written in late 2013. Crude oil
production in the United States is at the
highest level since the 1980s.41
President Obama and his administration
are negotiating a lifting of sanctions with
Iran which can potentially unleash
millions of barrels of crude oil onto world
markets.42 For the short term, at least,
Middle Eastern oil supplies together with
new US production coming on-stream
appear to be more than adequate in
filling international oil demand.43 Is an oil
6. Special Provisions. Last, consider
adding special provisions to Article
XVI, “Other Provisions,” such that 1)
an operator can cash call all well
costs, not just the succeeding
month’s estimated expenditures, and
2) to provide that the sole risk
penalties in “deemed non-consent”
situations are doubled (or tripled). 39
40
See ExxonMobil, Outlook for Energy: A View
to 2040, CORPORATE.EXXONMOBIL.COM (2013),
available at
http://corporate.exxonmobil.com/en/energy/ener
gy-outlook (giving data on global oil demand).
41
Zain Shauk, US Oil Production Reaches
Highest Level in 24 year, FUELFIX.COM (Sep. 6,
2013,
7:30
AM),
http://fuelfix.com/blog/2013/09/06/u-s-oilproduction-at-highest-level-in-24years/?shared=email&msg=fail.
All of the above of course requires
time and effort and today’s overworked
landmen, company attorneys, and
affiliated private counsel or other
personnel may question whether the
potential benefit outweighs the risk?
After all, with current crude oil prices at
42
Ambrose Evans-Pritchard, Iran sanctions deal
to unleash oil supply but Saudi wild card looms,
THE TELEGRAPH (Nov. 24, 2013, 9:00 PM),
available
at
http://www.telegraph.co.uk/finance/comment/am
broseevans_pritchard/10471548/Iran-sanctionsdeal-to-unleash-oil-supply-but-Saudi-wild-cardlooms.html.
39
There are numerous other special provisions
that are beyond the scope of this article but
which should be considered when negotiating
JOAs. For examples, see Derman, supra, note
25, at article XVI. See generally, Mark A.
Mathers and Christopher S. Kulander, Additional
Provisions to Form Joint Operating Agreements,
SECTION REPORT, OIL, GAS AND ENERGY SECTION,
STATE BAR OF TEXAS, Volume 33, Number 2
(Dec. 2008).
43
Steven Mufson, OPEC scrambling to keep oil
prices stable (and high) as it meets Wednesday,
THE W ASHINGTON POST (Dec. 2, 2013), available
at
http://www.washingtonpost.com/business/econo
my/opec-scrambling-to-keep-oil-prices-stableand-high-as-it-meets-
16
price crash similar to what was
experienced in the mid-1980s out of the
question in the mid-2010s? If such a
crash were to re-occur, how many nonoperators (and operators for that matter)
might find themselves in serious
financial trouble? History, unfortunately,
tends to repeat itself.
Shakespeare wrote, “[t]o fear the
worst often cures the worse,”44 or in
more modern English, planning for a
worst case outcome can sometimes
prevent the worst case from happening
at all. The best practices referenced
above seem consistent with prudent
planning for both worst and best case oil
price scenarios. Insurance always
seems expensive until one has a claim.
Providing more insurance for clients and
oil companies against insolvent nonoperators by taking some of the simple
steps outlined above may be well worth
the effort in dealing with the
uncertainties of the future.
There is yet one more “best” practice
not listed above but still worth
considering. If an individual ever comes
in your office wearing a very dated
green leisure suit with a gold puka shell
necklace and proposes that he partner
with your company or your client in an
oil and gas well, first, be wary. Second,
ask him to give the author a phone call,
as there may be some old business to
discuss.
wednesday/2013/12/02/2d5aeef0-5b6c-11e3a49b-90a0e156254b_story.html.
44
W ILLIAM SHAKESPEARE, TROILUS AND CRESSIDA,
act III, sc. ii.
17
to overlying surface estates. These
doctrines vary across jurisdictions, both in
form and substance. A majority of
jurisdictions refer to the mineral estate as
the “dominant estate,”3 but some hold that
the mineral owner has an implied right4 or
implied easement to make a reasonable use
of the surface. Others have been entirely
replaced by a statutory scheme.5 However,
the general premise behind each of these
doctrines is that the mineral estate, by its
very nature, is entitled to some form of right
of access and use of the surface estate for
the purposes of hydrocarbon exploration,
development and production operations.
SURFACE USE AGREEMENTS:
MULTIJURISDICTIONAL CONSIDERATIONS IN
NEGOTIATING AND DRAFTING AGREEMENTS
FOR USE OF SURFACE ESTATES IN OIL AND
GAS EXPLORATION, PRODUCTION AND
DEVELOPMENT
Randall K. Sadler, Editor
D. Bradley Gibbs, Author and Editor
Michael P. O’Connor, Author
Michael A. Mulé, Author
Travis Crawford, Author
Brian T. Wittpenn, Editor
Austin W. Brister, Author and Editor
Joseph “Joey” L. Breitenbach, Author
Daniel Tyson, Author
Houston, Texas
In decades past, oil and gas
operators could rely primarily on these legal
doctrines to gain the required access and
use for their operations. However, as time
has passed, important limitations have been
placed on the right to surface access and
use. While these limitations vary across
jurisdictions, many operators are now
required to alter their drilling plans to
accommodate certain surface uses, and
compensate the surface owner for use or
damage to the surface estate. Moreover,
many state legislatures have enacted
statutory frameworks requiring operators to
make good faith efforts to negotiate surface
use and damages agreements with the
surface owner.
INTRODUCTION
An
important
issue
in
the
development of oil and gas properties is the
right to use the surface estate for
hydrocarbon exploration, development and
production operations. The vast majority of
oil and gas leases grant the lessee the right
to use the surface; however, a large number
of production units cover lands consisting of
severed estates, where the owners of the
minerals are not the same parties as the
owners of the surface. It is with this severed
estate that conflict arises due to “the ageold battle between the surface owner and
mineral owner, as to their respective rights
in the use….”1 Surface owners’ existing and
future activities often conflict, to some
extent, with the goal of a mineral owner or
its lessee seeking to extract minerals from
under the surface.
mineral estate or its lessee.
3
See e.g., 38 AM. JUR. 2D Gas and Oil §§ 67,
69, 110 (2013) (citing numerous cases across
numerous jurisdictions holding that the mineral
estate is dominant and the surface estate is
servient).
A majority of jurisdictions have longheld and well-established legal doctrines
that provide mineral operators2 with access
4
Rosticil v. Phillips Petroleum Co., 502 P.2d
825, 826 (Kan. 1972).
1
Texaco, Inc. v. Parker, 373 S.W.2d 870, 871
(Tex. Civ. App.—El Paso 1963, writ ref’d n.r.e.).
5
See, e.g., W YO. STAT. ANN. §§ 30-5-401–410
(2013) (making Wyoming mineral estates the
dominant estates).
2
As referenced throughout this article the term
“operator” is used to refer to the owner of the
18
These existing surface access and
use frameworks have been complicated by
the
proliferation
of
technological
advancements in hydraulic fracturing and
horizontal drilling. Through the pairing of
these technologies, it is now practical and
somewhat common for an operator to place
a drilling padsite on one surface tract with
the intent of targeting a formation that
wholly underlies different surface tracts.
Under this plan of action, the minerals
underlying the surface entry site are not
benefitted, and thus, the operator may not
gain access and use through the dominant
estate theory.
push an image that operators do not
adequately respect the rights of the
landowners and their community. This
pervasive negative attitude hasn’t stopped
at activists; a notable portion of the general
public has begun to adopt the opinion that
the legal relationship between the surface
and mineral estates unfairly favors the
mineral owner, and have become
increasingly vocal to their legislatures.7
One method of dealing with this
conflict between lessees of the mineral
estate and surface owners is to negotiate
Surface Use Agreements (“SUA”).8 One
purpose of an SUA is to lay out the rights
and obligations of the parties as to the use
of the surface. Through these SUAs,
uncertainty and unforeseeability can be
avoided for both the operator and the
surface owner. SUAs allow the parties to
resolve their competing interests and come
to a voluntary agreement
through
negotiation, rather than confrontation and
litigation. While not every issue can be
anticipated and covered in the SUA, the
process of negotiating an SUA allows the
parties to develop trust and rapport, and
make true progress towards avoiding future
conflict
and
maintaining
workable
relationships.
An additional complication is the
continued growth of population in areas
potentially rich in oil and gas reserves.
Areas once prone to conflict only with
farming and grazing activities are now
becoming subject to a vast array of
residential concerns and implications.
Furthermore,
environmentalists
have
countered the proliferation of hydraulic
fracturing with vigor, terming themselves
“fractivists,”
and
their
movement
6
“fractivism.” These “fractivists” continue to
6
There are several spellings used in industry for
“fracking,” a shorthand term used to describe the
hydraulic fracturing process. Examples include
“fracking,” “fraccing,” “fracing,” “hydrofracking,”
“hydrofraccing,” and “hydrofracing.” These terms
all refer to the same process, are used
interchangeably, though regional preferences as
to the spelling have begun to develop. See
Hannah Wiseman, Untested Waters: The Rise
of Hydraulic Fracturing in Oil and Gas
Production and the Need to Revisit Regulation,
20 FORDHAM ENVTL. L. REV. 115, 115 (2009)
(“[M]uch of this extraction is occurring through …
hydraulic fracturing, which is alternately
described as hydrofracturing or ‘fracing’ ….”);
Hannah Wiseman, Trade Secrets, Disclosure,
and Dissent in a Fracturing Energy Revolution,
111 COLUM. L. REV. SIDEBAR 1, 2 n.5 (2011)
(“There are several types of hydraulic fracturing
(also known as ‘fracking’ or ‘fracing’).
This article will be broken into three
main parts, each focusing on an important
purpose or the provisions of an SUA. Part
One will explore one of the main purposes
of an SUA, which is to address, expand,
and clarify the underlying legal background
7
Matt Micheli, Showdown at the OK Corral –
Wyoming’s Challenge to US Supremacy on
Federal Split Estate Lands, 6 W YO. L. REV. 31,
33 (2006).
8
See Taub v. Houston Pipeline Co., 75 S.W.3d
606, 614–15 (Tex. App.—Texarkana 2002, rev.
denied) (express surface use agreement
governs rights between surface owner and
mineral lessee).
19
that governs the relationship between a
surface owner and mineral owner where no
SUA is executed by the parties. Part Two
will touch on several of the more common
provisions found in SUAs. Finally, Part
Three of this article will explore surface
damages acts enacted across various
jurisdictions and how SUAs can be used to
address the rights and obligations created
under these acts.
A.
Dominance of Mineral
Estate
One of the fundamental principles of
property law is that an owner of a parcel
may sever the land horizontally into surface
and subsurface estates in a conveyance or
reservation so that title to each respective
estate vests in different owners.9 When
such a severance occurs, a surface estate
and mineral estate are created.10 In most
jurisdictions it is well established, under
what has become known as the “dominant
estate doctrine,” that the mineral estate is
the dominant estate, and the surface estate
is the servient estate, such that in the event
of conflict between surface uses by the
mineral owner and surface owner, the
mineral owner has the paramount legal
right.11
While this article is not able to cover
every issue, it is the authors’ intent that this
article will assist both new and experienced
attorneys
and
land
management
professionals in understanding the purposes
of SUAs, common provisions found in
SUAs, how to negotiate and maintain better
relations with the surface owner, and what
to expect in surface damages acts.
Additionally, this article is intended to raise
the attention of the parties seeking an SUA
to anticipate and recognize various issues
that should be addressed in the SUA to
facilitate the interests of both parties and
avoid future conflicts with regard to the use
of the surface estate for oil and gas
exploration, development, and production.
9
Del Monte Mining & Milling Co. v. Last Chance
Mining & Milling Co., 171 U.S. 55, 60 (1898)
(“Unquestionably at common law the owner of
the soil might convey his interest in mineral
beneath the surface without relinquishing his title
to the surface….”).
10
Harris v. Currie, 176 S.W.2d 302, 304 (Tex.
1943) (“The owner has the right to sever his land
into two estates, and he may dispose of the
mineral estate and retain the surface, or he may
dispose of the surface estate and retain the
minerals.”).
In
Louisiana,
although
not
specifically referred to as either the surface
estate or the mineral estate, Louisiana law
provides that the landowner may create basic
mineral rights in his land, including but not
limited to, “the mineral servitude, the mineral
royalty, and the mineral lease.” LA. REV. STAT.
ANN. § 31:16 (2014).
PART ONE: ADDRESSING THE LEGAL
BACKGROUND
One of the fundamental purposes of
an SUA is to address, expand, and clarify
the underlying legal background that
governs the legal relationship between a
surface owner and operator where no SUA
has been established. Before one can
understand what needs to be addressed in
an SUA, the rights and obligations that are
enjoyed without an SUA should be
understood. AN SUA can be used to clarify,
modify and tweak these default rights and
obligations to best suit the needs of the
operator.
11
North Dakota: Hunt Oil Company v. Kerbaugh,
283 N.W.2d 131, 135 (N.D. 1979); Montana:
Hunter v. Rosebud County, 783 P.2d 927, 929
(Mont. 1989); Oklahoma: Indian Territory
Illuminating Oil Co. v. Dunivant, 80 P.2d 225,
233 (Okla. 1938); Louisiana: Rohner v. Austral
Oil Exploration Co., 104 So. 2d 253, 255 (La.
App. 1 Cir. 1958). See Ashby v. IMC Exploration
Co., 496 So. 2d 1334, 1337 (La. App. 3 Cir.
1986) (explaining Louisiana’s mineral servitude).
20
Under the dominant estate doctrine,
the mineral estate is dominant as to all
classes of surface owners, subject to the
limitations described below.12 This includes
persons with a grazing, cotton, wheat, or
other agricultural uses, or lessees for those
purposes, so long as the agricultural lease
was entered into after either (1) the oil and
gas lease was executed, or (2) after the
severance of the mineral estate.13 An
emerging area of the law, however, is
conflict of surface use by a mineral owner
with surface use by one vested with wind
rights, or owning a wind easement.14 This
area is subject to speculation at the current
moment as little case law exists on point,
and some statutory regimes are in
development.15
B.
enjoyment of the surface as the owner of
the dominant estate, such as the rule of
reasonable necessity.17 Under the rule of
reasonable necessity, a surface owner can
prevent a mineral owner from engaging in
an unreasonable or excessive use of the
surface, or recover damages if such a use
Rule of Reasonable
Necessity
Oil and gas operators are most
typically restricted from surface operations
through express provisions in an oil and gas
lease or other written agreement.16
However, a few legal theories exist that
place restrictions on the mineral owner’s
12
See Ernest E. Smith, Article: The Growing
Demand for Oil and Gas and the Potential
Impact Upon Rural Land, 4 Tex. J. Oil Gas &
Energy L. 1, 12 (2008) (“The dominant estate
theory applies to a person with a grazing, cotton,
wheat, or other agricultural lease, as well as to
the landowner himself.”).
13
Id.
14
Id. at 14.
15
See Ernest E. Smith, Wind Energy in Texas,
19 Advanced Oil, Gas & Mineral Law Course 3
(State Bar of Tex. 2001). See generally, Andrew
Campbell, Comment, You Don’t Need a
Weatherman to Know Which Way the Wind
Blows?: An Argument For Offshore Wind
Development in the Gulf Of Mexico, 50 Hous. L.
Rev. 899 (2013).
16
17
Mingo Oil Producers v. Kamp Cattle Corp.,
776 P.2d 736, 741 (Wyo. 1989). See Hurley v.
N. Pac. Ry. Co., 455 P.2d 321, 323 (Mont. 1969)
(holding that the location of a particular facility
must be necessary and convenient to the
operation of the oil and mineral owner).
Smith, supra note 21, at 12.
21
has
already
taken
place.18
Some
jurisdictions recognize this limitation as a
distinct limitation on the dominant estate
theory,19
while
others
include
the
“reasonable necessity” limitation as being
an inherent limitation on the rights granted
under the dominant estate theory itself.20 In
practice, this distinction likely has little
difference.
C
An additional limitation placed on the
dominant
estate
theory
is
the
accommodation
doctrine.
The
accommodation doctrine seeks to balance
the competing interests of the surface
owner’s continued use of the surface with
the necessity of ingress and egress for the
mineral owner.21 The accommodation
doctrine requires that the mineral owner
"reasonably accommodate" or give "due
regard" to the surface owner.22 Most states
apply some variation of the accommodation
doctrine.
Among
these
states
are
23
24
Colorado, New Mexico, North Dakota,25
18
See, e.g., Stephens v. Finley Res., Inc., No.
07-05-0023-CV, 2006 Tex. App. Lexis 2309, at
*3 (Tex. App.—Amarillo Mar. 27, 2006, no pet.)
(mem. op.) (citing Texas cases for the rule of
reasonable necessity); Flying Diamond Corp. v.
Rust, 551 P.2d 509, 511 (Utah 1976) (“The
general rule which is approved by all
jurisdictions that have considered the matter is
that the ownership…of mineral rights in land is
dominant of the owner of the fee to the extent
reasonably necessary to extract the minerals
therefrom.”); Hunt Oil Co. v. Kerbaugh, 283
N.W.2d 131, 134–35 (N.D. 1979) (“This
court…adopted the general rule…as to the
implied rights of the mineral estate owner: ‘…a
grant of mines or minerals gives to the owner of
the minerals the incidental right of entering,
occupying, and making such use of the surface
lands as is reasonably necessary in exploring,
mining,
removing,
and
marketing
the
minerals.’”); Amoco Production Co. v. Carter
Farms Co., 703 P.2d 894, 896 (N.M. 1985)
abrogated in part by McNeill v. Burlington
Resources Oil & Gas Co., 182 P.3d 121 (N.M.
2008) (“[The mineral lessee], is entitled to use
as much of the surface area as is reasonably
necessary for its drilling and production
operations.”). See also Buffalo Mining Co. v.
Martin, 267 S.E.2d 721, 725–26 (W. Va. 1980)
(stating that when a severance deed contains
broad rights for surface use for underground
mining, courts will imply compatible surface uses
that are reasonably necessary to the activity).
19
Accommodation Doctrine
So. 2d 553, 555 (Miss. 1962) (stating that the
Court has set out a rule that a grant of minerals
gives the mineral owner the right to such use of
the surface as is reasonably necessary for
mining); Placid Oil Co. v. Lee, 243 S.W.2d 860,
861–62 (Tex. Civ. App.—Eastland 1951, no writ)
(holding for the mineral owner when it did not
use “more of the land than was reasonably
necessary to do the things it had a right to do
under the lease”).
21
See Getty Oil Co. v. Jones, 470 S.W.2d 618,
622–23
(Tex.
1971)
(explaining
the
circumstances under which a surface owner
deserves an accommodation).
22
Tarrant Cnty. Water Control v. Haupt, 854
S.W.2d 909, 911 (Tex. 1993).
23
See Gerrity Oil & Gas Corp. v. Magness, 946
P.2d at 913 (Colo. 1997) (citing Getty Oil Co.,
470 S.W.2d at 622 and articulating the
accommodation doctrine in Colorado, which has
now been codified in a statutory equivalent).
See Mingo Oil, 776 P.2d at 741.
24
Carter Farms Co., 703 P.2d at 894 (a mineral
lessee is entitled to use as much of the surface
area as is reasonably necessary for its drilling
and production operations) abrogated in part by
McNeill v. Burlington Resources Oil & Gas Co.,
182 P.3d 121 (N.M. 2008); Kysar v. Amoco
20
These states define the dominant estate
theory as granting the mineral owner the implied
right to use so much of the surface as may be
reasonably necessary to produce the minerals.
See, e.g., Union Producing Co. v. Pittman, 146
22
Texas,26 Utah,27 and West Virginia.28 These
states each follow the dominant estate
theory,
but
have
adopted
the
accommodation doctrine in an effort to seek
that each owner, surface and mineral,
should have the right to use and enjoy his
property interest to the highest degree
possible without unreasonably interfering
with the rights of the other.29
The accommodation doctrine has
been adopted in several states through
case law30 and in other states by statute.
Colorado, for example has enacted a
statute under which an operator must
“minimize[e] intrusion upon and damage to
the surface of the land.”31 In order to do so,
the operator must select “alternative means
of operation that prevent, reduce, or
mitigate the impacts of the oil and gas
operations on the surface, where such
alternatives are technologically sound,
economically practicable, and reasonably
available to the operator.”32 The Colorado
statute specifically provides that nothing in
the statutory accommodation doctrine shall
“[p]revent an operator and a surface owner
from addressing the use of the surface for
oil and gas operations in a lease, surface
use agreement, or other written contract.”33
The requirements for invoking the
accommodation doctrine vary slightly by
jurisdiction. In Texas, for example, the
application of the accommodation doctrine
requires the surface owner or surface
lessee to prove three elements: (1) there is
an existing use of the surface, (2) the oil
and gas lessee's proposed use of the
surface will prevent or significantly impair
that existing use of the surface, and (3)
there is a reasonable alternative available to
the oil and gas company.34
Production Co., 93 P.3d 1272, 1278 (N.M. 2004)
(reciting the “general principle of oil and gas law
that” the lessee’s surface rights and servitude
must be exercised with due diligence for the
rights of the surface owner).
25
Hunt Oil Company v. Kerbaugh, 283 N.W.2d
131, 135 (N.D. 1979).
26
The determination of the breadth of
a mineral owner’s right to use the surface is
best described by turning to the cases
which have held the operator’s use of the
surface to be excessive.35 Nevertheless,
there are countless cases where a mineral
owner or his lessee is accused of exceeding
the scope of his implied mineral easement,
including the following examples:36
Getty Oil Co., 470 S.W.2d at 622.
27
Flying Diamond Corp. v. Rust, 551 P.2d 509,
511 (Utah 1976).
28
Buffalo Mining Co. v. Martin, 267 S.E.2d 721,
725–26 (W. Va. 1980).
29
See, e.g., Flying Diamond Corp., 551 P.2d at
511 (“We subscribe to the [accommodation
doctrine] as in harmony with the principle which
we think is sound: that wherever there exist
separate ownerships of interests in the same
land, each should have the right to the use and
enjoyment of his interest in the property to the
highest degree possible not inconsistent with the
rights of the other.”); Buffalo Mining Co., 267
S.E.2d at 725 (expressing the same sentiment
by carrying over principles of easement law).
Id.
33
Id.
34
Getty Oil Co., 470 S.W.2d at 622–23.
35
See Patrick H. Martin and Bruce M. Kramer,
W ILLIAMS & MEYERS, OIL AND GAS LAW § 218.7
(LexisNexis Matthew Bender 2012) (describing
the difficulty in defining the boundaries of
surface use and access afforded to mineral
owners or their lessees).
30
See, e.g., Getty Oil Co., 470 S.W.2d at 619
(adopting the accommodation doctrine in
Texas).
31
32
36
This comprehensive list of excessive surface
use examples was compiled in Patrick H. Martin
COLO. REV. STAT. § 34-60-127 (2013).
23
1.
2.
3.
4.
5.
6.
constructing roads to access
wells in excess of reasonable
needs;37
utilizing more surface than
reasonably necessary for the
full
enjoyment
of
the
minerals;38
utilizing pumping units that
interfere
with
farmerlandowner’s preexisting use
of
automatic
sprinkler
systems;39
choosing location of wells
with complete disregard for
surface owner;40
negligent use of deteriorated
equipment causing damage
from leaking oil;41
taking excessive quantities of
water for secondary recovery
techniques;42
7.
8.
use of the surface to benefit
minerals
underlying
a
43
separate tract of land; and
recent Texas case law has
made it clear that the
accommodation doctrine may
require directional drilling, as
a
reasonable,
industryestablished alternative.44
Louisiana has not specifically
adopted the accommodation doctrine.
However, under a similar rule, Louisiana
holds that the mineral lessee must exercise
its rights with “reasonable regard” for the
landowner. Under this “reasonable regard”
rule, certain existing contrary surface uses
must be accommodated, if practical.45 This
rule does not require a complete balancing
of interests between the mineral owner and
the surface owner. To the contrary,
Louisiana law requires that the surface
owner suffer the lessee’s use of the
property to the extent reasonable or
necessary to the mineral operations.46
and Bruce M. Kramer, W ILLIAMS & MEYERS, OIL
AND GAS LAW § 218.8 (LexisNexis Matthew
Bender 2012).
37
See, e.g., Magnolia Petroleum Co. v. Norvell,
240 P.2d 80 (Okla. 1952).
43
See TDC Engineering, Inc. v. Dunlap, 686
S.W.2d 346, 348 (Tex. Civ. App.—Eastland
1985, writ ref’d n.r.e.) (disallowing lessee from
injecting salt water into a non-productive
leasehold well bore that was produced from offleasehold wells).
38
See, e.g., Humble Oil & Refining Co. v.
Williams, 413 S.W.2d 413 (Tex. Civ. App.—Tyler
1967, writ granted) (building a road, destroying
trees, and rutting the surface created a fact
question for the Court of whether more land was
used than was necessary).
39
44
See Tex. Genco, LP v. Valence Operating
Co., 187 S.W.3d 118, 123–25 (Tex. App.—
Waco 2006, pet. denied) (involving an existing
ash disposal landfill where the mineral operator
was required to directionally drill from an area
adjacent to the landfill to avoid making portions
of the existing landfill unusable for ash waste
disposal).
Getty Oil Co., 470 S.W.2d at 618, 619–20.
40
Reading & Bates Offshore Drilling Co. v.
Jergenson, 453 S.W.2d 853, 855–56 (Tex. Civ.
App.—Eastland 1970, writ ref’d n.r.e.) (holding
that location of a well was unreasonable
because it was chosen with utter disregard for
the surface owner’s property rights).
45
See LA. REV. STAT. ANN. § 31:11 (2014)
(providing that “the owner of land burdened by a
mineral right or rights and the owner of a mineral
right must exercise their respective rights with
reasonable regard for those of the other”)
(emphasis added).
41
Speedman Oil Co. v. Duval County Ranch
Co., 504 S.W.2d 923, 927 (Tex. Civ. App.—San
Antonio 1973, writ ref’d n.r.e.).
42
Arkansas Louisiana Gas Co. v. Wood, 403
S.W.2d 54, 56–57 (Ark. 1966); Sun Oil Co. v.
Whitaker, 483 S.W.2d 808, 811 (Tex. 1972).
46
24
Ashby v. IMC Exploration Co., 496 So. 2d
doctrine.49 However, most of these
jurisdictions
have
adopted
a
reasonableness and negligence standard,
which may provide a defendant surface
owner a claim for relief.50
Wyoming appears to have adopted
some form of the accommodation doctrine,
though there is some disagreement
amongst
commentators.47
Some
commentators have opined that Wyoming’s
adoption of the accommodation doctrine
appeared to function more like a surface
damage
statute
than
a
“true”
48
accommodation doctrine.
For example, in Montana an
operator may locate a facility anywhere it
has a right of use (owns the dominant
estate), as long as such location is
“necessary and convenient to the operation
of the oil and mineral owner,” and is
“reasonable under prevailing conditions.”51
However, as to accommodating the surface
owner, the courts have made it clear that a
surface owner does not have a claim for
relief asserting that a facility placement
works a hardship solely because it could
have been placed elsewhere just as
conveniently.52 Nonetheless, an operator
may be required to accommodate other
reasonable alternatives under applicable
Montana statutes, which require the oil and
gas developer to make a “good faith”53
Illinois,
Oklahoma,
Michigan,
Montana and Kansas, on the other hand,
have not adopted the accommodation
1334, 1337 (La. App. 3 Cir. 1986) (“[Surface
owners] have no right to recover damages for
the diminished use of the land, arising out of [the
lessee’s] reasonable, necessary exercise of its
rights under the mineral lease.”). See also
Robert L. Theriot, Duty to Restore the Surface
(Implied, Express, and Damages), at 4 (2005)
(originally published in LA. MIN. LAW INST. (Spring
2005)) (stating that Louisiana has not
specifically
adopted
the
accommodation
doctrine, but does recognize a similar principle
that the lessee must exercise its rights with
“reasonable regard” for the landowner),
available
at
http://www.liskow.com/PublicationFiles/Theriot%
2020Duty%20to%20Restore%20the%20Surface%
20Article.pdf.
49
See YDF, Inc. v. Schluman, Inc., 136 P.3d
656, 659 (Okla. 2006) (applying the Oklahoma
Surface Damages Act instead of adopting a
broader accommodation doctrine); Rorke v.
Savoy Energy, LP, No. 245317, 2004 Mich. App.
LEXIS 1266, at *3–4 (Mich. Ct. App. May 18,
2004) (refusing to address the applicability of the
accommodation doctrine on procedural grounds
in the unpublished opinion).
47
Michelle Andrea Wenzel, Comment, The
Model Surface Use Act and Mineral
Development
Accommodation
Act:
Easy
Easements for Mining Interests, 42 AM. U. L.
REV. 607, 639 n.141 (1993). See Mingo Oil
Producers v. Kamp Cattle Corp., 776 P.2d 736,
741 (Wyo. 1989) (stating in dicta that the mineral
estate is dominant and entitled to use of the
surface estate as “reasonably necessary” to the
production and storage of minerals).
50
See, e.g., Phoenix v. Graham, 110 N.E.2d
669, 672 (Ill. App. 1953) (discussing a claim of
relief where an operator fails to use the
reasonable care of an ordinary prudent
operator).
51
Hurley v. N. Pac. Ry. Co., 455 P.2d 321, 323
(Mont. 1969).
52
48
See, e.g., Wenzel, supra note 56, at 639
n.141 (“Wyoming’s ‘accommodation doctrine’
functions more like a surface damage statute
than like the accommodation doctrine.”).
53
Id.
See Part (3)(I)(C), infra, for a discussion of the
requirement to attempt good faith negotiations
with the surface owner across the various
surface damages acts.
25
attempt to negotiate an agreement with the
surface owner.54
E.
Likewise, Oklahoma does not
recognize the accommodation doctrine.
Instead, the legislature has enacted the
Oklahoma Surface Damages Act55 to
provide a means of balancing the conflicting
interests of mineral and surface owners.
Also, as discussed in more detail below,
Kansas
does
not
recognize
the
dominant/servient distinction, and because
the surface and mineral estates are treated
with equal dignities, there is no need to
impose an accommodation between the two
estates.
D.
Kansas Has Not Adopted
the
Dominant
Estate
Theory
In contrast to the jurisdictional
approaches discussed above, Kansas has
not adopted, and does not recognize the
distinction between dominant and servient
estates as they pertain to oil and gas
leases. In the case of Rosticil v. Phillips
Petroleum Co., the Supreme Court of
Kansas ruled that the implied right to use
the surface under a lease does not create
an “easement.”59 The court asserted that
while an easement is a grant that creates a
dominant estate, an oil and gas lease
creates something comparable to “a
landlord and tenant relationship” under
which the lessee does not own a dominant
estate.60 However, there is some debate as
to whether the Rosticil decision implies that
the owner of a severed mineral interest who
acquired his interest through grant or
reservation (as opposed to a lessee
operating under an oil and gas lease) may
actually own a dominant estate. If that is the
case the mineral owner may have the
capacity to grant surface use rights
additional to those contained in a standard
oil and gas lease. Therefore, an operator
leasing from a severed mineral interest
owner in Kansas may want to include
Negligence as a Method of
Limiting Dominant Estate
Theory
An additional doctrine limiting the
mineral owner’s right to interfere with uses
of the surface by the surface owner is tort
liability for injury caused by negligent
operations.56 The Texas Supreme Court
established an oil and gas company's
liability for negligent injury to the land as
early as 1961.57 In that case, the Texas
Supreme Court held that a lessee was liable
for negligently allowing salt water to pollute
fresh water sources.58
59
Brown v. Lundell, 334 S.W.2d 863, 865 (Tex.
App.—Waco 1961, no writ).
Rosticil v. Phillips Petrol. Co., 502 P.2d 825,
826 (Kan. 1972) (holding that the lessee, under
an oil and gas lease, does not own a dominant
easement and opining that “[t]he obvious intent
of the parties under [an oil and gas lease] is that
the licensed privileges of the lessee are to run
hand in hand with those reserved to the lessor
with neither interfering more than need be with
the continuing uses of the other – the one for
exploration, production and transportation of the
minerals, and the other for the pursuit of
agriculture”).
58
60
54
Surface Owner Damage and Disruption
Compensation Act, MONT. CODE ANN. § 82-10504 (2013).
55
OKLA. STAT. tit. 52, §§ 318.1–318.9 (2013).
56
Leon Green, Hazardous Oil and Gas
Operations: Tort Liability, 33 TEX. L. REV. 574,
576–78 (1954); McNeill v. Burlington Res. Oil &
Gas Co., 182 P.3d 121, 129 (N.M. 2008).
57
Id.
26
Id.
language granting the lessee all of the
mineral owner’s rights to use the surface.61
rights and relationship between a surface
owner and operator in the absence of an
SUA.
Although Kansas does not recognize
the dominant/servient distinction, it does
recognize an implied right for a lessee to
make reasonable use of the surface.62 This
implied right of reasonable use includes the
right of ingress and egress over the surface
of the land, and has been extended to
owners of severed mineral interests.63
However, if a lessee engages in continuous
unreasonable use outside the parameters
set in the oil and gas lease, damages may
be awarded up to and including forfeiture of
the lease.64 In practice, because standards
such as “continuous unreasonable use” are
inherently ambiguous, specific and detailed
surface use provisions should be, and often
are, included in each Kansas oil and gas
lease or SUA.
F.
PART TWO: COMMON SUA PROVISIONS
Over the past century, oil and gas
leases have become largely standardized in
form and content. SUAs, on the other hand,
widely vary from region to region and from
operator to operator. SUAs can be as short
as a couple pages, or lengthy complex
volumes. Adding to the perplexity, very few
cases have been published interpreting the
language of SUAs. Therefore, SUAs should
be clearly drafted and thoroughly examined
prior to being executed by mineral owners
or operators. The following is a discussion
of some of the more common provisions
found in SUAs.
I.
Conclusion
In summation, most states have
adopted some form of the dominant estate
theory, or other similar legal theory,
affording the mineral owner or mineral
lessee some rights to surface access and
surface use, over the objection of the
surface owner. However, these rights are
not absolute, as they are accompanied by
important limitations. While the effect of
these limitations range from minor to
substantial, they can and do, in practice,
limit operators’ exploration, production, and
development activities. It is important to
understand these rules, as they define the
When drafting an SUA, it is
important to make sure that all interested
parties are included. Because an SUA deals
with surface rights, the surface owner of the
subject tract will obviously need to be
included in the negotiation and signing of an
SUA. However, it is important to note that
surface owners come in many varieties. The
typical SUA will be negotiated between (1)
an operator, and (2) a surface owner with
no interest in the underlying minerals. As
explained in Part One of this article, while
the owner of the surface in a severed estate
has no interest in the underlying minerals,
the purpose of an SUA is to ease the
tension between the mineral lessee and the
surface owner. Therefore, surface owners of
a severed estate are the primary target of
an SUA.
61
1 David E. Pierce, KANSAS OIL AND GAS
HANDBOOK 12-11 (Kansas Bar Association eds.,
1986).
62
Thurner v. Kaufman, 699 P.2d 435, 439 (Kan.
1985).
If the minerals have not been
severed from the surface estate, the surface
use provisions will typically be found
exclusively in the respective oil and gas
lease. In this situation, an SUA may be
entered into by the parties, but such an
63
Mai v. Youtsey, 646 P.2d 475, 480 (Kan.
1982); Brooks v. Mull, 78 P.2d 879, 882 (Kan.
1938).
64
Parties
Youtsey, 646 P.2d at 439–41.
27
agreement is generally unnecessary
because the provisions would be redundant.
Modern oil and gas leases negotiated with
owners of non-severed estates typically
contain most of the clauses found in an
SUA. However, one important exception to
this rule is the development of a
hydrocarbon formation that does not
underlie the drill site tract. Such
development would require the operator to
utilize one surface tract for surface
operations with the intention of producing
minerals only from one or more neighboring
mineral tracts. This causes an issue for the
mineral lessee because, as described in
Part One of this article, a mineral lessee
only has an implied easement to use the
surface estate overlying his own minerals
and in the production of those minerals. To
develop a formation that does not underlie
the drill site tract would require additional
rights from the owner of the surface on the
drill site tract, which would typically be by
execution of an SUA or a subsurface
easement. A discussion of subsurface
easements is beyond the scope of this
article.
formation.67 Therefore, it is entirely feasible,
and not uncommon, for the drill pipe and
drain hole for a horizontal well to travel
laterally outside a surface parcel before
hitting the target hydrocarbon formation.
Developing an adjacent tract from a
drill site has largely become a practical
issue only in recent decades. The concept
of drilling a directional or horizontal well has
been around since as early as 1929.65
However, the technology required for the
commercial viability of horizontal drilling did
not begin to develop until the late 1980s.66
The advent of sophisticated hydraulic
fracturing technology caused a rapid
proliferation of horizontal drilling in both oil
and gas formations. Horizontal wells are
initially drilled vertically, and then at a predetermined point, the drill stem deviates and
proceeds horizontally into the targeted
68
Utilizing one tract for surface
operations to benefit minerals underlying a
neighboring tract causes an issue because
the implied surface easement and the usual
express easements are limited to surface
use as is reasonably necessary for
exploration, development, and production
on the premises described in the deed or
lease.68 In other words, the mineral lessee
does not have an implied easement to use
the surface of a tract of land to benefit only
minerals that underlie other mineral
tract(s).69 However, a provision clearly
providing for an express easement to use
the surface in connection with operations
underlying only other premises is valid.70 As
67
Patricia A. Moore, Horizontal Drilling—New
Technology Bringing New Legal and Regulatory
Challenges, 36 Rocky Mtn. Min. L. Inst. §
15.01[1] (1990).
Patrick H. Martin and Bruce M. Kramer,
W ILLIAMS & MEYERS, OIL AND GAS LAW § 218.4
(LexisNexis Matthew Bender 2012).
69
See id. (“Absent [an] express provision,
clearly the use of the surface by a mineral owner
or lessee in connection with operations on other
premises constitutes an excessive use of his
surface easements.”). See also Dick Prop., LLC
v. Paul H. Bowman Trust, 221 P.3d 618, 621
(Kan. Ct. App. 2010) (discussing a restriction
that the surface owner is the proper party to
enter into a saltwater disposal well when water
from off premises is to be disposed and that the
mineral owner’s right to dispose of saltwater is
limited only to salt water produced from the
leased tract).
65
U.S. DEPT. OF ENERGY, ENERGY INFO. ADMIN.,
DRILLING SIDEWAYS—A REVIEW OF HORIZONTAL
W ELL
TECHNOLOGY
AND
ITS
DOMESTIC
APPLICATIONS 7 (April, 1993).
66
70
See Bruce M. Kramer & Patrick H. Martin, THE
LAW OF POOLING AND UNITIZATION § 20.06[1]
(LexisNexis, 3rd ed. 2012). See also Pittsburg &
Midway Coal Mining Co. v. Shepherd, 888 F.2d
Id.
28
discussed later in this article, this issue can
be cured by negotiating an SUA between
the mineral lessee and the owner of the
surface tract to establish an express
easement in the mineral lessee for this
exact use. As an example of such provision,
the following may appear after enumerating
the surface easements granted:
surface owner may have a pre-existing
surface lease with a hay farmer who makes
his income from hay harvested from the
surface estate.
Under the dominant estate doctrine,
the mineral estate is dominant as to all
classes of surface owners, subject to the
limitations described in Part One of this
article.72 This includes persons with a
grazing, cotton, wheat, or other agricultural
uses, or lessees for those purposes, so long
as the agricultural lease was entered into
after either (1) the oil and gas lease was
executed, or (2) after the severance of the
mineral estate.73 However, in many
jurisdictions the mineral lessee will be liable
to a surface lessee such as a farmer for
financial loss suffered due to loss of use of
his surface leasehold interest.74
. . . and any and all other
rights
and
privileges,
necessary,
useful,
or
convenient
to
or
in
connection with operations
conducted
by
lessee
thereon or on
any
neighboring land.71
A final category of surface occupant
that will be explored in this article is the
tenant or surface lessee. When obtaining an
SUA, it is important to consider whether or
not the surface owner has a tenant or other
surface lessee who may have rights that
predate the mineral lease or even the
mineral reservation. For example, the
Therefore, it is highly suggested that
surface tenants be included in the
negotiation and execution of an SUA. In an
SUA pertaining to a grazing or farming
tenant, a vital portion of the agreement will
discuss the particular expected surface
obstructions, including the drill pad and
roads to be constructed, and the parties will
need to come to an agreement on
measurement of damages that will be paid
due to loss of valuable farmland. However,
in this case, the SUA should also include
the surface landlord, as it is possible for the
surface lease to expire prior to the
expiration of the respective mineral lease.
1533, 1536 (11th Cir. 1989) (“[H]ere there are
specific grants of rights to use the surface of
[lessor’s] property in connection with mining coal
from other lands….Thus the [general rule is] not
applicable in the construction of the conveyance
in question here.”); Colburn v. Parker & Parsley
Dev. Co., 842 P.2d 321, 325–26 (Kan. Ct. App.
1992) (discussing disposal of salt water from
another tract); Kysar v. Amoco Production Co.,
93 P.3d 1272, 1273 (N.M. 2004) (discussing the
effect of Communitization Agreements on the
rights of the mineral owner); Miller v. Crown
Cent. Petrol. Corp., 309 S.W.2d 876, 878–79
(Tex. Civ. App.—Eastland 1958, writ dism’d by
agr.) (discussing the effect of pooling); Flanagan
v. Stalnaker, 607 S.E.2d 765, 771 n.7 (W. Va.
2004) (quoting a lease with an express
easement granted).
72
See Ernest E. Smith, The Growing Demand
for Oil and Gas and the Potential Impact Upon
Rural Land, 4 TEX. J. OIL GAS & ENERGY L. 1, 12
(2008).
73
74
Id.
See Anderson-Prichard Oil Corp. v. McBride,
109 P.2d 221, 224 (Okla. 1940) (holding that an
agricultural lessee was entitled to recover
damages under 64 OKLA. STAT. ANN. § 288 for
loss in use or rental value of land and injury to
crops).
71
Patrick H. Martin and Bruce M. Kramer,
W ILLIAMS & MEYERS, OIL AND GAS LAW § 218.4,
n.1 (LexisNexis Matthew Bender 2012).
29
Another essential party that needs to
be involved in the negotiation and signing of
an SUA is the operator. As the party
charged with actually operating the
leasehold,
the
operator’s
proposed
development plan, proposed well locations,
drilling and production timeline, and method
of development are the main subjects of an
SUA. Non-operating working interest
owners may also need to be included as a
party to an SUA, depending on the
language found in the associated joint
operating agreement or farmout agreement
governing the parties. Although nonoperators do not have a direct interest in
surface access, they may be responsible for
sharing
the
costs associated
with
compensating the surface owner. Therefore,
whether non-operators should be included
in SUAs turns largely to the language found
in the instrument that defined their nonoperating interest.
lease. In most jurisdictions, the law implies
certain covenants in every oil and gas lease
including, but not limited to, the following:
(1) the covenant to develop the lease, which
may include an obligation to drill an initial
well but is more usually defined as the
obligation to develop the lease after
production has been acquired, and (2) the
covenant to protect the lease, which
includes the obligation to protect against
drainage and not to depreciate the lessors'
interest.77
For various reasons, operators
sometimes agree to an SUA that
significantly affects his ability to develop the
leasehold. For example, a highly restrictive
well-location or well pad quantity restriction
may be agreed to by the mineral lessee in
exchange for much greater surface water
use rights for the operations. Likewise, a
highly restrictive SUA may be agreed to in
exchange for surface access and storage
facility construction rights on the tract, and
for the benefit of an entire unit.
Some commentators75 also believe
that circumstances exist where the mineral
lessee will need to obtain a ratification of the
SUA by the mineral owners and nonexecutive mineral owners for two primary
reasons. First, if a perpetual duration is
sought for the SUA, the mineral owner will
need to agree to the surface-use restrictions
described in the SUA that will outlive the
lease owned by the mineral lessee.76
Second, commentators argue that mineral
owners and royalty owners should ratify an
SUA, because SUAs that significantly affect
the mineral lessee’s ability to develop the
mineral estate may have implications on the
mineral lessee’s implied duties under the
In each of the above examples, a
mineral lessee may benefit from agreeing to
highly restrictive terms in an SUA. 78
However, the examples given above can
considerably increase the cost of drilling
additional wells. For example, in order to
fully develop the mineral estate, this may
require costly directional drilling techniques.
In Colorado, the legislature determined that
$87,500 is the baseline amount to use as a
default for the increased cost per well for
directional drilling where a vertical well
75
Christopher G. Hayes, Surface Use
Agreements: Severed Minerals, Split Estates,
Rights of Access, and Surface Use in Mineral
Extraction Operations, Paper No. 15, Page No.
2–3 (Rocky Mt. Min. L. Fdn. 2005).
77
Amoco Prod. Co. v. Alexander, 622 S.W.2d
563, 567 n.1 (Tex. 1981).
78
See Hayes, supra note 84, at 2–3 (discussing
surface use agreements that significantly affect
the mineral owner or mineral lessee’s ability to
fully develop the estate).
76
See id. (describing the benefits to the
involvement of a mineral owner in the
participation of a surface use agreement).
30
would have effectuated
development plan.79
a
particular
of prohibiting the operator’s ability to
reasonably
develop
the
leasehold.
Therefore, in an abundance of caution, it is
suggested that an attorney be consulted
regarding the restrictions, because it may
be in the operator’s best interest to have the
mineral and royalty owners join in or ratify
the SUA.
This additional cost can cause
conflict between the mineral lessee and the
mineral and royalty owners, because as a
general rule, “no obligation rests upon (the
lessee) to carry the operations beyond the
point where they will be profitable to him
even if some benefit to the lessor will result
from them.”80 However, included in the
implied covenant to develop the leasehold is
the covenant to continue development with
reasonable diligence until a sufficient
number of wells are drilled to reasonably
develop the premises for oil and gas.81
II.
Property Description
As with any contract or instrument
concerning real property, it is of utmost
importance to ensure that an SUA includes
a legally adequate description of the land
that complies with the applicable statute of
frauds. An instrument which does not
ascertain a legally adequate description
is fatally
defective,
being
void
for
uncertainty.82 A property description is
legally sufficient if the writing furnishes
within itself, or by reference to some other
existing writing, the means or data by which
the particular land may be identified with
reasonable certainty.83
For this reason, it is best to obtain consent
by the mineral and royalty owners to the
SUA. It is likely that most operators will only
agree to SUAs that are plainly reasonable
under the circumstances and that fall within
the duty of care of a reasonably prudent
operator. However, if an operator is faced
with a significantly restrictive SUA, these
restrictive provisions may ride the fine line
Generally speaking, the best means
of describing land is by section, township,
and range in Public Land Survey System
jurisdictions84 (frequently referred to as the
Jeffersonian System85), and by metes and
79
COLO. REV. STAT. § 24-65.5-103.7(1)(a). See
also Zeiler Farms, Inc. v. Anadarko E & P Co.
LP, No. 07-cv-01985-WYD-MJW, 2010 U.S.
Dist. LEXIS 76670, at *9 (D. Colo. July 1, 2010)
(discussing the additional costs a mineral lessee
bears by drilling a directional well to decrease
the surface area occupied by the wells).
82
Meadow River Lumber Co. v. Smith, 1 S.E.2d
169, 171 (W. Va. 1939). However, in some
states a surface use agreement may not fall
within the purview of the statute of frauds. For
example, in Washington, the statute of frauds
does not apply to oil and gas leases. See Walla
Walla Oil, Gas & Pipe Line Co. v. Vallentine, 174
P. 980, 981 (Wash. 1918) (holding that an oil
and gas lease establishes a mere chattel
interest which is not within the statute of frauds).
80
Brewster v. Lanyon Zinc Co., 140 F. 801, 814
(8th Cir. 1905). See 2 THE LAW OF OIL AND GAS
LEASES § 16.02 (2013) (discussing the implied
covenant to develop the leasehold and the
limitations to that duty).
81
Waggoner Estate v. Sigler Oil Co., 19 S.W.2d
27, 29 (Tex. 1929); Cole Petrol. Co. v. U.S. Gas
& Oil Co., 41 S.W.2d 414, 416 (Tex. 1931); New
State Oil & Gas Co. v. Dunn, 182 P. 514, 515
(Okla. 1919); Howerton v. Kansas Natural Gas
Co., 108 P. 813, 813–14 (Kan. 1910); Mountain
States Oil Corp. v. Sandoval, 125 P.2d 964, 967
(Colo. 1942).
83
AIC Management v. Crews, 246 S.W.3d 640,
645 (Tex. 2008).
84
Flygare v. Brundage, 302 P.2d 759, 761–62
(Wyo. 1956).
85
For more information concerning the
establishment of the “rectangular survey system”
31
bounds in other jurisdictions.86 Metes and
bounds descriptions are not a legal
necessity though, as long as enough
information or data is included in the
description so that a person familiar with the
area can locate the premises with
reasonable certainty.87 Jurisdictions vary as
to the sufficiency of a description limited
only to a permanent county parcel
identification number. Generally, however,
referencing the permanent county parcel
identification number along with an acreage
amount is sufficient description for the
purposes of complying with the statute of
frauds.88
to be paired with other descriptive factors to
satisfy the statute of frauds.91 For example,
pairing the specification of ownership with
the size of the premises,92 or the location of
the premises93 provides a much better case
for validity under the statute of frauds.
Similarly,
describing
the
real
property in terms of general locality is
generally insufficient to satisfy the statute of
frauds.94 For example, a designation of the
acreage or reference to street address
alone is likely insufficient. On the other
hand, reference to the lot and block number
Lewis, 12 S.W.2d 719, 721 (Mo. 1928) (holding
that describing the land as “farm of T. C. Shy”
was an insufficient legal description).
A common mistake in dealing with
contracts that pertain to real property, as
opposed to conveyancing instruments, is
that parties may deem it sufficient to
describe the land by specification of
ownership.89 For example, parties to a
contract may simply describe the property
as “the surface estate owned by John Doe.”
However, a specification of ownership as
the principal descriptive element, is likely
not sufficient to satisfy the statute of
frauds.90 Specification of ownership needs
91
72 AM. JUR. 2D Statute of Frauds § 235
(2013).
92
Moore v. Exelby, 281 S.W. 671, 674 (Ark.
1926).
93
Peterson v. Bray, 83 A.2d 198, 199–200
(Conn. 1951) (holding a legal description valid
where it referenced both the specification of
ownership as well as stating “her stone
residence and grounds at Sasqua Hills, East
Norwalk, Connecticut”); Coates v. Lunt, 96 N.E.
685, 686–87 (Mass. 1911) (finding the legal
description valid where the specification of
ownership was paired with “store number 32
Market Square which I own”); Huot v. Janelle, 56
A.2d 639, 640–41 (N.H. 1948) (finding a legal
description valid where the specification of
ownership was paired with “my house at 488490 Bartlett Street, in said Manchester”).
established in 1796 by Congress in the National
Land Act, see National Land Act, ch. 29, 1 Stat.
464 (1796); 43 U.S.C. 52 (1986).
86
Helmik v. Pratt, 139 A. 559, 561 (Md. 1927);
Desmarais v. Taft, 97 N.E. 96, 97 (Mass. 1912);
Keator v. Helfenstein Park Realty Co., 132 S.W.
1114, 1114–15 (Mo. 1910).
87
Nguyen v. Yovan, 317 S.W.3d 261, 267 (Tex.
App.—Houston [1st Dist.] 2009, pet. denied).
94
See Barber v. Stewart, 90 N.Y.S.2d 607, 609
(N.Y. App. Div. 1949) (“Premises: On South
Side of Turner Land, [Lane] Loudonville, N.Y.,
Town of Colonie, County of Albany, New York
on lot 150’ wide and 107’ deep with dwelling
thereon” deemed insufficient); McMurtry v.
Hodges, 278 S.W. 866, 867–68 (Tex. Civ.
App.—Fort Worth 1925, no writ) (“214 acres in
Wichita county, and being the same 214 acres
that R. L. McMurty inspected, price $150 per
acre, total $32,100” deemed insufficient).
88
McGee v. Tobin, No. 04 MA 98, 2005 Ohio
App. Lexis 2021, at *2 (Ohio Ct. App. 2005).
89
See 72 AM. JUR. 2D Statute of Frauds § 235
(2013) (citing cases in which land description by
specification of ownership was insufficient).
90
Rundel v. Gordon, 111 So. 386, 389–90 (Fla.
1927) (holding that a description of “your
property” is insufficient for the purposes of
complying with the statute of frauds); Shy v.
32
in a subdivision are generally held
sufficient.95 However, a writing which
describes the land by lot and block, but fails
to specify or to indicate in any way the map
or plat according to which the description is
made is generally defective, unless by wellunderstood custom there is an implied
reference to a particular map or plat that is
on file.96 Finally, a contract pertaining to real
property is unenforceable under the statute
of frauds if it provides only that the
boundaries will be determined upon
agreement, or subject to a subsequent
survey and plat.97
duration of the agreement. Over the last
century, the industry has created a standard
durational framework for oil and gas leases,
being the designation of a primary term for a
specific number of years, and the
designation of a secondary term, typically
reading "and as long thereafter as oil, gas
or other minerals are produced from said
land."99
There is no such industry standard
for the duration of a surface use agreement.
The possibilities are practically endless.
Below are some temporal durations the
authors have seen:
In
conclusion,
an
agreement
pertaining to real property is only as good
as its legal description. Even though the
legal description in an SUA will not cause a
title failure, particular care should be placed
in drafting the description of the subject
surface tract. Failure to do so could render
the SUA void.
1.
2.
3.
4.
5.
6.
III.
Duration of the Agreement
One of the most fundamental
clauses in an oil and gas lease is the
habendum clause, which sets the duration,
or life, of the lease.98 Similarly, one of the
most important terms in an SUA defines the
7.
95
72 AM. JUR. 2D Statute of Frauds § 239
(2013).
8.
specified term of years;
life of the oil and gas lease;
life of the oil and gas lease,
plus a set amount of time;
life of a unit;
life of the unit, plus a set
amount of time;
life of the oil and gas
lease/unit, plus life of any oil
and gas lease/unit entered
into by lessee within a year
thereafter;
later of termination of the oil
and gas lease, or completion
of
reclamation
and
restoration of the surface;
and
perpetual.
Setting the duration of an SUA as a
specified number of years is not
recommended as the SUA would expire
while the oil and gas lease could still be in
effect. On the other hand, defining the
duration as a perpetual burden on the
surface owner is likely to be difficult to
negotiate. Setting the duration as being
based in some way on the life of the oil and
gas lease or a particular unit is the most
practical. The addition of a set amount of
time after the expiration of the oil and gas
96
Reed v. Siler, 439 S.W.2d 466, 467 (Tex. Civ.
App.—Houston [14th Dist.] 1969, no writ).
97
72 AM. JUR. 2D Statute of Frauds § 239; Safe
Deposit & Trust Co. of Pittsburg v. Diamond
Coal & Coke Co., 83 A. 54, 56 (Pa. 1912);
Ensminger v. Peterson, 44 S.E. 218, 219–20
(W. Va. 1903).
98
See Bruce Kramer, The Temporary Cessation
Doctrine: A Practical Response to an Ideological
Dilemma, 43 BAYLOR L. REV. 519, 519 n.1
(1991) (discussing the habendum clause and
Texas’s rule for fee simple determinable status
for leases in the secondary term).
99
33
See id.
real property.102 In the absence of clear
terms of duration, it is assumed that the
conveyance is of fee title.103 However,
agreements, such as an SUA, are not
conveyances but are covenants. A covenant
is an agreement between two or more
individuals to do or refrain from doing
something.
Covenants
are
typically
“personal covenants,” meaning that they
only bind the parties who sign the
agreement and will not bind their
successors in interest.104 A real covenant,
however, is said to “run with the land,”
meaning it will bind the heirs and assigns of
the covenanting parties.105 A covenant is
considered to run with the land if, (1) it
touches and concerns the land, (2) it relates
to a thing in existence or specifically binds
the parties and their assigns, (3) it is
intended by the original parties to run with
the land, and (4) the successor to the
burden has notice.106
lease or a particular unit can be useful to
allow for the removal of the operator’s
equipment from the land, as well as
plugging and reclamation activities. The
option to continue the life of the SUA upon
the recording of an additional oil and gas
lease or a particular unit within a year gives
the operator the chance to enter into an
additional oil and gas lease while
guaranteeing continuing operations under
the same surface terms.
The general rule is that oil and gas
leases are indivisible by nature, meaning
that production from any part of the lease
(including pooled acreage) will keep the
lease in effect through the secondary
term.100 However, this can be modified by
the inclusion of a “Pugh clause,” which
operates to release that portion of the
acreage which is not being produced, those
depths that are not being produced, or both,
upon the expiration of the primary term of
the oil and gas lease.101 When drafting an
SUA, if the duration of the agreement is tied
to an underlying oil and gas lease, the
possible existence of a Pugh clause should
be addressed. For example, the draftsman
should tie the expiration of the SUA to the
expiration to the “final expiration of the
entire acreage and all depths covered by
the oil and gas lease covering the Subject
Land,” rather than simply stating that the
SUA “shall terminate on the termination of
the oil and gas lease.”
102
See Stephens Cnty. v. Mid-Kansas Oil & Gas
Co., 254 S.W. 290, 294 (Tex. 1923) (discussing
cases declaring a number of instruments as
conveyances).
103
As for a statement of the rule in Texas, see
TEX. PROP. CODE ANN. § 5.001 (West 2013).
104
See Fallis v. River Mt. Ranch Prop. Owners
Ass'n, No. 04-09-00256-CV, 2010 Tex. App.
LEXIS 5152, at *24 (Tex. App.—San Antonio
July 7, 2010, no pet.) (“Unlike a personal
covenant, however, real covenants run with the
land, binding the heirs and assigns of the
covenanting parties.”).
Most instruments dealt with in oil
and gas title, such as deeds, assignments,
and oil and gas leases, are conveyances of
105
Inwood N. Homeowners' Ass'n, Inc. v. Harris,
736 S.W.2d 632, 635 (Tex. 1987).
106
Id.; Montfort v. Trek Res., Inc., 198 S.W.3d
344, 355 (Tex. App.—Eastland 2006, no pet.);
Raman Chandler Props., L.C. v. Caldwell's
Creek Homeowners Ass'n, Inc., 178 S.W.3d
384, 391 (Tex. App.—Fort Worth 2005, pet.
denied).
100
Shown v. Getty Oil Co., 645 S.W.2d 555, 560
(Tex. App.—San Antonio 1982, writ ref’d).
101
Friedrich v. Amoco Production Co., 698
S.W.2d 748, 752 (Tex. App.—Corpus Christi
1985, writ ref’d n.r.e.).
34
For the purposes of an SUA, where
the SUA itself or a memorandum is
recorded, the essential focus is going to be
whether the parties intended the covenant
to run with the land. One effective way to
evidence this intent in an instrument such
as an SUA is to include the following words
after describing the parties to be bound by
the
agreement:
“[party
name],
its
successors, heirs and assigns.”107 However,
by far the most common and iron-clad
method of ensuring the SUA will run with
the land is to include an “Inurement Clause”
in the agreement, such as the following:
IV,
Payment for Proposed Activities
Central to any SUA is payment by
the operator to the surface owner for use of
the surface estate. Over the last century,
the advent and progression of the energy
era, robust in business negotiations
involving numerous landowners per well,
necessitated
the
formation
of
a
comprehensive and standardized set of
forms for leasing land.108 One such standard
oil and gas lease form is known as the
“Producers 88,” and has many variants
depending on the development plans and
jurisdiction.109 These oil and gas lease
forms have been key to developing a
standard landowner compensation scheme,
including royalty, bonus, and rentals.110
These forms of pecuniary consideration
have become so well ingrained in the oil
and gas business that they are firmly
expected by landowners in an oil and gas
lease.111
All covenants, agreements,
warranties, representations,
and conditions contained in
this Agreement shall bind
and inure to the benefit of the
respective parties to this
Agreement, their personal
representatives, successors,
heirs and assigns. This
Agreement,
and
its
covenants and restrictions,
shall run with the land.
However, when it comes to SUAs,
no such industry standard has developed. In
practice, the authors have seen a large
variety of schemes for compensating
surface owners. The industry terminology
for compensation varies from jurisdiction to
jurisdiction, using terms such as damages,
compensation, or rentals. A few of the most
common of these compensation schemes
Duration of the agreement is an
important issue to address in an SUA, and
provisions pertaining to its duration should
be carefully drafted to ensure that the SUA
does not expire before the operator is
finished developing the leasehold and
plugging procedures. Additionally, an
inurement clause should be included in the
SUA to ensure that the SUA will survive
assignments, quitclaims, probates, and
other conveyances.
108
See Earl A. Brown, Earl A. Brown, Jr. &
Lawrence T. Gillaspia, THE LAW OF OIL AND GAS
LEASES § 18.02 (LexisNexis Matthew Bender, 2d
ed. 2012) (setting out selected oil and gas lease
forms used in different areas and states).
107
109
See Day & Co. v. Texland Petrol., Inc., 786
S.W.2d 667, 669 (Tex. 1990) (discussing the
executive right as a property interest); Pan
American Petrol. Corporation v. Cain, 355
S.W.2d 506, 510–11 (Tex. 1962) (holding that
because the reservation of the executive right
did not include the words “heirs and assigns,” or
similar language, that the right did not survive
the grantor’s death).
Id.
110
See Ervin, The Bonuses, Minimum Royalties
and Delay Rentals, 5 SW . LEGAL FDN. OIL & GAS
INST. 529, 557 (1954).
111
See Schlittler v. Smith, 101 S.W.2d 543,
544–45 (Tex. 1937) (discussing the words
“royalty,” “bonus,” and “rentals” in the context of
oil and gas business and conveyancing).
35
will be discussed below, as well as a short
discussion of the “pros and cons” of each.
Additionally, depending on the jurisdiction,
an SUA may overlap statutory or common
law
provisions
aiming
to
provide
compensation to the surface owner for oil
and gas development.
primary advantage of using a liquidated
damages provision is that it allows damages
to become extremely foreseeable. The
disadvantage, however, is that actual
damages to the surface may be less than
the predetermined amount provided for in
the SUA. While a liquidated damages
provision cannot be set at an excessive
level, a party generally is bound to pay the
liquidated amount even where the actual
damages are less.113
Before we discuss any particular
compensation scheme, an important
drafting consideration will be discussed. It is
recommended that all SUAs contain a
clause limiting compensation to the
landowner for use and damage to the
surface estate to that which is provided for
in the SUA. Many states provide for surface
use compensation by oil and gas operators
to surface owners, either by statute,
regulation or common law. A clause
providing that the compensation described
in the SUA is exclusive will aim to waive the
damages and compensation provided for in
the statute or common law. This is crucial
because otherwise the surface owner could
potentially make a claim for the
compensation provided for in the SUA in
addition to those provided for by statute or
common law. This double recovery could
destroy one of the main purposes of an
SUA: making compensation foreseeable to
avoid conflict and litigation.
Some operators elect to pay a
royalty to the landowner, typically at or
around 2.5%. This payment scheme is quite
common in Colorado. The benefit to a
royalty scheme is that the operator is not
required to pay any surface costs until
actual production is achieved. Additionally,
this payment scheme can be great for
maintaining positive relations with the
surface owner because it gives the surface
owner the same incentive as the operator
and mineral owners, insofar as they all
stand to benefit from additional drilling and
increased production. However, paying a
surface royalty also comes with drawbacks.
For example, depending on the level of
production and the chosen royalty
percentage, a surface royalty could very
well compensate the landowner much more
than its actual value, and more than
anticipated.
The most common compensation
scheme found in SUAs is the liquidated
damages provision. Here, the parties agree
that the surface owner will be paid a set
amount, whether the actual damages are
more or less. This predetermined rate could
be based on an amount per well, per square
footage, per rod, or per activity-type.112 The
Some operators elect to pay a onetime bonus to the surface owner as
compensation for surface use. Typically this
bonus is combined with another scheme,
such as a bonus plus royalty, or bonus plus
annual rentals. In North Dakota, for
112
One particular New Mexico “Surface
Agreement” seen by the Authors includes the
maximum size for well location pads, tank
batteries, and roads. It also includes a provision
that should the operator exceed the size
limitations of the foregoing, he will further
compensate the landowner “an amount equal to
the square footage of the surface used outside
the confines of the authorized area times $0.15
per square foot.”
113
Jeffrey B.
Coopersmith,
Comment,
Refocusing Liquidated Damages Law for Real
Estate Contracts: Returning to the Historical
Roots of the Penalty Doctrine, 39 Emory L.J.
267, 267–70 (1990).
36
example, one of the more common
practices is to pay a bonus upfront, similar
to a bonus payment on an oil and gas lease,
with “rentals” being paid to the surface
owner each year thereafter. The benefit to
this scheme is that the compensation is
foreseeable and will not grow if high
production is achieved or if additional wells
are drilled.
(2) paid a reduced price for the surface
estate because it was stripped of its mineral
rights. According to these practitioners, any
compensation scheme in an SUA is more
akin to a “preemptive settlement agreement”
to keep the parties out of conflict and
litigation, rather than compensation for any
additional rights.
In practice, which of these
jurisprudential theories is applied makes
little difference. However, the use of these
terms help to understand the payment
scheme and what can be expected in terms
of quantity of payout and scheduling of
payments. Whichever payment scheme is
chosen, keep the following factors in mind:
Some practitioners argue that a
‘bonus with rentals’ scheme is the most
appropriate payment scheme from a
jurisprudential perspective. This is because
a true royalty is only applicable to mineral
owners, and liquidated damages are
designed to compensate a party due to a
breach of contract. Additionally, some
practitioners argue that true liquidated
damages must be in response to a probable
loss, whereas there is technically no loss to
the surface owner considering the value he
paid for the land should have been reduced
for lack of mineral rights and for the fact that
the surface will be restored after drilling and
production activities. The same argument
can be said as to a “before and after”
appraisal scheme, as the subsequent
appraisal should always render a $0.00
balance
after
appropriate
surface
restoration measures have taken place,
compensating for changes in market-value.
1.
2.
3.
Additionally,
other
practitioners
argue that a rental scheme is inappropriate
because it operates only under a legalfiction of “rent” being paid by the operator
for a property right he is already entitled to
under the dominant estate theory.114 Finally,
some practitioners argue that no scheme is
actually appropriate because the surface
owner has already been fairly compensated
for any drilling activity when (1) they
conveyed the minerals at market value or
4.
V.
whether statutory, regulatory,
and common law damages,
and
compensation
are
effectively waived by the
surface
owner
and
preempted by the SUA;
whether the operator is
statutorily required to repair
and restore the surface;
determine which payment
scheme is the common
practice in your area, and
figure
out
what
your
bargaining power is within
that scheme; and
think ahead: understand your
development
plans,
and
choose both a scheme and
compensation level that will
keep the costs reasonable
and foreseeable.
Surface Owner Requirements of
Operator
Perhaps the most important section
of an SUA from the surface owner’s
perspective is the collection of provisions
requiring the operator to act or refrain from
acting in certain ways. These provisions are
important to a surface owner because they
seek to limit the potential intrusion the oil
114
Of course this is not true in those states that
do not recognize the dominant estate theory.
Using the term ‘rentals’ may be entirely
appropriate in those states.
37
and gas development will have on the
surface owner’s full enjoyment of the
surface estate. Often times, these
provisions may simply mirror or regurgitate
requirements the operator is already bound
to by law. However, it is important to
understand and be aware of these common
provisions before negotiating and drafting
an SUA. The lessee should understand the
compromise between making the surface
owner happy and keeping the lessee’s
operational options diverse and restrictionfree.
Therefore, if an operator were to reduce the
number of well sites from five down to one
on a 160-acre parcel, this would free-up
nearly one million dollars’ worth of land for
the surface owner.115
Other common provisions govern
the actual operations themselves. For
example, an SUA may contain prohibitions
against drilling activities during hunting
seasons. Depending on the area, this
season could be as long as October through
March. In South Texas, for example, many
of the most productive oil and gas leases
are situated on some of the best and most
lucrative hunting operations in the country.
Operators typically have no problem
agreeing to a restriction against using the
land for hunting purposes, but it is important
to understand that restrictions aiming to
protect the quality of hunting grounds can
go much further. Many other provisions
exist that aim to protect the use of the land
as prime hunting territory, with the goals of
maximizing
wildlife
quality,
wildlife
population, and use as hunting land.
There are countless considerations
a surface owner may deem necessary for
inclusion in an SUA. For the purposes of
brevity, this article will discuss only some of
the more common provisions. One of the
most contentious demands involves the
location of the well site(s). This can be as
simple as prohibiting the placement of drill
sites within a certain distance of a dwelling
or building, or can go much further and be
far more restrictive. For example, an SUA
may require the operator to drill only in
certain designated areas, limit the total
number of drill pads, or limit the total area of
the surface covered by operations. This can
be crucial to the surface user if, for
example, the surface is used as farmland
and keeping operations away from the
middle of pastures or fields is of utmost
importance to the surface owner.
Other common provisions a surface
owner may request include the following:
1.
2.
With the widespread use of
directional drilling, surface owners are more
frequently demanding that the operator
employ directional drilling techniques to
minimize surface impact. A landowner may
persistently demand directional drilling of
multiple wells from one pad to reduce the
surface area used by the operator. In the
northern Front Range of Colorado, for
example, drilling multiple wells from a single
pad can reduce surface use by 80%. Land
values for many family farms in Colorado
often exceed $25,000 per acre. A typical
well with related easements and setbacks
occupies
approximately
12
acres.
3.
115
fencing, fencing repairs, gate
or cattle guard installation
and other cattle management
tools;
provisions relating to housing
workers on the premises;
provisions
pertaining
to
water, such as quantity
usable, or requirements as to
testing water in relation to
fracking activities;
EarthWorks Oil & Gas Accountability Project,
The Landowner’s Guide to the Colorado
Landowners’ Protection Act, EARTHW ORKS (last
visited
Jan.
1,
2014),
available
at
http://www.earthworksaction.org/library/detail/col
orado_landowners_protection_act_brochure#.U
sRNqGRDuJ5.
38
4.
5.
6.
7.
tank battery storage and
location;
equipment and oil and gas
storage;
road provisions, such as
location, quality, and road
construction
materials
restrictions; and
usable surface materials
restrictions, prohibiting the
use of timber, caliche, water,
gravel, etc.
surface owner is to effectively balance
addressing the surface owner’s concerns
and the business needs of the operator.
Remember one of the fundamental goals of
SUAs: resolving potential disputes in
advance using negotiation, rather than
waiting for actual conflict and resorting to
litigation.
VI.
Another important provision in an
SUA is to describe the activities the
operator is permitted to perform on the
surface estate, which for our purposes will
be referred to as the “Operator Rights
Clause.” These clauses can take many
forms and vary greatly in length. The clause
can be as short as the following:
Another key inclusion in any SUA is
penalties for non-compliance or “overuse” of
the surface beyond the limiting provisions.
Sometimes these provisions aim to remedy
damages and make the surface owner
whole, while others aim to deter conduct the
surface owner considers undesirable. For
example, if a drillpad exceeds the size
agreed to in the SUA, the operator may be
required to pay an amount per square foot
exceeded.116 To some surface owners,
maintaining the aesthetic quality of the land
may be crucial. As such, it is not uncommon
to find provisions requiring the payment of
penalties for each tree destroyed or for
every piece of debris or trash found on the
premises. These provisions can become
quite complicated, such as requiring the
payment of $3,000.00 for every tree
destroyed that had a trunk diameter of more
than twenty inches when measured twentyfour inches above the surface of the ground.
One SUA in Wyoming called for a penalty of
$7,500.00 for every turtle that was run over
by a vehicle on the premises.
The parties hereby agree
that the Operator shall be
granted such surface rights
as are reasonably necessary
for
Lessee’s
operations
related to the drilling and
producing of oil and gas
wells
pursuant
to
the
Operator’s oil and gas lease
covering the Subject Lands
as well as other lands
contiguous to or within a
logical spacing or pooling
area to the Subject Lands.
This short version of an Operator
Rights Clause is concise and to the point.
However, it is practically nothing more than
a restatement of the dominant estate theory.
As such, in most jurisdictions, it fails to grant
or limit the operator’s rights already enjoyed
Many landowners take these
provisions very seriously. Depending on the
requirement, and how strictly they are
drafted, these concerns can be trivial to the
operator or can rise to the level of being
overly burdensome. A crucial point in
maintaining a good relationship with the
116
Operator’s Permitted Activities
Supra note 121.
39
under the law.117 However, there is one
scenario where this short clause can be a
useful curative tool. Where a mineral
reservation or other valid recorded covenant
expressly limits the surface rights of the
mineral or royalty owner or lessee, there is
generally no basis for the implication of a
surface use easement in favor of the
mineral owner in excess of those expressly
granted or limited.118 As such, the use of the
surface by the mineral owner or lessee
would require curative measures to obtain
the right to use of the surface. The short
version of the Operator Rights Clause given
above can seek to cure such a limitation by
regaining the stature typically enjoyed by
operators under the dominant estate theory.
2.
3.
Expanding the Right to Use the Surface
Estate
In most situations, this shortened
version of an Operator Rights Clause is
inadequate because it does not fulfill some
of the most important goals of an Operator
Rights Clause. An Operator Rights Clause
should seek to satisfy one or more of
several potential goals, which will be further
discussed below, including the following:
1.
clarify the surface rights
enjoyed under the dominant
estate theory by express
agreement in the SUA
between the operator and the
surface owner; and
ease tension with the surface
owner and avoid future
conflict by obtaining the
surface owner’s express
written consent to the
operator’s
planned
operations, whether already
permitted under the dominant
estate theory or not.
A mineral owner is granted relatively
broad rights to use the surface estate under
the dominant estate theory, and only
minimally restricted by the rule of
reasonable
necessity
and
the
accommodation doctrine. Nonetheless,
operators typically look to enjoy the
maximum extent of their implied surface
easement and sometimes even directly
desire to engage in activities that exceed
the scope of their implied surface
easement.119 In relation to the operator’s
right to use the surface, an SUA has two
primary functions. First, the SUA can be
used to cure the risk associated with
engaging in activities that brush close to the
limits of the surface easement by clarifying
the extent of the operator’s easement to use
the surface estate, and by obtaining the
surface owner’s express agreement as to
that use. Second, an SUA can be used by
the operator to obtain the right to engage
directly in operations that exceed the scope
of an easement implied under the dominant
estate theory and which exceeds the
grant the operator the right to
use the surface estate
beyond what may be enjoyed
under the dominant estate
theory;
117
As described earlier in this article, most
jurisdictions follow some form of the dominant
estate theory, which holds that the mineral
estate enjoys the right to use so much of the
surface estate as is reasonably necessary to
enjoy the ownership of the mineral estate, even
though such use may, and likely will, interfere
with the surface owner’s use of the land. Harris
v. Currie, 176 S.W.2d 302, 305 (Tex. 1943);
Vest v. Exxon Corp., 752 F.2d 959, 961 (5th Cir.
1985).
119
See, e.g., id. (stating that court-adopted tests
make it difficult to prove a mineral owner’s
actions exceeded the scope of its implied
easement of surface use).
118
Patrick H. Martin and Bruce M. Kramer,
W ILLIAMS & MEYERS, OIL AND GAS LAW § 218
(LexisNexis Matthew Bender 2012).
40
limitations imposed under the limiting
doctrines such as the accommodation
doctrine.
accommodation doctrine. The plaintiff
surface owner objected to the defendant
operator’s proposed drilling of four vertical
wells rather than the drilling of four
directional wells from a single surface
location.
An SUA can cure these issues
because most jurisdictions hold that the
limiting
doctrines,
such
as
the
accommodation doctrine, do not apply if
contradicted by an express agreement to
the contrary.120 For example, in Zeiler
Farms, Inc. v. Anadarko E & P Co.,121 a
Colorado court held that the terms of an
SUA controlled an operator’s use of the
surface estate in connection with its
proposed drilling operations rather than the
In Colorado, the accommodation
doctrine was codified by statute and
expressly provides that it “shall not be
construed to prevent an operator from
entering upon and using that amount of the
surface as is reasonable and necessary to
explore for, develop, and produce oil and
gas.”122 However, the SUA provided that the
operator had the right to enter the premises
and “construct, maintain, and use . . . all oil
wells . . . necessary or convenient in
prospecting and developing . . . oil.”123 The
court held that the “necessary or
convenient” standard the parties bargained
for in the SUA was the controlling standard
rather than the “reasonable and necessary”
standard
found
in
the
statutory
accommodation doctrine.124 Finally, the
court dismissed the plaintiff’s claim, in part
noting that the phrase “necessary or
convenient” is not a discretionary term
requiring the duty of good faith and fair
dealing,125 and later rejected the plaintiff’s
claim that the proposed drilling exceeded
the scope of being “necessary or
convenient.”126
120
See Amoco Prod'n Co. v. Thunderhead, 235
F.Supp.2d 1163, 1173 (D. Colo. 2002) (stating
that the rule of reasonable accommodation
applies in the absence of lease provisions to the
contrary). See also Landreth v. Melendez, 948
S.W.2d 76, 81 (Tex. App.—Amarillo 1997, no
writ) (accommodation doctrine did not apply
where reservation of rights expressly included
the right to employ "all usual, necessary and
convenient means" to explore for, produce and
remove minerals); Texaco Inc. v. R.W. Faris,
413 S.W.2d 147, 149–50 (Tex. Civ. App.—El
Paso 1967, writ ref’d n.r.e.) (where express use
of surface estate is set forth in an easement, the
provisions of the easement control rather than
any implied right to "reasonably necessary"
use); COLO. REV. STAT. § 34-60-127(4)(b) (the
Colorado statutory adoption of the reasonable
accommodation doctrine expressly provides that
it does not override any private agreement to the
contrary between the lessee and the surface
owner).
Another example of a situation
where a mineral lessee may desire to use
the surface estate beyond the scope of the
implied easement is the development of a
hydrocarbon formation that does not
121
Zeiler Farms, Inc. v. Anadarko E & P Co., No.
07-cv-01985-WYD-MJW, 2010 U.S. Dist. LEXIS
76670 , at *2 (D. Colo. July 1, 2010). See also
COLO. REV. STAT. § 34-60-127(4)(b) (“Nothing in
this section shall…[p]revent an operator and a
surface owner from addressing the use of the
surface for oil and gas operations in a lease,
surface use agreement, or other written
contract.”).
122
COLO. REV.
(emphasis added).
123
STAT.
§
34-60-127(1)(c)
Zeiler Farms, 2010 U.S. Dist. LEXIS 76670 ,
at *5 (emphasis added).
41
124
Id. at *12–14.
125
Id.
126
Id. at *14–17.
underlie the drill site tract. For more on this
issue, see the “Parties” subsection in Part
Two of this article.
important to be intimately familiar with the
specific remedies available in each
jurisdiction and retain experienced counsel
from an attorney when appropriate.
In conclusion, it is important to
remember that a reasonable use of the
surface by a surface owner and a
reasonable use by a mineral owner or his
lessee may be two completely different
things. As such, the implied easement
enjoyed by operators is inherently subject to
some ambiguity. Occasionally, operators
take a gamble by choosing to accept the
business
risk
associated
with
the
assumption that their operations will fall
within the confines of the dominant estate
theory. Therefore, the best way to avoid
conflict with the surface owner and eliminate
the risk associated with surface use is to
ensure that the parties are on the same
page and expressly lay out the proposed
activities in a written agreement.
VII.
Prohibited
Activities
Surface Owner
of
One of the most common tools of
the unreasonable surface owner in
prohibiting mineral operations is restriction
of access to the property. This can be
accomplished in many ways, from locking
the gates at all access points to, in extreme
circumstances, meeting agents of the
operator at the boundary line of the property
with an unpleasant disposition and a double
barrel shotgun. In other instances, surface
owners will make unreasonable drill site
placement requests or seek exorbitant
figures for damage compensation with the
intent of delaying the drilling process.
As discussed above, meaningful
negotiations with the surface owner and the
execution of an SUA is the best and most
cost effective way of resolving such
impasses. To the extent reasonably
practicable, the surface owner’s concerns
should be addressed, no matter how trivial,
so long as any concessions made do not
place the operator in an unfavorable
position.
the
The majority of this article has been
drafted with the intent of providing
attorneys, draftsmen, and landmen with the
information necessary to negotiate and
execute surface use agreements that are
favorable
to
the
operator
while
simultaneously satisfying surface owners
and complying with each jurisdictional
statutory framework. However, completing
this process is often times easier said than
done. In practice, situations sometimes
arise, either before or after execution of an
SUA, where an unreasonable surface owner
is intent on delaying, or altogether
prohibiting, mineral operations. Without
proper protection and knowledge of the
legal remedies available to the operator,
these surface owners can make continued
exploration and production activities a long,
arduous, and expensive process. What
follows are some suggestions intended to
move along the development and
production process and minimize monetary
consequences in such situations. It is
However, when it becomes clear
that the surface owner has no intention of
coming to an agreement, the most effective
option for the operator is to file a temporary
restraining order (“TRO”) in the county in
which the lands at issue are located. A TRO
is “a court order preserving the status quo,
forbidding the opposing party from taking
some action until a litigant’s application for a
preliminary or permanent injunction can be
heard.”127 In the context of exploration and
production operations, it is typically
argued/understood that the “status quo” is
the mineral developer’s right as the
dominant estate owner to develop the
127
BLACK’S LAW DICTIONARY 697 (2d pocket ed.
2001).
42
resources under the surface, and the
injunction is typically requested to prevent
the surface owner from taking the action of
blocking access to the property or otherwise
prohibiting operations.
issues that are important to the surface
owner and by anticipating issues that could
potentially become relevant if the relations
were to substantially deteriorate. For
example, the surface owner may demand
access to the drill site for inspection
purposes. If this is a provision the operator
is willing to negotiate, care should be
exercised in outlining, as specifically as
possible, an inspection procedure that
includes reasonable limitations, preventing
the surface owner from accessing or
inspecting the equipment and operations in
an unreasonable manner. If the breadth of
the surface owner’s rights are carefully
described in the SUA, the surface owner will
be prevented from arguing for the
application of an expanded interpretation of
those rights in the future, or alternatively,
arguing that he is being denied those rights
by the operator.
A thorough understanding of the
statutory procedure for obtaining a TRO in a
court of competent jurisdiction is crucial to
resolving the conflict as quickly and
efficiently as possible once it becomes clear
that such an action is necessary. Once a
TRO has been granted by a court and
operations are allowed to commence,
continued negotiations with the surface
owner is highly advisable. If the operator
cannot come to agreement with the surface
owner regarding continued surface access
and surface damage compensation, the
resolution of such issues will continue to be
left to litigation in a costly and slow moving
courtroom.
Even the most carefully drafted
surface use provision cannot always
prevent
a
contentious
battle
with
unreasonable
surface
use
owners.
Fortunately, the financial and durational
impact of these disputes can be reduced by
including alternative dispute resolution
provisions in the SUA. These provisions will
generally prohibit the parties from
commencing litigation in a court of law
without first attempting to mediate the
dispute with a mutually agreeable mediator
and/or entering into arbitration.
While the negotiation of an SUA is
typically very effective in establishing and
maintaining a positive relationship with the
surface owner, positive relations can and do
sometimes deteriorate even after positive
early stages. As stated above, an unhappy
surface owner may attempt to preclude
exploration and production activities,
regardless of the legal merit of doing so.
The most effective method of dealing with
such situations is handled up front during
the negotiation phase, by drafting clear,
concise, and specific provisions in the SUA.
Clear, well-worded provisions that dispose
of the issues frequently encountered, such
as surface access, surface use, drill site
locations, and drilling provisions, will allow
the operator to obtain a TRO much more
easily and efficiently. Without clear
provisions in the SUA, obtaining a TRO
frequently requires litigating contentious
battles based on legal doctrines that are
open to interpretation.
Arbitration is a process by which one
or more neutral and mutually agreed upon
third parties, outside of the court of law,
review evidence presented and resolve a
disagreement between two or more
disputing parties. Generally, the alternative
dispute resolution provisions contained in
surface use agreements provide for
voluntary, non-binding arbitration. The
authors note that arbitration is viewed as
both favorably and unfavorably depending
on jurisdiction. The advice of legal counsel
should be sought regarding the implications
and use of arbitration provisions in that
Additionally, deteriorating relations
are best handled with foresight, by
establishing an SUA that clearly covers the
43
jurisdiction prior to including the same in a
surface use agreement.
the dispute and the relief
requested. The parties will
cooperate with one another
in
selecting
a
single
mediator, and in promptly
scheduling the mediation
proceedings. If the parties
cannot agree to a mediator,
they shall appoint the
American
Arbitration
Association as a mediation
body (which shall in turn
select a mediator), and shall
implement the Commercial
Mediation
Rules.
All
settlement offers, promises,
conduct and statements,
either oral or written, made in
the course of the settlement
and mediation process by
either Mineral Owner or
Surface Owner, their agents,
employees,
experts and
attorneys,
and
by
the
mediator, are confidential
privileged and inadmissible
for any purpose, including
impeachment,
in
any
arbitration
or
other
proceeding involving the
parties:
provided
that
evidence that is otherwise
admissible or discoverable
shall not
be rendered
inadmissible
or
nondiscoverable as a result of its
disclosure during settlement
or mediation efforts. During
the
pendency
of
the
settlement and mediation
process, the parties agree to
forebear from filing or
otherwise proceeding with
litigation; provided, however,
that either Mineral Owner, on
the one hand, or Surface
Owner, shall be entitled to
seek a temporary restraining
order
or
preliminary
injunction to prevent the
The following is an example of a
thorough and well-drafted alternative
dispute resolution clause found in a Texas
SUA:
In the event of any dispute,
claim,
question,
disagreement or controversy
arising from or relating to this
Agreement or breach thereof,
Mineral Owner and Surface
Owner
shall use
their
reasonable efforts to settle
the dispute, claim, question
or disagreement. To this
effect, they shall consult and
negotiate with each other in
good faith and, recognizing
their
mutual
interests,
attempt to reach a just and
equitable
solution
satisfactory to the parties. If
the Mineral Owner and
Surface Owner do not reach
a solution within a period of
30 days after written notice
by either Mineral Owner or
Surface Owner requesting
that such discussions be
initiated, the parties agree
that any and all disputes,
claims,
questions,
disagreements,
or
controversies arising from or
relating to this Agreement or
the breach thereof, shall be
submitted to non-binding,
voluntary mediation. Either
Mineral Owner or Surface
Owner
may
commence
mediation
by
providing
Surface Owner (in the case
of Mineral Owner) or Mineral
Owner (in the case of
Surface Owner) with a
written request for mediation,
setting forth the subject of
44
breach of
the Mineral
Owner’s or the Surface
Owner’s obligations, as the
case may be, under this
Agreement. If the agreement
of the parties to use
mediation breaks down and a
later litigation is commenced
or application for injunction is
made, the parties will not
assert a defense of laches or
statute of limitations based
upon the time spent in
mediation. Either Mineral
Owner or Surface Owner
may initiate litigation with
respect to the matters
submitted to mediation at any
time following 60 days after
the initial mediation session
or 90 days after the date if
sending the written request
for mediation, whichever
occurs first. The mediation
may continue after the
commencement of litigation if
Mineral Owner and Surface
Owner so mutually elect in
writing. The provisions of this
Section may be enforced by
any court of competent
jurisdiction and the party
seeking enforcement shall be
entitled to an award of all
costs, fees and expenses,
including attorney’s fees, to
be paid by the party against
whom
enforcement
is
ordered.
surface use agreement. Notwithstanding,
such provisions, if legally applicable in a
particular jurisdiction, are essential in
protecting the operator from the actions of
unreasonable surface owners. While not
guaranteed, these provisions are likely to
bypass costly and time consuming litigation,
saving the operator thousands of dollars
and a significant amount of time and effort.
VIII.
Surface Restoration Provisions
Surface
restoration
(or
“reclamation”) provisions are becoming
increasingly common in today’s surface use
agreements. In most oil and gas producing
states, reclamation is defined, to varying
degrees, as the restoring of the surface
directly affected by oil and gas operations,
as closely as reasonably practicable, to the
condition that existed prior to oil and gas
operations, or as otherwise agreed to in
writing by the oil and gas operator and the
surface owner.128 A typical surface use
restoration provision reads as follows:
Unless Owner otherwise
agrees in writing, upon
termination
of
any
of
Operator’s operations on
Owner’s land, Operator shall
fully restore and level the
surface of the land affected
by
such
terminated
operations as near as
possible to the contours
which existed prior to such
operations. Operator shall
use water bars and such
other
measures
as
appropriate
to
prevent
erosion
and
non-source
As provided above, the authors note
that this example is not one which should be
freely utilized by landmen in each situation
and jurisdiction. This is simply an example
of an alternative dispute resolution provision
specifically for use in Texas. The advice of
independent legal counsel should be sought
regarding the applicability of such provisions
in the state in which the subject lands are
located prior to including the same in the
128
See, e.g., W YO. STAT. ANN. § 30-5-401(vi)
(2013) (“‘Reclamation’ means the restoring of
the surface directly affected by oil and gas
operations, as closely as reasonably practicable,
to the condition that existed prior to oil and gas
operations…”).
45
Dakota,136 and Illinois137 have adopted some
form of legislation requiring reclamation of
the surface. The reclamation obligations
imposed upon an operator vary greatly from
state to state,138 and the extent of these
variations is not considered within the
context of this article. The specific
obligations to which an operator in each
jurisdiction is bound should be carefully
followed. For example, the state of New
Mexico requires that an operator consider
issues such as removal and exploration of
plant life and vegetation, surface water
drainage, and other issues when negotiating
damages and reclamation under a surface
pollution. Operator shall fully
restore all private roads and
drainage
and
irrigation
ditches
disturbed
by
Operator’s operations as
near as possible to the
condition which existed prior
to such operations. All
surface restoration shall be
accomplished
to
the
satisfaction of Owner.
Traditionally, courts were reluctant to
place an affirmative duty on an operator to
restore the surface to its pre-drilling
condition, absent a written agreement
providing otherwise.129 However, the use of
reclamation provisions in surface use
agreements have increased in frequency
over the years, mainly as a result of (1)
state legislatures passing mandatory
reclamation statutes130 and (2) savvy
mineral owners who, in recognition of the
rights of surface use owners, demand
provisions in the oil and gas lease for
reclamation of the surface. Any and all oil
and gas leases covering the subject
minerals should be carefully reviewed, as
well as any contractual or statutory duty to
reclaim the surface prior to entering into
negotiations with the surface owner.
abandoning party have entered into a contract
providing otherwise).
134
LA. REV. STAT. ANN. § 31:22 (2014). See also
Terrebonne Parish Sch. Bd. v. Castex Energy,
Inc., 893 So.2d 789, 797 (La. 2005) (holding that
where a lease is silent as to restoration, the
extent of restoration required turns to a focus on
whether the operations were conducted
negligently or unreasonably, rather than the
reasonable costs of restoration and cleanup
activities); Rohner v. Austral Oil Exploration Co.,
104 So.2d 253, 256 (La. App. 1 Cir. 1958).
135
136
N.D. ADMIN. CODE 43-02-02-11 (2013)
(posted bond must include anticipated surface
restoration costs).
Several states, including, but not
limited to, Colorado,131 New Mexico, 132
Kansas,133 Louisiana,134 Montana,135 North
137
138
Warren Petrol. Corp. v. Monzingo, 304
S.W.2d 362, 363 (Tex. 1957).
130
See, e.g., 2 COLO. CODE REGS. § 404-1
(2013) (1000-series).
Id
132
N.M. STAT. ANN. § 70-12-4 (2013).
765 ILL. COMP. STAT. 530/6(4C) (2013).
For example, in Louisiana, it was held that an
award for $33 million was an appropriate award
under a contractual obligation on the part of the
lessee to restore the property as nearly as
possible to its prior condition, even though the
property was only worth a fair market value of
$108,000.00, and even though the landowner
had no intention of using the money for actual
restoration
activities.
Corbello
v.
Iowa
Production, 850 So. 2d 686 (La. 2003). Corbello
has since been superseded by statute. See
State v. Louisiana Land & Exploration Co., 110
So. 3d 1038 (La. 2013).
129
131
MONT. ADMIN. R. 36.22.1307 (2013).
.
133
KAN. STAT. ANN. § 55-177 (2012) (requiring
that whenever an operator abandons any well
he shall grade the surface of the soil in such a
manner as to leave the land as it was before
unless the owner of the land and the
46
use agreement.139 In contrast, Kansas
merely requires that the operator, at
termination of the lease, remove any rig,
derrick, or other operating structure and
return land to original grade, unless
otherwise agreed.140
tree, shrub, fence or native vegetation that
may be disturbed during mineral operations.
Leaving these restoration costs for
determination at a later date can be a costly
decision for the operator, as many surface
owners will retain counsel to determine the
extent of restoration required on the
property, usually on a highly inflated basis.
SUA negotiations provide the best
opportunity to negotiate accurate and
reasonable restoration and reclamation
costs with the surface owner. Of course,
when an agreement is reached, the
operator should ensure the SUA explicitly
states that the contemplated compensation
is intended to provide the surface owner
with
all
available
restoration
and
reclamation compensation.
In addition to statutory requirements,
there are instances where states have
placed a common law duty upon an
operator to engage in restoration of the
surface. One such state is Oklahoma,
where the Oklahoma Supreme Court ruled
that there was a duty to restore the
premises while a lease was in effect by
reason that it complied with the
reasonableness requirement of not using
more of the surface than necessary.141
The intricacies associated with the
restoration and reclamation laws in each
state should be carefully followed, and legal
counsel should be retained, if necessary, to
ensure that any negotiated surface use
agreement adequately covers all operator
compliance issues with regard to restoration
and reclamation.
In contrast, operators may find
themselves in situations, especially with
more reasonable surface owners, where it is
more beneficial to forego the negotiation of
specific reclamation issues and instead
include a broad reclamation provision like
the one described above. By including such
a provision, the guessing game regarding
the cost of future reclamation operations is
set aside. This creates the potential of
making it easier and cheaper for the
operator to assess the actual and not
speculative cost to restoring the surface.
The inclusion of such a provision can also
be useful in placing the surface owner’s
mind at ease regarding the future state of
his property. The typical surface owner
wants nothing more than for his land to
remain undisturbed, and while this isn’t
possible if operations are to be conducted
on the land, the surface owner can take
solace in the fact that after operations are
completed, it will be as though the operator
never stepped foot onto his land, or as close
to
possible
thereto
depending
on
circumstances.
Several of the above identified
states, Illinois being a prime example, have
adopted statutes mandating reclamation of
the surface unless waived, in writing, by the
surface owner.142 In such jurisdictions, and
in situations where the surface owner may
be difficult to work with, there is added
incentive to negotiate and execute an SUA
identifying specific reclamation costs in
order to settle the issue up front and relieve
the operator of any further reclamation
obligations after operations have ceased.
During SUA negotiations, operators have
wide latitude in discussing the value of each
139
N.M. STAT. ANN. § 70-12-5 (2013).
140
KAN. STAT. ANN. § 55-177 (2013).
141
In conclusion, operators should be
intimately familiar with the restoration and
reclamation laws covering the state in which
he or she is negotiating any surface use
Tenneco Oil Co. v. Allen, 515 P.2d 1391,
1396–97 (Okla. 1973).
142
765 ILL. COMP. STAT. 530/6(4C) (2013).
47
North
Dakota,152
Oklahoma,153
154
Pennsylvania,
South
Dakota,155
156
157
Tennessee, Utah, West Virginia,158 and
Wyoming,159 have supplemented the
common law redresses available to surface
owners by codifying some form of legislation
to address surface use and surface owner
compensation issues. These statutory
schemes are generally referred to as
“Surface Damage Compensation Statutes,”
“Split Estates Acts,” or “Surface Damages
Acts.”
agreement. Understanding the extent of
these laws and how they may be
implemented into a surface use agreement
will protect the operator and potentially save
significant amounts of restoration cost in the
process.
PART THREE: SURFACE DAMAGE ACTS
I.
Overview of Surface Damage Acts
At least seventeen states, including
Alaska,143
Arkansas,144
Colorado,145
146
147
Illinois,
Indiana,
Kentucky,148
149
150
Louisiana,
Montana,
New Mexico, 151
143
The content and extent of each
state’s Surface Damages Act varies widely;
however, the acts generally focus on the
following issues: (1) some form of notice
requirement with a specified period of time
that the operator is obligated to provide to
the surface owner before commencing any
operations on the surface, including the
locations of proposed facilities and access
routes related to the oil and gas operations;
(2) some form of negotiation requirement,
whereby the operator is obligated to at least
enter into good faith negotiations, propose a
reasonable offer to the surface owner, or
attempt to enter into a surface use
agreement; (3) the operator may be
required to pose some form of financial
surety in the event that they are unable to
come to an agreement with the surface
ALASKA STAT. §§ 38.5.131–134 (2013)
144
ARK. CODE ANN. § 15-72-219 (2013) (surface
owner is entitled to reasonable compensation
after a spill of crude oil or produced water).
145
COLO. REV. STAT. ANN. § 34-60-127
(2013)(“[developer must select] alternative
location for wells, roads, pipelines, or production
facilities, or…means of operation, that prevent,
reduce, or mitigate the impacts of the oil and gas
operations…where such [operations] are
technologically sound, economically practicable,
and reasonably available to the operator.”). This
has been commonly referred to as a statutory
accommodation doctrine. However, due to the
broad language of the statute, its application
may go beyond those restrictions typically found
in accommodation doctrines in other states.
Additionally, Colorado Oil and Gas Commission
has promulgated various regulatory rules that
provide for damages to the surface owner. 2
COLO. CODE REGS. §404-1 (2013) (1000-series
Reclamation Regulations).
150
MONT. CODE ANN. §§ 82-10-501–511 (2013).
151
N.M. STAT. ANN. §§ 70-12-1–10 (2013).
152
N.D. CENT. CODE §§ 38-11.1-01–10 (2013).
153
OKLA. STAT. tit. 52 §§ 318.2–318.9 (2013).
154
58 PA. CONS. STAT. §§ 3216–27 (2013).
146
765 ILL. COMP. STAT. 530/1–7 (2013).
155
147
S.D. CODIFIED LAWS §§ 45-6C-33–55 (2013).
IND. CODE ANN. § 32-23-7-6 (2013).
156
TENN. CODE ANN. §§ 60-1-601–608 (2013).
148
KY. REV. STAT. ANN. §§ 353.595–730 (West
2013).
157
UTAH CODE ANN. §§ 40-6-2, 5, 20, 21 (West
2013).
149
LA. REV. STAT. ANN. § 31:196 (2014) (mineral
owner is responsible to surface owner for value
of all use and damages caused by operations).
48
158
W. VA. CODE §§ 22-7-1–8 (2013).
159
W YO. STAT. ANN. §§ 30-5-401–410 (2013).
owner; (4) specific categories of damage
liability; (5) provide some avenue for dispute
resolution; (6) require the furnishing of a
copy of the applicable act to the surface
owner; (7) the potential waiver of the
statutory requirements; (8) a statute of
limitations for causes of action arising from
the statute; and (9) operator’s compliance
with the act as a condition precedent to
approval for an application for a drilling
permit.160
North Dakota Act, however, the Montana
Legislature made a concerted effort to
recognize the balancing act between the
necessity of exploration and development of
oil and gas reserves within the state and the
just compensation due landowners for
interference with the use of their property.165
Some commentators have argued
that these various surface compensation
statutes have eviscerated the applicability of
the dominant/servient estate theory in the
states where these statutes have been
adopted, in essence, granting the surface
estate owner the dominant estate.166 This
observation is not without merit. These
statutes have, in essence, subjected
operators to strict liability for surface
damages, regardless of whether their
actions in conducting said operations were
grossly
negligent,
or,
alternatively,
completely
reasonable
under
the
circumstances
and
within
industry
standards. It goes without saying that it is of
utmost importance that one be keenly
familiar with the provisions contained in the
statutory framework of each states’ surface
damages act and the extent of protections
and mandatory compensation afforded to
surface owners while negotiating surface
use agreements.
While the extent of surface owner
protections varies on a state by state basis,
it is the universal intent of each Surface
Damages Act to provide the surface owner
with fair and adequate compensation for
certain damages to the land, regardless of
whether
the
operator’s
use
was
reasonable.161
The
North
Dakota
Legislature, which was the first legislative
body to adopt a comprehensive Surface
Damages Act,162 found it prudent to codify
the act’s purpose as providing “the
maximum
amount
of
constitutionally
permissible protection to surface owners
and other persons from the undesirable
effects of development of minerals.”163
Subsequently, the Montana Legislature
largely adopted the provisions of North
Dakota’s Act when drafting its own Surface
Owner
Damage
and
Disruption
Compensation Act.164 In contrast to the
While these surface compensation
statutes are overwhelmingly surface owner
friendly, there are several benefits to these
statutes of which an operator may take
advantage. The most obvious benefit is the
opportunity provided the operator to
dispense of all potential conflicts with the
operator regarding surface damages before
drilling operations begin. As any operator
who has ever found themselves inside a
courtroom will attest, any day that does not
160
Norman D. Ewart, State Surface Access and
Compensation Statutes, 54 Rocky Mtn. Min. L.
Inst. 4-1, §4.03 (2008).
161
David Patton, The Mineral Estate and
Conflicting Interests – The Accommodation
Doctrine and Surface Damages Acts, 34 ERNEST
E. SMITH OIL, GAS AND MINERAL LAW INST. 7, 3
(2008).
162
North Dakota adopted the Oil and Gas
Production Damage Compensation Act in 1978.
N.D. CENT. CODE §§ 38-11.1-01–10 (2013).
163
N.D. CENT. CODE § 38-11.1-02 (2013).
164
MONT. CODE ANN. §§ 82-10-501–511 (2013).
165
166
MONT. CODE ANN. § 82-10-501(2) (2013).
Christopher M. Alspach, Surface Use by the
Mineral Owner: How Much Accommodation is
Required Under Current Oil and Gas Law?, 55
Okla. L. Rev. 89, 117–18 (2002).
49
remedies allowed by law.”168 Two situations
in which an operator may be obligated to
pay
a
surface
owner
additional
compensation above and beyond the terms
agreed to in a surface use agreement are
(1) where the particular type of damages
were not contemplated in the agreement,
and (2) the surface owner incurs injury due
to negligent or unreasonable actions of the
operator.
involve litigation is a good day. Most
statutory schemes provide that the amount
of compensation due a landowner “may be
determined by any formula mutually
agreeable between the surface owner and
the mineral developer.”167 This allows the
parties unlimited flexibility to negotiate the
compensation and determination of surface
damages, and provides the operator an
opportunity to implement unique and
creative negotiation techniques that can be
tailored to each specific situation. The
authors have observed the use of the
following provision within surface use
agreements to provide the operator
maximum protection against any claim for
damages extraneous to those bargained for
in the surface use agreement prior to the
commencement of operations:
The scope of the provisions
contained in the myriad surface damage
acts enacted across the country is varied,
extensive, and too broad to thoroughly
discuss within the framework of this article.
These statutes should be thoroughly
reviewed on an individual basis prior to the
negotiation of each surface use agreement.
Notwithstanding, the authors have identified
the following issues typically found within
the surface damage acts.
By executing this Surface
Use, Damage Agreement
and
Release,
the
undersigned
do
hereby
acknowledge that they have
been compensated in full for
any and all damages allowed
under
[YOUR
STATE’S
ACT].
A.
Individuals
Entitled
to
Protection under the Acts
One should take considerable care
in determining exactly which individuals or
entities are entitled to compensation under
each state’s respective surface damages
act. While it is reasonable to assume that
every state’s act mandates compensation
for the owner of the servient surface estate
upon which drilling operations will be
conducted, several states have enacted
statutes with the intent of broadening, and in
some cases limiting, the parties to which
compensation is provided.169
While the above noted provision has
the effect of limiting a surface owner’s
compensation to that which was originally
negotiated for, the operator must be aware
that the execution of a surface use
agreement is not a complete bar to
additional compensation for the surface
owner. A large majority of the states that
have adopted surface damage acts have
drafted them in such a way as to leave open
the possibility for additional compensable
damages. New Mexico’s Surface Owner’s
Protection Act, for example, provides, “The
remedies provided by the Surface Owners
Protection Act are not exclusive and do not
preclude a person from seeking other
168
169
N.M. STAT. ANN. § 70-12-8 (2013).
Compare W YO. STAT. ANN. § 30-5-401(a)(vii)
(2013) (“‘Surface owner’ means any person
holding any recorded interest in the legal or
equitable title, or both, to the land surface on
which oil and gas operations occur, as filed of
record with the county clerk of the county in
which the land is located. ‘Surface owner’ does
not include any person or governmental entity
that owns all of the land surface and all of the
167
See, e.g., N. D. CENT. CODE § 38-11.1-04
(2013).
50
Quite often the surface estate upon
which drilling operations are proposed is
occupied by a tenant rather than the
landowner of record. In states such as New
Mexico, operators are relieved, in most
circumstances, from considering the
implications that drilling operations may
have on the rights of a tenant.170 However,
states such as Montana and North Dakota
recognize the potential damages that may
be incurred by tenants leasing the surface
upon which operations will be conducted.
Each of these acts provide that a surface
owner may not reserve or assign the right to
damage and disruption compensation apart
from the surface estate except to a tenant of
the surface estate.171 The North Dakota Act
further reflects that “in the absence of an
agreement between the surface owner and
a tenant as to the division of compensation
payable under this section, the tenant is
entitled to recover from the surface owner
that portion of the compensation attributable
to the tenant’s share of the damages
sustained.”172
addresses the potential damage that may
be incurred by both the surface owner and
tenant in executing a surface use
agreement for this land. One should always
inquire as to (1) whether the land is leased,
and if so, (2) whether the tenant leases the
land via cash payments or by splitting crop
proceeds with the landowner.
Additionally, inquiry as to whether
individuals other than those occupying the
directly affected surface estate are entitled
to compensation should be addressed. For
example, North Dakota has enacted
legislation that statutorily protects the
domestic, livestock and irrigation water
supplies of any person who owns an
interest in real property within one-half mile
of where geophysical or seismograph
activities are or have been conducted or
within one mile of an oil or gas well site,
regardless of whether operations have been
conducted on that surface owner’s
property.173 Operators executing an SUA in
these states should take into account the
effect that operations may have on the
water supplies of neighboring landowners.
Much of the farm land, especially in
the western oil producing states, is tenant
farmed, and it is imperative that one
Finally, one should carefully review
their individual state’s surface damages act
for any provisions limiting the class of
landowners to which the operator is
required to compensate. For example, the
Illinois Drilling Operations Act provides that
the Act is applicable only to the drilling of
new wells and only when there has been a
complete severance of the ownership of the
oil and gas from the ownership of the
surface.174 Only a careful review of the
jurisdictions surface damages act will
ensure that the operator is not paying
unnecessary compensation to surface use
owners under states where limitations have
been placed on compensated issues.
underlying oil and gas estate, or any person or
governmental entity that owns only an
easement, right-of-way, license, mortgage, lien,
mineral interest or non-possessory interest in
the land surface[.]”); with UTAH STAT. ANN. § 406-2(24) (West 2013) (“‘Surface land owner"
means a person who owns, in fee simple
absolute, all or part of the surface land as shown
by the records of the county where the surface
land is located. (b) ‘Surface land owner’ does
not include the surface land owner's lessee,
renter, tenant, or other contractually related
person.”).
170
N.M. STAT. ANN. § 70-12-4(B) (2013).
171
MONT. CODE ANN. § 82-10-504(1)(e) (2013);
N.D. CENT. CODE § 38-11.1-04 (2013).
173
N.D. CENT. CODE § 38-11.1-06.
172
174
765 ILL. COMP. STAT. 530/3 (2013).
N.D. CENT. CODE § 38-11.1-04 (2013).
51
B.
In addition to the strict time
requirements described above, surface
damages acts place several other
requirements on operators during the
“notice” period. Operators should carefully
review the applicable notice provisions to
ensure that all proper procedures have
been followed. Some of these unique
requirements imposed on a state by state
basis include, but are not limited to, the
following:
Notice
Requirements
Imposed Under the Act
Virtually every state legislature that
has adopted a surface damages act has
imposed notice requirements on operators
that must be satisfied prior to entering a
surface owner’s property and commencing
operations.175 Typically, these statutes
provide notice requirements both for (1)
activities that do not disturb the surface of
the land and (2) operations that may or will
disturb the surface estate, such as seismic
and drilling operations. The time frame
allocated to each of these notice
requirements vary widely from state to state.
For example, New Mexico’s Surface
Owner’s Protection Act requires that an
operator provide not less than five days’
notice prior to commencement of any
activities that will not disturb the land, and
no less than thirty days’ notice prior to
commencement of operations that will
disturb the surface estate.176 Wyoming’s act
provides for no less than 30 days’ notice
and no more than 180 days’ notice for
activities that will disturb the land.177
1.
2.
3.
In many states, the minimum notice
requirements provide little time for the
surface owner to alter surface use to
accommodate an operator’s activities, and
little time for negotiation between the
operator and the surface owner. This short
notice runs the risk of potentially straining
relationships before operations even begin.
Accordingly, and as a practical matter,
operators should make a habit of providing
notice to potentially affected landowners as
soon as reasonably possible. As discussed
above, much of the battle should be won
during the negotiation process by gaining
the trust and respect of the surface owner.
175
Notable exceptions are Utah and Tennessee.
176
N.M. STAT. ANN. § 70-12-5 (2013).
177
W YO. STAT. ANN. § 30-5-402(e) (2013).
4.
5.
the operator must provide the
surface owner with a copy of
that
state’s
Surface
Damages
Act
(most
jurisdictions);
the operator must include a
proposed
Surface
Use
Agreement178 (New Mexico);
an offer to discuss the
location of proposed entry
points, drilling sites, road
placement, construction of
pits, restoration of fences,
removal of trees and surface
water drainage179 (Illinois and
Wyoming);
a
detailed
plat
map
describing all operations and
uses proposed for the
surface (most jurisdictions);
and
a current copy of a
publication
produced
by
Montana’s
environmental
quality council entitled “A
178
N.M. STAT. ANN. § 70-12-5 (2013) (terming
SUAs “surface use
and compensation
agreement” in New Mexico).
179
See 765 ILL. COMP. STAT. 530/5 (2013)
(requiring the operator to offer to discuss a
number of uses of the land with the surface
owner). See also W YO. STAT. ANN. § 30-5402(e)(iv) (2013) (requiring an offer to discuss
and negotiate in good faith proposed changes to
operations prior to commencing operations).
52
Guide to Split Estates in Oil
and Gas Development180
(Montana).
simultaneously, to this problem: (1) posting
a bond for damages, (2) requiring an offer of
settlement from the operator, and (3) third
party appraisal of damages.
One should take extreme caution in
ensuring that all statutory notification
requirements have been satisfied prior to
drilling operations. Additionally, one should
also be familiar with any potential penalties
that may exist under each Surface
Damages Act for failing to adequately
provide notice to the surface owner,
because such penalties can be substantial.
For example, the New Mexico Act requires
the payment of attorney fees, costs, and
treble damages if a court finds, by clear and
convincing evidence, that the operator failed
to comply with its notice obligations under
the Act.181
B.
i.
Posting a Bond
In the event the surface owner and
the operator are not able to come to an
agreement, several of the acts specify that
the operator may proceed with operations, if
notice is first provided as well as a proposed
plan of operations on the land. For example,
in Wyoming, after providing adequate notice
and failure to come to terms on an SUA, the
operator may post a bond with the Wyoming
Oil and Gas Commission in the amount of
$2,000.00 per well site.182 Within seven
days, the Commission will send notice of
the bond to the surface owner, and the
surface owner then has 30 days to object
and request a hearing on the bond
amount.183
Alternatives to Compliance
with the Act
Most surface damages acts require
that the operator engage in “good faith
negotiations” or make a “good faith attempt”
to negotiate an SUA with the surface owner.
However, things often appear simple on
paper but are difficult in practice. Most who
have negotiated SUAs on behalf of an
operator will have experienced an inflexible
or difficult surface owner. In states such as
Texas, where negotiation is not required, no
damages are required, and surface
restoration is not required, the issue can be
solved by resort to the courts. However, in
states that have enacted a surface
damages act, operators must resolve
conflict with surface owners quite differently.
In the event the surface owner and the
operator are not able to come to an
agreement regarding an SUA, the surface
damages acts provide for some form of
process to allow the operator to continue
with its operations. The states take three
general
approaches,
sometimes
Operators in Wyoming may choose
to commence operations without an SUA.
However, in this case, the surface owner
has a two year period after surface
damages are discovered, or should have
been discovered, to give notice of the
damages to the Commission. Once these
damages are reported, an operator then has
60 days to make a written offer of
settlement with the surface owner. If the
parties cannot agree to a damages
settlement, the Wyoming statute directs the
surface owner to bring an action for
compensatory damages.184
ii.
Offer and Acceptance of
Payment for Damages
1.
In
North
Dakota
and
Montana, in the absence of an SUA, the
182
W YO. STAT. ANN. § 30-5-404(b) (2013).
180
MONT. CODE ANN. § 82-10-503(1) (2013).
183
W YO. STAT. ANN. § 30-5-404(c).
181
N.M. STAT. ANN. § 70-12-7 (2013).
184
W YO. STAT. ANN. § 30-5-406(a)–(c).
53
operator is required to negotiate surface
damages caused by exploration in the form
of an offer of settlement contemplating the
entire time of operations in writing. The
surface owner can then accept or reject this
offer. Generally, these offers must include a
proposed single lump sum payment for
compensation.185 For loss of agricultural
production, however, the operator is
required to make annual payments unless
the surface owner elects to receive a lump
sum payment instead.186
recommendations to the parties as to the
damages that are likely to occur.189 The
operator selects one appraiser, the surface
owner(s) selects the second, and the two
mutually select a third appraiser who must
be a state-certified real estate appraiser.
Within 30 days, the appraisers file their
appraisal with the court. The parties then
have 20 days to either accept the appraisal
or to demand a trial by jury.190
However, it should be noted that
while the Oklahoma statute contains many
procedural steps, the statute does provide
some protection against unreasonable
delays to the operator. This is because after
filing the petition to commence appraisals,
and before the actual appraisals, the statute
allows the operator to enter the property
and begin conducting operations. One
should understand these nuances in the
statutes, and efficiently navigate their
requirements
to
ensure
that
no
unreasonable costs or delays are incurred.
2.
In these states, if a surface
owner rejects the operator’s offer, he can
bring an action for compensation in court.
This can be costly to the operator because
in addition to litigation costs these statutes
provide that if the compensation awarded in
court is greater than that offered by the
operator, the surface owner is also awarded
reasonable attorneys’ fees, costs, and
interest calculated from the day drilling is
commenced.187 Therefore, it is usually in the
operator’s best interest to start with a fair
proposal in the surface damages settlement
offer.
iii.
D.
Damages
Categories
Available to the Surface
Owner
Third Party Appraisers
Oil and gas producing states have
taken a broad range of approaches in
defining which damages the operator can
be liable for in the absence of a surface use
agreement. On one end of the spectrum,
Utah limits damages to “unreasonable” loss
of crops on the surface land, “unreasonable”
loss of value on existing improvements, and
“unreasonable” permanent damage to the
land.191 At the other end of the spectrum,
North Dakota and New Mexico have
enacted a much broader statutory category
of damages that can be recovered. North
Dakota requires compensation for lost value
Oklahoma has a unique process for
dealing with a situation where the parties
are unable to negotiate an agreeable SUA.
In Oklahoma, prior to entering the site with
heavy equipment, the operator must post a
$25,000.00
bond,
calculate
the
contemplated damages to the surface, and
the parties must enter into an agreement.188
If the surface owner and the operator
cannot come to an agreement as to the
value of damages, then the operator must
petition the court to commence a process
whereby three appraisers will make
185
N.D. CENT. CODE § 38-11.1-08 (2013).
189
Id.
186
Id.
190
Id.
187
N.D. CENT. CODE § 38-11.1-09.
191
188
OKLA. STAT. tit. 52, § 318.3–318.5 (2013).
UTAH CODE ANN. § 40-6-20(2)(c) (West
2013).
54
of land and improvements,192 lost use of and
access to the land, and lost agricultural
production.193 New Mexico allows for “loss
of agricultural production and income, lost
land value, lost use of and lost access to the
land, and lost value of improvements
caused by oil and gas operations.”194 As of
the writing of this article, there are few, if
any, cases interpreting most of the terms
used to clarify the damages recoverable
under these statutes. Therefore, this
indicates that the current practice in these
states is to obtain SUAs and paying
according to their terms, rather than run the
risk of ambiguous and possibly broad
statutory measure of damages.
E.
unrealistic.196 Many of these resources
strongly advocate voluminous, lengthy, and
often unrealistic surface-friendly provisions.
Additionally, many of these resources are
geared towards surface owners with little to
no experience in oil and gas exploration and
production. The effect is that these
resources have a tendency to encourage
surface owners to begin negotiations with
power moves, request unreasonable
provisions, and to believe the provisions
recommended by the resource to be either
the law, or to be standard custom and
practice.
F.
Surface damages acts have resulted
in challenges to their constitutionality under
various theories, including due process,
impairment of contracts, takings clause, and
equal protection. So far, these challenges
have not proven successful, as the statutes
have been upheld, both as constitutional
exertions of state police power197 and
regulation of the public welfare.198 A second
type of challenge has been raised in
Wyoming under the theory that the
Wyoming Split Estate Act, as applied to
surface ownership over federally owned
minerals, would be preempted by federal
law.199 The Stock Raising Homestead Act of
1916200 (SRHA) provides that:
Negotiations with Surface
Owners
As described above, the lack of case
law and reported disputes indicates the
statutes have had the effect of forcing
surface owners and operators to obtain
surface use agreements. There is no
shortage of free advice available for the
surface owner facing the possibility of
entering into a surface use agreement. The
surface owner who previously had limited
rights under the dominant estate theory now
comes to the bargaining table armed with
considerable additional power and can
present a considerable additional cost. The
advice received by surface owners can
range from reasonable195 to flat out
192
N.D. CENT. CODE § 38-11.1-04 (2013).
193
N.D. CENT. CODE § 38-11.1-06.
194
N. M. STAT. ANN. § 70-12-4(A) (2013).
Legal Challenges
196
See POWDER RIVER BASIN RESOURCE
COUNCIL, Surface and Damage Agreement
Sample 3, at 15 (May 4, 2001), available at
http://www.powderriverbasin.org/assets/Uploads
/files/surfacedamage/surfacedamageagreement3.pdf
(location of well sites must be approved by
Owner prior to Operator obtaining permit to drill).
195
See SOUTHEASTERN W YOMING MINERAL
DEVELOPMENT
COALITION,
LANDOWNER
GUIDELINES FOR NEGOTIATING A MINERAL LEASE
OR SURFACE USE AGREEMENT 20 (2011)
(recommending landowner to obtain a proposed
development plan from the operator and to
address mutual accommodation of future wind,
solar, and other use agreements).
197
Murphy v. Amoco Prod. Co., 729 F.2d 552,
555 (8th Cir. 1984).
198
Davis Oil Co. v. Cloud, 766 P.2d 1347, 1351–
52 (Okla. 1986).
199
See Matt Micheli, Showdown at the OK
Corral – Wyoming’s Challenge to U.S.
55
Any person qualified to
locate and enter the coal or
other mineral deposits, or
having the right to mine and
remove the same…shall
have the right at all times to
enter upon the lands entered
or patented,…for the purpose
of prospecting for coal or
other
mineral
therein,
provided he shall not injure,
damage, or destroy the
permanent improvements of
the entryman or patentee,
and shall be liable to and
shall
compensate
the
entryman or patentee for all
damages to the crops on
such lands by reason of such
prospecting.
been resolved, and as of May 2013, no
case
or
controversy
has
arisen.
Nevertheless, in the future, a legal
challenge on pre-emption grounds is
probable. Considering the quantity of
federally owned minerals underlying private
ownership in the western United States, the
outcome of this legal challenge cannot be
overstated for the future of surface damage
acts.
I.
When conducting operations in
Wyoming and many other states in the
Rocky Mountain West, operators will
undoubtedly encounter lands where the
surface and subsurface estates have been
split pursuant to the Stock-Raising
Homestead Act of 1916 (SRHA). The SRHA
“allowed settlers to claim 640 acres of
nonirrigable land that had been designated
by the Secretary of the Interior [(hereinafter
“Secretary”)] as ‘stock raising’ land”;
however,
“[m]ineral
exploration
was
beginning to escalate during this time
period, and the federal government opted to
maintain the mineral rights to all lands
claimed under [the Act].”202 Much like the
surface damages compensation statutes
adopted in the states identified above, the
SRHA provides specific notice and surface
owner compensation requirements of which
the operator must be aware. The following
is only a general overview of those
requirements. One should be intimately
The language of the act limits the
compensable damages to the “crops” on
such land and a limitation on the ability to
injure
permanent
improvements
on
structures.
The
Bureau
of
Land
Management (“BLM”) has taken the position
that the Wyoming Act does not apply to
federally administered lands, whereas the
State of Wyoming has taken the position
that it does.201 Currently, the issue has not
Supremacy on Federal Split Estate Lands, 6
W YO. L. REV. 31, 35 (2006).
200
Overview of the Stock-Raising
Homestead Act of 1916 (SRHA)
43 U.S.C. § 299 (2014).
201
See POWDER RIVER BASIN RESOURCE
COUNCIL, THE STATE OF THE SPLIT ESTATE: A
LANDOWNER PERSPECTIVE: FIVE YEARS AFTER
PASSAGE OF THE W YOMING SPLIT ESTATE STATUTE
7 (2010).(discussing a district court case in
which the court claimed the Act does not apply
to surface estates above federal mineral lands).
See also Matt Micheli, Showdown at the OK
Corral – Wyoming’s Challenge to U.S.
Supremacy on Federal Split Estate Lands, 6
W YO. L. REV. 31, 35 (2006) (discussing federal
pre-emption); D. Bleizeffer, State Stands Behind
Split Estate Law, CASPER STAR TRIBUNE, Jul. 20,
2005, available at http://trib.com/news/state-andregional/state-stands-behind-split-estatelaw/article_fda269d7-ff40-50f9-97cfc018f00cd13c.html (discussing industry and
state reaction to the district court ruling).
202
U.S. DEP’T OF THE INTERIOR, Split Estate
Mineral Ownership, BLM.GOV (last visited Jan.
28,
2014),
http://www.blm.gov/wy/st/en/programs/mineral_r
esources/split-estate.html.
56
familiar with the specifics of these
requirements prior to conducting any
operations on lands claimed under the
SRHA.
surface owner no less than 30 days before
the operator intends to enter the lands.206
For a ninety (90) day period after
submission of the NOITL to the BLM and 30
days after notice is provided to the surface
owner, the operator may enter the lands
covered by the NOITL to explore for
minerals and locate mining claims, so long
as said operations cause only a minimal
disturbance to the surface and do not utilize
mechanized earth moving equipment,
explosives
or
toxic
or
hazardous
materials.207
Under the SRHA, no person other
than a surface owner may enter lands
subject to the Act without first (1) filing with
the BLM a “Notice of Intention To Locate a
Mining Claim” (frequently referred to as a
“NOITL”) and (2) providing notice to the
surface owner.203 Once an operator has
made the determination to develop a certain
parcel of land claimed under the SRHA, the
operator must include the following
information in a NOITL:204
1.
2.
3.
4.
5.
6.
7.
Under federal law, the surface owner
is statutorily entitled to compensation for
any permanent damages to crops and
intangible improvements of the surface, or
loss of income from impairment of grazing
or other uses by the surface owner as a
result of mineral operations.208 In addition,
operators are required to reclaim the lands,
to the maximum extent practical, to a
condition capable of supporting the uses to
which said lands were capable of supporting
prior to the surface disturbance.209
the name and telephone
numbers of all known surface
owners;
names, mailing addresses
and telephone numbers of all
claimants filing the NOITL;
tax records evidencing proof
of surface ownership;
legal description of the lands
covered by the NOITL,
including number of acres;
a map of the land subject to
mineral
exploration
displaying proposed access
routes;
a brief description of the
proposed mineral activities;
and
the
dates
on
which
exploration and/or location of
claims will begin and end.
The operator may not engage in any
other mineral activities (other than those
previously described above), without
“securing the written consent or waiver of
the homestead entryman or patentee;
second, upon payment of the damages to
crops or other tangible improvements to the
owner thereof, where agreement may be
had as to the amount thereof; or, third, in
lieu of either of the foregoing provisions,
upon the execution of a good and sufficient
bond or undertaking to the United States for
the use and benefit of the entryman or
owner of the land, to secure the payment of
such damages to the crops or tangible
Additionally, the operator must
provide the surface owner of record with a
copy of the NOITL by registered or certified
mail.205 Notice must be provided to the
206
203
43 C.F.R. § 3838.11(d)(1); 43 U.S.C. §
299(3).
43 U.S.C. § 299(b)(1)(A) (2014).
207
43 U.S.C. § 299(2); 43 C.F.R. § 3838.12
(2014).
43 C.F.R. § 3838.15(a).
208
43 U.S.C. § 299.
205
209
43 U.S.C. § 299(h).
204
43 C.F.R. § 3838.11.
57
improvements of the entryman or owner, as
may be determined and fixed in an action
brought upon the bond or undertaking in a
court of competent jurisdiction against the
principal and sureties thereon.”210 Stated
more succinctly, an operator is prohibited
from conducting mineral activities on SRHA
lands without (1) the consent of the surface
owner, or (2) authorization from the
Secretary of the Interior.211
The plan of operations submitted to
the Secretary must include procedures for
the minimization of damages to crops and
tangible improvements to the surface
owner, procedures for the minimization of
disruption to grazing or other uses by the
surface owner, and payment of a fee for the
use of the surface during mineral activities
equivalent to the loss of income to the ranch
operation.214 The amount of the fee is
established by the Secretary taking into
account the acreage involved and the
degree of potential disruption to existing
surface uses during mineral activities, not to
exceed the fair market value of the land.215
This fee must be paid to the surface owner
in advance of any mineral activities.216 Once
these steps are completed in lieu of the
execution of a surface use agreement, the
operator may conduct mineral activities,
defined as any activity for, related to or
incidental to mineral exploration, mining,
and beneficiation activities for any locatable
mineral on a mining claim.217 As discussed
above, the surface owner has the right to
challenge the sufficiency of the bond in a
court of competent jurisdiction.
It is advisable that a landman begin
negotiating an SUA with the surface owner
as soon as practical after providing notice
pursuant to the NOITL. The BLM requires
that the operator make a good faith effort to
execute an SUA with the surface owner.
The federal statutes cited above set no
parameters
or
limitations
regarding
negotiations or damage compensation
calculations. Accordingly, much like in the
states described above, the operator and
surface owner are free to negotiate
compensation in any way the parties deem
appropriate.
If good faith negotiations with the
surface owner fail, the operator must (1)
post a bond with the Secretary and (2) file a
plan of operations with the BLM. The bond
must
be
sufficient
to
insure
(a)
compensation for any permanent damages
to crops and intangible improvements of the
surface, and (b) loss of income due to loss
or impairment of grazing or other uses by
the surface owner as a result of mineral
operations.212 In determining the amount of
the bond, the Secretary shall consider,
where appropriate, the potential loss of
value due to the estimated permanent
reduction in utilization of the land.213
210
Like the state surface damages acts
described above, federal law imposes stiff
penalties on operators who fail to comply
with the above statutory provisions. In the
event of a compliance failure, a surface
owner may bring an action in the
appropriate United States district court, and
the court may award double damages plus
costs for willful misconduct or gross
negligence.218 Accordingly, it is imperative
that one be aware of and understands all of
the unique implications in dealing with
SRHA.
214
43 U.S.C. § 299(f)(1).
43 U.S.C. § 299(g).
43 U.S.C. § 299(a).
215
211
43 U.S.C. § 299(c).
216
Id.
212
43 U.S.C. § 299(e)(1).
217
43 U.S.C. § 299(o)(1).
213
43 U.S.C. § 299(e)(2).
218
43 U.S.C. § 299(k).
58
CONCLUSION
Perhaps in years past, operators could
comfortably rely on the rights afforded by
the dominant estate theory in order to
secure rights to access and use of severed
surface estates. However, the tables have
been turning, severely shifting the balance
of power in favor of the surface owners.
This shifting effect has been in large part
due to changing social and political
pressures, the creation of many legal
doctrines, statutes, and regulations that
severely limit operators’ rights to surface
access and use, and the advent of surface
owner protection groups that advocate farreaching surface-friendly provisions. One
should be well-versed in the applicable legal
doctrines,
statutory
and
regulatory
schemes, and be keenly aware of what to
expect in an SUA. Those who understand
these laws, the constituent parts and
purposes of an SUA, and the importance of
meaningful negotiation can best protect the
operator’s interest, while avoiding litigation.
59
RECENT TEXAS OIL AND GAS CASES
Richard F. Brown
Brown & Fortunato, P.C.
Amarillo, Texas
Gonyea v. Kerby1 construed two
conflicting contracts for deed against the
draftsman after considering extrinsic
evidence. Gonyea contracted with Kerby to
sell and convey two lots that together
comprised just over two acres in Alvarado,
Texas. Gonyea drafted two contracts for
deed, signed them, and sent them to Kerby.
Kerby signed both, sent one back to
Gonyea, and Kerby kept the other. The
contract retained by Kerby stated that the
mineral rights in the property would be
conveyed to the purchaser when the note
for the deed had been paid in full, while the
contract returned to Gonyea stated just the
opposite—that no mineral rights would be
conveyed to the purchaser even when the
note was paid in full. By the contract’s
terms, it was a monthly installment sale over
a 15-year term. In 2005, Gonyea signed an
oil and gas lease on the property. In 2008,
shortly before the final payment was due,
Kerby noticed that there was oil and gas
activity happening on the property and
contacted Gonyea to inquire about the
mineral rights. Gonyea told Kerby that
Kerby did not own the mineral rights and
that they were not for sale. Kerby made his
final payment, and when Gonyea refused to
convey the minerals, Kerby sued Gonyea
for breach of contract.2
the jury finding that the parties had agreed
to convey the minerals.4
The court found that neither
contract, when read alone, was ambiguous,
and that the ambiguity only results from
reading the two contracts together.5 The
court cited the usual rules of construction
that the intent of the parties is to be
determined from the written agreement and
that separate instruments executed at the
same time, between the same parties, and
relating to the same subject matter may be
considered together and construed as one
contract.6
The
court
resolved
this
conundrum by concluding that the jury had,
in effect, picked which contract was the
agreement between the parties, and that the
determination of which contract was the
agreement was a fact question.7 The
existence of the second contract that
differed from the first was parol evidence
that there were issues of fact which were for
the jury to decide. The fact that Gonyea
drafted and Kerby kept one of the two
contracts was enough for the jury to find
that the parties agreed on the contract
Kerby kept.8
Moreover, if forced to construe the
two contracts together, the court held that it
would still find for Kerby, as a matter of law,
because Gonyea drafted both of the
contracts for deeds. Texas law provides that
The parties agreed that their
agreement was ambiguous, and Kerby
obtained a jury verdict on his breach-ofcontract claim.3 The issue on appeal was
the sufficiency of the evidence to support
4
Id. at *1–2.
No. 10–12–00182–CV, 2013 WL 4040117
(Tex. App.—Waco Aug. 8, 2013, pet. filed)
(mem. op.).
5
Id. at *5 n.4.
6
Id. at *4.
2
Id. at *1–2
7
Id. at *5.
3
Id. at *2.
8
Id.
1
60
contracts are to be construed against the
draftsman.9
as the functional equivalent when the
excepted interest remains with the grantor.14
Thus, if the exceptions in the conveyances
to the lot owners were effective to exclude
all of the minerals, then Thomason and
Lupton kept 1/2 of the minerals for
themselves.15
Because the two contracts were so
clearly irreconcilable, the case highlights the
significance of a fact finding at the trial court
level as to the fact of the “agreement” of the
parties and the risk of being the draftsman
under the law applicable to the construction
of the agreement of the parties.
The Reese Deed was explicit in its
reservation of a one-half mineral interest,
but the Hopkins Deed did not contain a
similar provision. The court ultimately held
that “[n]either the reference to the Reese
deed nor the reference to the Hopkins deed
created a new reservation or exception of
the 50% interest conveyed to Thomason
and Lupton. They conveyed the mineral and
surface estates subject to any previously
recorded reservations, namely the Reese
reservation.”16 “The meaning of the phrase
‘all oil, gas[,] and other minerals as
recorded’ is simply not a clear exception of
the 50% mineral interest owned by
Thomason and Lupton.”17 The court
concluded that the Hopkins deed must be
construed against the grantors to confer
upon the grantee lot owners the greatest
estate that the terms of the conveyances
will permit, and that a reservation of
minerals will not be implied.18
Thomason v. Badgett10 held that a
deed should be construed to grant the
greatest estate possible to the grantee, and
a grantor’s attempt to reserve or except
mineral rights from a deed will not be
implied. Reese conveyed to Hopkins with
warranty, reserving 1/2 of the minerals
(“Reese Deed”). Hopkins conveyed to
Thomason and Lupton with warranty, save
and except the 1/2 of the minerals
previously reserved by Reese (“Hopkins
Deed”). Thomason and Lupton then
subdivided the land into lots and conveyed
to the lot owners with warranty: “‘[s]ave &
except: all oil, gas[,] and other minerals as
recorded in [the Reese Deed] and [the
Hopkins deed].’”11 The issue was whether
Thomason and Lupton reserved 1/2 of the
minerals for themselves under the deeds to
the lot owners, or whether they conveyed
that 1/2 of the minerals to the lot owners.12
The case applies established rules
of deed construction to hold that in the
absence of a clear, effective exception, a
deed must be construed against the grantor
to convey the greatest possible estate to the
grantee and that a reservation of minerals
will not be implied.
Thomason and Lupton conceded
that they did not reserve the mineral
interest, but they “excepted” it from the
conveyances, which functioned as a
reservation.13 An exception is not the
equivalent of a reservation, but can operate
9
14
Id. (citing Pich v. Lankford, 302 S.W.2d 645,
650 (Tex. 1957)).
Id.
10
No. 02–12–00303–CV, 2013 WL 3488254
(Tex. App.—Fort Worth July 11, 2013, pet.
denied) (mem. op.).
11
12
13
15
Id.
16
Id.
Id. at *1.
17
Id. at *3.
Id.
18
Id. (citing Lott v. Lott, 370 S.W.2d 463, 465
(Tex. 1963)).
Id. at *2.
61
Meekins v. Wisnoski19 held that a
receiver’s deed out of an estate was
effective to convey all of the interests owned
by the decedent, divested all title the
devisees would have otherwise acquired
under the will, and that no reservation of the
minerals would be implied into the receiver’s
deed. Simplified, Lavern Meekins (“Lavern”)
owned 1/2 of the surface and 1/2 of the
minerals at the time of her death. Her
husband, Robert F. Meekins, Sr. (“Meekins,
Sr.”) owned the other 1/2 of the surface.
Lavern’s will left all of her share to Robert F.
Meekins, Jr. (“Meekins, Jr.”).20 Meekins, Sr.
filed an application for appointment of a
receiver in Lavern’s estate to pay unpaid ad
valorem taxes owed by the estate. The
probate court appointed a receiver to sell
the property and to distribute the proceeds
equally between Meekins, Sr. and Meekins,
Jr.21 The partition order did not specify
whether the probate court intended to
partition the mineral estate or only the
surface estate.22 The receiver for Lavern’s
estate and Meekins, Sr. executed a deed
conveying the property with no reservations
to the Wisnoskis.23 Meekins, Jr. did not
appeal the probate court’s approval of the
sale or file a bill of review.24 Meekins, Jr.
filed suit in trespass to try title against the
Wisnoskis, claiming that: (1) Lavern’s
interests in the surface and the minerals
passed to Meekins, Jr. by Lavern’s will, and
thus could not be conveyed by the receiver,
and (2) the receiver’s deed did not convey
the minerals.25 The main issue in the case
was whether the receiver’s deed conveyed
to the Wisnoskis the interests in the
property that Lavern owned on the date of
her death.26
Texas Probate Code § 37 provides:
“‘When a person dies, leaving a lawful will,
all of his estate devised or bequeathed by
such will . . . shall vest immediately in the
devisees or legatees of such estate . . . ;
subject, however, to the payment of the
debts of the testator.’”27 Meekins, Jr. argued
that because the property belonging to the
estate vested in him, the receiver’s deed
conveyed nothing.28 The court disagreed.
Meekins, Jr. held a vested property interest,
but his interest was subject to the
administration of Lavern’s estate. “The
administrator of the estate holds legal title
and a superior right to possess estate
property and to dispose of it as necessary to
pay the debts of the estate. . . . If the
administrator exercises this dispositive
power, the sale divests the beneficiary of his
interest in the property.”29 “Similarly, a
probate court may appoint a receiver to
partition and sell estate property for
purposes of administration and settlement
of the estate.”30 Here, because there was a
need to pay unpaid taxes, the receiver had
the authority to convey the estate’s interest
in the property to the Wisnoskis.31
26
27
Id. at 697 (quoting Tex. Prob. Code Ann.
§ 37).
19
404 S.W.3d 690 (Tex. App.—Houston [14th
Dist.] 2013, no pet.).
20
Id. at 692–93.
21
Id. at 693.
22
Id. at 697 n.7.
23
Id. at 693.
24
Id.
25
Id. at 696–97.
Id. at 697.
28
Id. at 697–98.
29
Id. at 698 (citing Tex. Prob. Code Ann. § 37;
Woodward v. Jaster, 933 S.W.2d 777, 781 (Tex.
App.—Austin 1996, no writ)).
30
Id. (citing In re Estate of Herring, 983 S.W.2d
61, 65 (Tex. App.—Corpus Christi 1998, no
pet.)).
31
62
Id.
including Robert Wormser (“Wormser”).38
PanAm provided Wormser with a cubicle,
an office landline, a company email domain
name, and the president of PanAm knew
exactly what Wormser was doing on behalf
of PanAm.39 Wormser contacted William
Elder (“Elder”), the attorney responsible for
negotiating leases on behalf of the Maud
Smith Estate (“Maud”), to negotiate a lease
on Maud’s property for PanAm. Wormser
identified
himself
as
a
PanAm
representative, but never disclosed that he
was an independent contractor. Wormser
and Elder agreed on terms, and Wormser
sent Elder a form lease from his PanAm
email account. On June 2, 2008, Elder
accepted and emailed a copy of the signed
lease to Wormser and asked for the lease
bonus.40 On July 21, 2008, Elder sent the
original lease to PanAm. On August 12,
2008, PanAm acknowledged receipt of the
lease.41 After the price of oil dropped
precipitously,
PanAm
asserted
that
Wormser had no authority to execute leases
on its behalf.42 Apparently, PanAm dodged
the payment questions from Elder for about
three months before repudiating the validity
of the lease, and PanAm’s possession of
the lease prevented Maud from leasing to a
third party.43 Elder attempted to collect the
lease bonus for two months, and after
seven months, Maud sued PanAm for
breach of contract due to failure to pay the
lease bonus. The issues on appeal were
whether Wormser held the apparent
authority to bind PanAm and whether
PanAm ratified the lease by failing to timely
repudiate the lease.44
The receiver’s deed, in the blank
provided
for
“Reservations
from
32
Conveyance,” stated “None.” Meekins, Jr.
conceded there was no express reservation
of the minerals, but asserted that there was
an implied reservation of the minerals.33 The
receiver’s deed in the legal description
included a reference to the 1958 deed,
which was the instrument that originally
severed the surface and the minerals
estates.34 However, a reservation by
implication in favor of the grantor is not
favored by the courts.35 Because there was
no language in the receiver’s deed clearly
showing a reservation of the mineral rights,
the court held that the receiver’s deed
conveyed all of the estate’s interest to the
Wisnoskis.36
The significance of the case is that it
continues the line of authorities which
refuse to imply a mineral reservation in
grantor. Here, Meekins, Jr. had his chance
to attack the receiver’s deed in the probate
proceeding, but once that avenue was
closed, there was not much chance that the
deed could be successfully challenged and
no chance that the power of the receiver
could be challenged.
PanAmerican Operating, Inc. v.
Maud Smith Estate37 held that an
independent landman’s apparent authority
and the company’s failure to promptly
repudiate an oil and gas lease made the
lease
binding
on
the
company.
PanAmerican Operating, Inc. (“PanAm”)
hired landmen as independent contractors,
32
Id. at 699–700.
33
Id. at 699.
34
Id. at 699–700.
35
Id. at 699.
36
Id. at 700.
37
409 S.W.3d 168 (Tex. App.—El Paso 2013,
pet. denied).
63
38
Id. at 171.
39
Id. at 173–74.
40
Id. at 171, 176 n.4.
41
Id. at 176 n.4.
42
Id. at 174–75.
43
Id. at 176.
44
Id.
“Apparent authority arises when a
principal either knowingly permits its agent
to hold himself out as having authority or
acts with such a lack of ordinary care as to
clothe its agent with indicia of authority.”45
Silence may also constitute a manifestation
of apparent authority.46 It was undisputed
that Wormser had authority to obtain leases
on PanAm’s behalf and to negotiate on
PanAm’s behalf. The court held that a
reasonably prudent person would have
believed Wormser possessed the authority
to contract on PanAm’s behalf because
PanAm acted with “such a lack of ordinary
care as to clothe Wormser with indicia of
authority.”47
demonstrate that PanAm performed an
“intentional act that was inconsistent with
any intention to avoid the lease.”51 The
“intent may be inferred from the acceptance
of benefits under the lease after having full
knowledge of the act that would make the
lease voidable.”52 The benefit PanAm
received was obtaining a signed lease
without having to pay until PanAm
determined if honoring the lease made
economic sense. Therefore, PanAm ratified
the lease by failing to repudiate after
obtaining sufficient knowledge of the facts.
The significance of this case is that it
highlights the risk in failing to promptly
repudiate a lease or a contract to lease. The
industry frequently uses contract landmen
and the facts in this case were particularly
bad for PanAm. But the issues about
authority can arise in a narrower context,
such as the specific business points (bonus,
royalty, term) in a lease, other lease
provisions, or the lease form itself. Such
issues would be more common than a
complete repudiation of authority, but the
landman’s apparent authority and the
company’s acquiescence will be equally
important on those issues.
“Ratification is the adoption or
confirmation, by a party with actual
knowledge of all material facts, of a prior act
that did not then legally bind that party and
which that party had a right to repudiate.”48
“A party ratifies a contract by acting under it,
performing under it, or affirmatively
acknowledging it.”49 PanAm knew all the
material facts surrounding Wormser’s
acquisition of the lease, and “by keeping the
lease and failing to repudiate it when
presented with the opportunity to do so,
[PanAm] affirmatively acknowledged its
validity, thereby ratifying it.”50
45
Fain Family First Ltd. P’ship v. EOG
Res., Inc.53 held that a well is not capable of
producing in paying quantities for purposes
of authorizing a shut-in royalty payment, if
the production is not sufficient to justify
making the connection to a nearby pipeline.
The mere existence of the pipeline does not
by itself satisfy the requirement that lessee
46
51
PanAm argued there was no clear
evidence PanAm intended to ratify the
lease. The court dismissed this argument
because Maud was only required to
Id. at 172 (citing Gaines v. Kelly, 235 S.W.3d
179, 182 (Tex. 2007)).
Id. at 172–73 (citing RESTATEMENT (THIRD) OF
AGENCY § 1.03, cmt. b (2006)).
47
Id. (citing Old Republic Ins. Co., Inc. v. Fuller,
919 S.W.2d 726, 728 n.1 (Tex. App.—
Texarkana 1996, writ denied)).
Id. at 173.
52
Id. (citing Williams v. City of Midland, 932
S.W.2d 679, 685 (Tex. App.—El Paso 1996, no
writ)).
48
Id. at 176 (citing Thomson Oil Royalty, LLC v.
Graham, 351 S.W.3d 162, 165 (Tex. App.—
Tyler 2011, no pet.)).
49
Id. (citing Thomson Oil, 351 S.W.3d at 166).
50
Id. at 177.
53
No. 02–12–00081–CV, 2013 WL 1668281
(Tex. App.—Fort Worth Apr. 18, 2013, no pet.)
(mem. op.).
64
must have “facilities for marketing gas.”
EOG Resources, Inc. (“EOG”) acquired a
mineral
lease
from
Fain
Family
Management Corporation and First Limited
Partnership (“FFFLP”) on June 22, 2004,
with a primary term of three years.54
Additionally, EOG and FFFLP entered into
an A.A.P.L. Form 610–Model Form
Operating
Agreement–1989
(“JOA”)
whereby FFFLP could elect to participate in
EOG’s efforts to develop the minerals by
paying 1/8th of the development costs.
Pursuant to the JOA, on May 2, 2007,
FFFLP agreed to participate in drilling the
Fain 1H well, and on November 7, 2007,
FFFLP agreed to participate in the Fain 4H
well. EOG drilled the wells and sent invoices
to FFFLP. When FFFLP failed to pay these
invoices, EOG filed a suit on sworn account
and for breach of contract. The trial court
granted EOG’s motion for summary
judgment.55
by production,
otherwise.”59
extension,
renewal
or
The lease included a shut-in royalty
clause, which stated that if, after the
expiration of the primary term, there was a
shut-in gas well capable of producing, then
the Lessee may pay a shut-in royalty and
the well would be considered to be
producing. EOG produced evidence in the
form of an email dated June 2008 that EOG
considered itself to be operating under the
shut-in provision of the lease, and that EOG
paid shut-in royalties in March of 2008. The
court observed that “capable of producing”
meant “capable of producing in paying
quantities,” and that “a lack of ‘facilities for
marketing the gas’ is sufficient to show that
a well is not capable of production in ‘paying
quantities.’”60 There was evidence that the
wells were not producing enough gas to
justify the cost of connecting them to an
existing pipeline. The court held this implied
that the wells were not capable of
production in “paying quantities” because
EOG had no facilities for marketing the
gas.61 This presented a question of material
fact and summary judgment was improper.
To prevail on its breach-of-contract
claim on traditional summary judgment,
EOG had to prove that the parties had a
valid, enforceable contract.56 FFFLP argued
that the JOA terminated before FFFLP
agreed to participate in the Fain 4H well and
before EOG incurred the expenses that it
billed to FFFLP.57 The JOA’s termination
clause was tied to lease expiration.58
Specifically, under Article XIII of the JOA,
the parties chose the option that states the
JOA will continue in force “[s]o long as any
of the Oil and Gas Leases subject to this
agreement remain or are continued in force
as to any part of the Contract Area, whether
The significance of the case is that it
adds some additional definition to the
meaning of “facilities for marketing gas” in
the context of a shut-in royalty clause. The
existence of a nearby pipeline is not
enough, if the well is not producing enough
gas to justify the cost of making a
connection to that pipeline.
Indian Oil Company, LLC v. Bishop
Petroleum Inc.62 held that in the absence of
59
54
Id. at *1, *3, *4.
55
Id. at *1.
56
Id. at *2.
57
58
Id.
60
Id. at *5 (citing Anadarko Petroleum Corp. v.
Thompson, 94 S.W.3d 550, 558–59 (Tex. 2002);
Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959)).
61
Id. at *6.
62
Id. at *5 (citing Anadarko, 94 S.W.3d at 559).
406 S.W.3d 644 (Tex. App.—Houston [14th
Dist.] 2013, pet. filed).
Id. at *3.
65
enrichment.66 Operator prevailed in the trial
court, and only Non-Operator appealed.67
an express or implied release, a nonoperator assigning its interest under a
1989 M.F.O.A. remains liable for operating
costs and plugging and abandonment costs.
Bishop Petroleum (“Operator”) was the
operator under an A.A.P.L. Form 610 —
1989 Joint Operating Agreement (“JOA”) for
a well in Escambia County, Alabama.
Operator drilled the Scott Paper 27-1 Well
which produced from 1993 until 2007.
William E. Trotter, II (“Non-Operator”) was a
non-operating working interest owner under
the JOA. In 2002, Non-Operator assigned
his 8.5% working interest in the well to
Indian Oil Company, LLC (“Assignee”),
notified Operator of the assignment, and
thereafter, Operator distributed revenues
and billed expenses to Assignee.63
Non-Operator
contended
that
Operator had breached the JOA as a matter
of law by (1) failing to provide daily
workover reports68 and (2) failing to issue a
new AFE when the workover became
dramatically more complex and expensive
than the original AFE anticipated.69 NonOperator also contended that NonOperator’s liability for costs incurred should
be limited to costs incurred in connection
with operations in which Non-Operator
agreed to participate prior to Non-Operator’s
assignment to Assignee.70
Non-Operator’s argument as to
daily workover reports was based on
Article V.D.7(b) of the JOA, which stated:
When the well stopped producing in
2007, Operator eventually proposed a
workover under the "July AFE" in the
amount of $589,800, which Assignee and
various other working interest owners
approved, but it was not approved by NonOperator.64 Workover operations started on
October 1, 2007, and were more difficult
and lengthy than Operator anticipated. As a
result, Operator abandoned the workover
efforts in January 2008 after incurring
approximately $1.6 million in costs. In 2009,
Operator sent an AFE to the working
interest owners in the amount of $243,300
for plugging and abandonment.65
Operator will send to Non-Operators
such reports, test results, and notices
regarding the progress of operations on the
well as the Non-Operators shall reasonably
request, including, but not limited to, daily
drilling reports, completion reports, and well
logs.71
The court noted that this language
requires the operator to provide such
reports as non-operators “reasonably
request,” and did not require the provision of
“any and all requested reports.”72 Because
Non-Operator never requested a report,
Operator’s failure to provide reports could
not be considered breach of contract.
Neither Operator nor Assignee paid
any expenses associated with the reworking
or plugging and abandonment. Operator
sued Non-Operator, Assignee, and various
other working interest owners for breach of
contract, quantum meruit, and unjust
66
Id. at 648–49.
67
Id. at 649.
68
Id. at 653–54.
69
Id. at 654–55.
63
Id. at 647.
70
Id. at 655.
64
Id. at 648.
71
Id. at 654.
65
Id.
72
Id.
66
Non-Operator also alleged that Operator
was under a duty to provide daily workover
reports because such reports had been
requested by one of the other working
interest owners. The court noted that NonOperator offered no authority for the
proposition that “one working interest
owner’s request for reports obligated
[Operator] to send reports to every working
interest owner, including those who made
no such request.”73 The court held that
Non-Operator did not establish that by
failing to provide workover reports, Operator
had breached the JOA as a matter of law.
incurred under the JOA, and (2) NonOperator had not consented to the July
AFE, and therefore, could not have incurred
any expenses under it.76
The parties’ disagreement on this
issue centered on different interpretations of
the Texas Supreme Court’s opinion in
Seagull Energy E & P, Inc. v. Eland Energy,
Inc.77 The Eland Court held that an assignor
of a working interest subject to a joint
operating agreement remained liable for
operating expenses when the assignee
failed to pay for the operating expenses
attributable to that interest (in Eland,
plugging and abandonment costs).78
Operator asserted that, under Eland, in the
absence of an express or implied release,
Non-Operator remained liable for all
expenses incurred under the JOA,
notwithstanding Operator’s assignment to
Assignee. This court distinguished Eland,
because the operating agreement construed
in Eland did not address the assignor’s
liability for expenses incurred subsequent to
the assignment. It was silent as to
continuing liabilities.79 The JOA in this case
was not silent as to a party’s ongoing
liability subsequent to an assignment. The
pertinent language from the JOA provided:
Non-Operator also contended that
Operator should have issued a new AFE
when the workover operations contemplated
by the July AFE became dramatically more
expensive than originally anticipated and
additional operations were undertaken, and
that Operator’s failure to do so was a
breach of the JOA.74 Non-Operator
contended that the evidence established
Operator’s breach as a matter of law, but
the court noted that the evidence was
contradictory. An expert witness had
testified that issuing a new AFE would have
required dismissing the workover rig and
that the fishing operations that were
conducted were a normal part of the kinds
of workover operations contemplated by the
July AFE. Therefore, the court held that
Non-Operator had failed to show that
Operator had breached the JOA.
[N]o assignment or other dis-position
of interest by a party shall relieve such party
of obligations previously incurred by such
party hereunder with respect to the interest
transferred, including without limitation the
obligation of a party to pay all the costs
attributable to an operation conducted
hereunder in which such party has agreed
The jury found that Non-Operator
was liable for $336,393.42 for expenses
incurred under the JOA.75 Non-Operator
argued that there was no evidence to
support this amount because (1) NonOperator had assigned his interest to
Assignee in 2002, and Non-Operator was
thus not liable for expenses subsequently
73
Id.
74
Id. at 654–55.
75
76
Id.
77
207 S.W.3d 342 (Tex. 2006).
78
Bishop Petroleum, 406 S.W.3d at 657 (citing
Eland, 207 S.W.3d at 344).
79
Id. at 657–58 (citing Eland, 207 S.W.3d at
346–47).
Id. at 649, 656.
67
to participate
assignments.80
prior
to
making
such
providing reports under an operating
agreement generally went off on evidence
points, the opinion suggests that under the
1989 M.F.O.A., the obligation to deliver
reports requires a reasonable request and
not every operational event of a workover
will trigger an obligation to issue a new AFE.
This language made Non-Operator
liable for expenses “previously incurred,”
i.e., incurred before Non-Operator assigned
to Assignee. Non-Operator conceded that
Non-Operator continued to be liable for
monthly operating costs and the costs of
plugging and abandoning the well.
However, Non-Operator had assigned the
working interest to Assignee in 2002, and
Operator did not request approval for the
workover until 2007. Under the “previously
incurred” language, Non-Operator could not
be liable for expenses incurred pursuant to
the July AFE.81
Southwestern Energy Production
Co. v. Berry-Helfand84 held that the use for
personal gain of a prospect analysis
disclosed under a confidentiality agreement
was a misappropriation of a trade secret.
Over the course of several years, Helfand (a
reservoir engineer) and her geologist
partners conducted a detailed analysis of
public and semi-public production data for
600 wells in a six county area. They
identified ten sweet spots favorable for
production from the James Lime formation
with several stacked pays. Helfand focused
on two of the prospects where leases were
available and began leasing with the object
of selling her prospects for cash and an
overriding royalty interest. In February 2005,
Southwestern Energy Production Company
(“Sepco”) signed a confidentiality agreement
with Helfand regarding the materials to be
presented by Helfand, and Exhibit A,
describing the area subject to the
noncompetition agreement, was limited to
those two prospects. Helfand then
presented to Sepco the results of her
research and analysis identifying all of the
sweet spots. Prior to the presentation,
Sepco had no interest in the James Lime
because of poor production history. After
the presentation, Sepco declined to
participate in Helfand’s prospects, because
the prospects failed Sepco’s economic
criteria. Helfand promptly sold the same two
prospects to Petrohawk. Soon after the
Helfand/Sepco meeting, Sepco began
leasing land in the area of Helfand’s sweet
spots, ultimately acquiring 1,800 leases on
or near the sweet spots. Two years after the
The amount the jury awarded
included workover costs, monthly operating
expenses, and plugging and abandonment
expenses.82 Although the evidence was
insufficient to support the entire damage
amount awarded against Non-Operator, it
was sufficient to support some damages.
The court remanded the case to determine
liability and damages.83
The significance of the case is that it
limits the continuing obligations of nonoperators under Eland, at least under the
1989 M.F.O.A.,
to
those
obligations
“previously incurred.” This does not mean
accrued, but incurred, so the assigning nonoperator will continue to be liable for
monthly operating costs, plugging and
abandonment costs, and other liabilities
included in the operating agreement.
Presumably the assigning non-operator will
be able to avoid only those subsequent
liabilities
that
require
an
express
subsequent consent. Although the issues on
80
Id. at 657.
81
Id. at 657–58.
82
Id. at 659.
83
84
411 S.W.3d 581 (Tex. App.—Tyler 2013, no.
pet.).
Id. at 660.
68
presentation, Sepco drilled a successful
James Lime well and then began a large
scale drilling program in the James Lime.
Ultimately, Sepco drilled or participated in
over 80 James Lime wells, all successful
and all clustered in and around Helfand’s
sweet spots.85 Helfand filed suit against
Sepco in February 2009.86 The jury found
against Sepco on five liability theories,
including common law trade secret
misappropriation. The trial court awarded
approximately $11 million in actual
damages to Helfand.87
Trade secret misappropriation may be
proven by circumstantial evidence.92 “A
person must bring suit for misappropriation
of a trade secret no later than three years
after the misappropriation is discovered or
by the exercise of reasonable diligence
should have been discovered.”93
Sepco maintained that, even if
Helfand’s analysis was a trade secret, there
was insufficient evidence to show that
Sepco misappropriated the trade secret by
unauthorized use.94 Essentially, Sepco
claimed that the circumstantial evidence
supporting Helfand’s misappropriation claim
amounted to an unsupported “before and
after argument,” i.e., Sepco had no James
Lime wells before meeting with Helfand and
three years later it had more than 80 wells.95
Sepco also offered other plausible
explanations
for
its
James
Lime
development, claiming that the well
locations chosen were the product of its
own in-house study.96
“A trade secret is ‘any formula,
pattern, device or compilation of information
which is used in one’s business and
presents an opportunity to obtain an
advantage over competitors who do not
know or use it.’”88 The court quickly
concluded
that
Helfand’s
“massive
compilation and analysis” of data drawn
from public and semi-public sources was a
trade secret, because it led her to identify
sweet spots and stacked pays.89 Further,
the court determined that Helfand’s trade
secret was not lost when she shared the
material with other operators because these
disclosures were conditioned on the
execution of confidentiality agreements.90
The court disagreed. Although
Sepco had no interest in the James Lime
prior to the meeting, in the year that
followed, it took approximately 1,800 leases
that included James Lime drilling rights,
almost all of which were in Helfand’s sweet
spots.97 Thereafter, Sepco drilled more than
80 successful James Lime wells, all of
which were in or near Helfand’s sweet
spots.98 The timing of Sepco’s drilling of the
James Lime wells coincided with the time
A plaintiff seeking to prevail on a
trade secret misappropriation in Texas must
prove “(1) the existence of a trade secret,
(2) a breach of a confidential relationship or
improper discovery of the trade secret, (3)
use of the trade secret, and (4) damages.”91
85
Id. at 586–89, 598.
92
86
Id. at 589, 602.
93
87
Id. at 590.
Id.
Id. at 602 (citing Tex. Civ. Prac. & Rem. Code
Ann. § 16.010(a) (West 2002)).
94
Id. at 597 (quoting In re Bass, 113 S.W.3d
735, 739 (Tex. 2003)).
Id. at 598.
95
Id. at 599–600.
89
Id. at 597–98.
96
Id. at 599.
90
Id. at 598.
97
Id. at 599–600.
91
Id.
98
Id. at 600.
88
69
January 2009.106 Accordingly, the court held
that there was no evidence that Helfand
knew or should have known that Sepco had
misappropriated her trade secret before
February 16, 2006.107
required to implement a drilling program to
exploit Helfrand’s secrets.99 Further, Sepco
failed to produce sufficient independent
research to explain its selection of drill
sites.100 According to the court, the
circumstantial
evidence
supporting
Helfand’s claim was both legally and
factually sufficient to support a finding that
Sepco misappropriated and used Helfand
trade secrets during the term of the
confidentially agreement.101
Several other interesting issues
were raised in the case. The court held that
confidentiality
agreements
do
not
necessarily create fiduciary relationships,
and this confidentiality agreement did not
create a fiduciary relationship.108 There can
be no theft of a trade secret when the secret
is voluntarily delivered.109 There is an
extensive analysis of the appropriate
measure of damages, methodology of
calculating damages, and proof of
damages.110
Sepco also argued that Helfand’s
claim of misappropriation was barred by the
statute of limitations.102 Sepco maintained
that Helfand knew or should have known of
her wrongful injury before February 17,
2006, three years before she sued
Sepco.103 In particular, Sepco cited emails
Helfand sent in May 2005 which expressed
her frustration with Sepco’s failure to return
all the materials provided at the February
2005 presentation, as well as concern about
the possible misuse of her trade secret.
Sepco returned her materials shortly
thereafter with assurances it retained
nothing. Helfand was entitled to rely on
these assurances and “had no objective
reasonable basis for further inquiry into
Sepco’s conduct.”104 Even if she had made
further inquiries before October 2007, when
Sepco drilled its first James Lime well, her
investigation would have revealed nothing,
because the pattern of James Lime wells
would not be apparent for many months
thereafter.105 Helfand testified that she first
learned of Sepco’s misappropriation in
99
This case is significant because of
the holding that a prospect analysis can be
a trade secret and that misappropriation
may
result
in
substantial
liability.
Confidentiality agreements are commonly
used in the industry; the specific terms and
conditions of this confidentiality agreement
are commonly included, and the attendant
risks and protections are highlighted by this
case. Sepco protected itself against the
noncompetition provision by limiting the
scope of the lands described on Exhibit A,
but lost this case because it (1) used the
trade secret, and (2) the use was during the
term of the agreement.
Anadarko Petroleum Corp. v.
Williams Alaska Petroleum, Inc.111 held that
course of performance by the parties was
part of a contract for the purchase and sale
Id.
100
Id.
106
Id.
101
Id.
107
Id. at 604.
102
Id. at 602.
108
Id. at 591–94.
103
Id. at 602–03.
109
Id. at 599–601.
104
Id. at 603.
110
Id. at 605–14.
105
Id. at 603–04.
111
737 F.3d 966 (5th Cir. 2013).
70
of oil under the U.C.C. and should be
considered regardless of whether the
contract was ambiguous. Anadarko sold oil
to Williams under two purchase agreements
in 2000-2002. Both of these agreements
contained a provision that tied the contract
price for crude oil to other factors, including
a third-party accounting arrangement for
quality adjustments by the TAPS Quality
Bank for oil shipped through the pipeline.
The contract price between Anadarko and
Williams would be adjusted on a monthly
basis according to the anticipated
adjustment by Quality Bank, but the actual
adjustment would not be known until
Williams actually received debits or credits
from Quality Bank the following month. The
parties would then “true-up” the price, or
bring it to the correct balance, in the
following month’s invoice based on the
actual Quality Bank credits or debits as
received by Williams. Several years after
the contracts terminated, the Federal
Energy Regulatory Commission (“FERC”)
revised the methodology used to assess the
quality of oil entering a pipeline and
retroactively applied the change, effective
as of February 1, 2000. The change in
methodology resulted in over a $9 million
credit paid to Williams attributable to
Anadarko’s oil.112 In August 2007, Williams
received the credit and refused to pay
Anadarko.113
that “‘[u]nless carefully negated,’” the course
of performance becomes “‘an element of the
meaning of the words used,’” and that “‘the
course of actual performance by the parties
is considered the best indication of what
they intended the writing to mean.’”116
The contract payment provision
required that the payments from Williams to
Anadarko must be timely, but there was no
time limitation on Williams’ obligation to
correct any errors in an adjustment found
later. In fact, under the parties’ course of
performance, adjustments were constantly
made to the amount of payment due after
the contract payment date had passed to
“true up” the amount due after the receipt of
the adjustments from the Quality Bank. The
court held that, although the FERC’s
methodology changes did not occur during
the contract period, the parties had a history
of not treating the payment provision’s
monthly schedule as conclusive on the
obligation to pay a final, correct purchase
price.117
The court also held that Williams’
obligation to pay the correct contract price
survived the termination of the contracts.
Upon termination of a contract, all executory
obligations are discharged, but “‘any right
based on prior breach or performance
survives.’”118 An obligation is executory if
both parties have an obligation yet to be
performed.119 The court held that Williams’
obligation to “remit Quality Bank credits . . .
is tied to Anadarko’s prior tender of the
The court held that under the Texas
Uniform Commercial Code (“U.C.C.”), “a
contract for the sale of oil is a contract for
the sale of goods….”114 Williams contended
that, under the U.C.C., the court could not
consider evidence of course of performance
without first finding that the contracts were
ambiguous.115 The court disagreed and held
Ann. § 2.202, cmt. 1 (West 2009)).
116
Id. (quoting Tex. Bus. & Com. Code Ann.
§ 2.202, cmt. 2 (West 2009)).
117
112
113
Id. at 968.
118
Id. (quoting Tex. Bus. & Com. Code Ann.
§ 2.106(c) (West 2009)).
Id. at 971.
114
Id. at 969 (citing Tex. Bus. & Com. Code
Ann. § 2.107(a) (West 2009)).
115
Id. at 971.
119
Id. (quoting Lee v. Cherry, 812 S.W.2d 361,
363 (Tex. App.—Houston [14th Dist.] 1991, writ
denied)).
Id. at 970 (citing Tex. Bus. & Com. Code
71
crude oil.”120 Therefore, the court concluded
that “where Anadarko has already
discharged its full performance under the
contract by tendering the oil, Williams
Alaska’s obligation to pay the correct
contract price, including the Quality Bank
credits, is no longer executory and thus
survives the contract’s termination.”121
access to its property to survey for
Crosstex’s planned natural gas liquids
pipeline, Crosstex filed for declaratory
judgment and a temporary injunction
preventing RRF from interfering with its right
as a common carrier to access and survey
RRF’s tract of land. RRF argued that
Crosstex could not establish its status as a
common carrier or that the pipeline would
be used by the public.124 The trial court held
a hearing on Crosstex’s request for a
temporary injunction and denied the request
without making written findings of fact or
conclusions of law. On appeal, Crosstex
claimed the trial court abused its discretion
in failing to grant the temporary injunction
claiming: (i) its pipelines are a crude
petroleum line given common carrier status
under Section 111.002(1) of the Texas
Natural Resources Code, and (ii) Crosstex
is entitled to common carrier status under
Section 2.105 of the Texas Business
Organizations Code because the pipeline is
available for public use.125
Williams also contended that
Anadarko’s claim was barred by the fouryear statute of limitations. The court
disagreed and held that the contracts were
breached at the time Williams received the
adjustments and failed to remit them to
Anadarko, which was in August of 2007.
Anadarko filed suit in March of 2011, which
was within the limitations period.122
The significance of this case is that
in contracts governed by the U.C.C. (here,
the sale of oil), course of performance is
made part of the contract, is admissible
without a prior finding of ambiguity, and is
considered the best indication of what the
parties intended by their agreement. This
can only be avoided if carefully negated in
the written agreement. Only executory
obligations are discharged by contract
termination.
In response to Crosstex’s claim that
its pipeline is a “crude petroleum line,” RRF
contended that pipelines carrying natural
gas liquids are not crude petroleum
pipelines, and therefore the trial court did
not abuse its discretion in refusing to grant
the temporary injunction. The court
considered the Webster’s Dictionary
definition
of
“crude
petroleum”
as
“petroleum as it occurs naturally, as it
comes from an oil well, or after extraneous
substances (as entrained water, gas, and
minerals) have been removed[.]”126 The
court also considered the Texas Natural
Resource Code’s definition of “crude oil” as
“any naturally occurring liquid hydrocarbon
at atmospheric temperature and pressure
coming
from
the
earth,
including
Crosstex NGL Pipeline, L.P. v. Reins
Road Farms-1, Ltd.123 held that under the
statutes granting pipelines the right to
condemn a right of way, the pipeline must
be for a public use and a natural gas liquids
pipeline may not fit within the statutory
requirement that the pipeline be a “crude
petroleum pipeline.” When Reins Road
Farms-1, Ltd. (“RRF”) repeatedly refused
Crosstex NGL Pipeline, L.P. (“Crosstex”)
120
Id.
121
Id.
124
Id. at 756.
122
Id.
125
Id. at 757–758, 760.
123
126
404 S.W.3d 754 (Tex. App.—Beaumont
2013, no pet.).
Id. at 758 (quoting Webster’s Third New Int’l
Dictionary 546 (2002)).
72
condensate.”127 Because Crosstex’s Vice
President of Corporate Development
testified at the temporary injunction hearing
that the natural gas liquids transported in
the pipeline are extracted from a stream of
crude gas by subjecting the crude gas to
temperatures well below freezing, the
appeals court held that the trial court could
determine that a natural gas liquids pipeline
is different than a crude petroleum pipeline.
Therefore, the trial court did not abuse its
discretion in rejecting Crosstex’s claim that
its natural gas liquids pipeline qualifies as a
crude petroleum pipeline entitling Crosstex
to
common
carrier
status
under
Section 111.002(1) of the Texas Natural
Resources Code.128
discretion in denying Crosstex’s request for
a preliminary injunction.
The significance of this case is the
court’s holding that a natural gas liquids
pipeline may not be the same as a “crude
petroleum pipeline” under the statute, and
that a public use means a public use.
However, review was limited to “abuse of
discretion.”129
In re Texas Rice Land Partners,
Ltd.130 held that the trial court must make a
preliminary finding as to a developer’s
status as a common carrier before issuing a
writ of possession pending final resolution of
the
landowner’s
challenge
to
the
developer’s
common
carrier
status.
Unsuccessful at negotiating the purchase of
an easement necessary for its crude
petroleum pipeline, TransCanada Keystone
Pipeline, L.P. (“TransCanada”) filed a
petition for condemnation of land owned by
Texas Rice Land Partners, L.P., James
Holland, and David Holland (collectively,
“TRL”). The trial court appointed special
commissioners to hear the matter, who then
granted TransCanada the easement and
awarded TRL $20,808 in compensation for
the easement. TRL objected to the
commissioners’ decision and requested a
jury trial on TransCanada’s common carrier
status under the Texas Natural Resource
Code.131
In response to Crosstex’s claim that
it qualified for common carrier status under
Section 2.105 of the Texas Business
Organization Code because its pipeline
would be open for use by the public, RRF
pointed to evidence submitted at the
temporary injunction hearing that the
Crosstex pipeline’s maximum capacity
would be 70,000 barrels per day and that
Crosstex had a pre-existing commitment to
provide its affiliates with 70,000 barrels a
day, leaving virtually no capacity for
customers’ natural gas liquids. Four of the
five contracts Crosstex produced as
evidence of its efforts to obtain unaffiliated
customers to use the pipeline required that
Crosstex purchase the natural gas liquids
before the product entered the Crosstex
pipeline. RRF also pointed to evidence that
the fifth Crosstex contract is with an entity
whose processing plant does not connect to
the proposed Crosstex pipeline. The court
held that this evidence allowed the trial
court to determine that Crosstex was
building a pipeline for the purpose of
transporting its own natural gas liquids, and
therefore, the trial court did not abuse its
TransCanada filed a motion for a
writ of possession pending resolution of the
jury trial and deposited the full award of
$20,808 in the court registry, along with a
surety bond and cost bond. The court
issued the writ of possession to
TransCanada, and TRL filed a petition for
writ of mandamus, claiming the trial court
129
127
Id. at 759 (quoting Tex. Nat. Res. Code Ann.
§ 40.003(6)).
130
128
131
Id. at 757.
402 S.W.3d 334 (Tex. App.—Beaumont
2013, no pet.).
Id.
73
Id. at 336.
abused
its
discretion
in
granting
TransCanada’s writ of possession prior to
resolving its challenge to TransCanada’s
common carrier status.132
commissioners or deposits the amount of
the award into the registry of the court.”136
“Nevertheless,
[the
court]
recognize[d] that there must be evidence in
the record that reasonably supports
TransCanada’s assertion that it is an entity
with ‘eminent domain authority,’ and it was
error for the trial court to refrain from making
such a preliminary finding.”137 However, the
court held that the trial court’s failure to
make such a finding was harmless, given
uncontroverted evidence in an affidavit
submitted by TransCanada that its pipeline
would be operated as a common carrier
pipeline and that “‘[a]ny shipper wishing to
transport crude petroleum meeting the
specifications set forth in the [applicable]
tariff . . . will have access to ship its crude
petroleum on the pipeline for a fee[.]”138
Relying on Texas Rice Land
Partners, Ltd. v. Denbury Green Pipeline—
Texas, LLC,133 TRL argued that the trial
court was required to fully resolve
TransCanada’s common carrier status
before TransCanada could take possession
of TRL’s private property in conjunction with
its suit for condemnation.134 In Denbury
Green, the Texas Supreme Court explained
that once a landowner challenges an
entity’s prima facie evidence of common
carrier status pursuant to a permit granted
by the Texas Railroad Commission, “‘the
burden falls upon the pipeline company to
establish its common-carrier bona fides if it
wishes to exercise the power of eminent
domain. . . . Merely holding oneself out [as a
common-carrier] is insufficient under Texas
law to thwart judicial review.’”135
The significance of this case is the
court’s holding that the trial court erred by
failing to make a preliminary finding of
TransCanada’s common carrier status
before issuing a writ of possession.
However, the court considered that
the Texas Supreme Court, in Denbury
Green, expressly limited its opinion to
determining common carrier status under
Section 111.002(6) of the Texas Resource
Code. The Texas Supreme Court did not
address Section 21.021 of the Texas
Property Code, the statute at issue in this
case, which “allows a party with eminent
domain authority to take possession of the
condemned property, ‘pending the results of
further litigation’ if that party pays the
property owner the amount of damages and
costs
awarded
by
the
special
132
133
Crawford Family Farm Partnership v.
TransCanada Keystone Pipeline, L.P.139
held that a nongovernmental entity had the
power to exercise the power of eminent
domain to compel the grant of a pipeline
right-of-way over a landowner’s property
because the entity established itself as a
common carrier pursuant to the Texas
Natural Resources Code. TransCanada
Keystone Pipeline, L.P. (“TransCanada”)
contemplates the installation and operation
of a network of over 2,100 miles of pipeline
136
Id. (quoting Tex. Prop. Code Ann. § 21.021).
Id. at 336–38.
137
Id. at 339–40.
363 S.W.3d 192 (Tex. 2012).
138
In re Texas Rice Land Partners, 402 S.W.3d
at 338.
Id. at 340 (quoting Affidavit of Louis
Fenyvesi, Director of Markets and Supply for
TransCanada).
135
139
134
Id. at 339 (quoting
363 S.W.3d at 202, 204).
Denbury
409 S.W.3d 908 (Tex. App.—Texarkana
2013, pet. filed).
Green,
74
for the transmission of crude petroleum
which originates in Canada, traversing
markets within the Midwest United States to
Cushing, Oklahoma, and then through
Texas to its ultimate destination in the Port
Arthur, Texas area. TransCanada, through
condemnation, acquired an easement for a
buried pipeline across the property of
Crawford
Family
Farm
Partnerships
(“Crawford”) in Lamar County. Crawford
appealed arguing that TransCanada did not
have the power to exercise eminent domain
because it was not a “common carrier”
under the Texas Natural Resources Code
(the “Code”).
compliance argument, Crawford further
contended “that because TransCanada is
an interstate pipeline, it cannot subject itself
to all of the provisions of Chapter 111.”144
Crawford’s premise was based primarily
upon the fact that an interstate crude oil
pipeline is not subject to the rate-setting
powers of the Texas Railroad Commission,
but is subject to that jurisdictional power of
the Federal Energy Regulatory Commission
(“FERC”).145 Because TransCanada could
not subject itself to all the provisions of
Chapter 111 of the Code, Crawford argued
that TransCanada could not meet the
definition of common carrier.146
In Texas, “[c]ommon carriers have
the right and power of eminent domain.”140
In the exercise of that power, “a common
carrier may enter on and condemn the land,
rights-of-way, easements, and property of
any person or corporation necessary for the
construction, maintenance, or operation of
the common carrier pipeline.”141
The court disagreed with Crawford’s
analysis and explained that “the language
preceding the definition of ‘common carrier’
does not specifically state that such
common carrier is subject to all of the
provisions of the chapter.”147 Crawford
misinterpreted the opening phrase as being
prescriptive, rather than descriptive.148 The
court stated “the language ‘subject to the
provisions of this chapter’ is merely
descriptive of the type of common carrier to
which reference is made.”149
A person is a common carrier
subject to the provisions of this chapter if it:
“(1) owns, operates, or manages a pipeline
or any part of a pipeline in the State of
Texas for the transportation of crude
petroleum to or for the public for hire, or
engages in the business of transporting
crude petroleum by pipeline. . . .”142
Crawford also contended that
interstate pipelines were not included as
“common carriers.” However, the definition
of common carrier makes no distinction
between
intrastate
and
interstate
pipelines.150 The court reasoned that, “had
the Legislature intended to exclude
interstate petroleum pipelines from the
definition of common carrier, it could have
Crawford argued that the language
preceding subsection (1) above limits
common carrier status to entities subject to
all of the provisions of Chapter 111 of the
Code.143 Based upon Crawford’s strict
144
Id. at 915.
145
Id. at 916.
146
Id.
Id. (citing Tex. Nat. Res. Code Ann.
§ 111.019(b) (West 2011)).
147
Id.
142
148
Id. at 917.
149
Id.
150
Id. at 918.
140
Id. at 913 (citing Tex. Nat. Res. Code Ann. §
111.019(a) (West 2011)).
141
Id. at 914 (citing Tex. Nat. Res. Code Ann. §
111.002(1) (West 2011)).
143
Id.
75
easily done so with an express limitation.”151
“Chapter 111 . . . places no express
limitation on the grant of eminent domain
power to persons transporting crude
petroleum by interstate pipeline.”152 “[T]he
Legislature’s silence with respect to terms
used elsewhere in a statute is indicative of
its intent.”153 “[E]very word excluded from a
statute must also be presumed to have
been excluded for a purpose[,]” and “[t]he
Legislature has drawn intrastate/interstate
distinctions in other sections of” the Code.154
“We do not infer from the statute’s language
. . . that the Legislature intended its
purposes to be anything other than what
was expressly stated.”155
[A]reasonable probability must exist
that the pipeline will at some point after
construction serve the public by transporting
gas for one or more customers who will
either retain ownership of their gas or sell it
to parties other than the carrier.158
In addition to arguments relating to
TransCanada’s failure to qualify as a Texas
common carrier with eminent domain
authority, Crawford also claimed that
TransCanada’s contemplated pipeline was
not for public use.156 To establish that the
pipeline is for a public use, the pipeline
company seeking to exercise the power of
eminent domain “must do more than
transport its own product to one of its other
facilities or to those facilities of its affiliates,
. . . [it] must demonstrate a reasonable
probability that third-party customers will
use the pipeline.”157 To qualify as a common
carrier under Chapter 111.002(6) of the
Code:
The requirement of evidence as to
the public purpose probably added little to
Denbury, but the construction of the Code to
include interstate pipelines as common
carriers under the Code, and to specifically
grant the power of eminent domain to
interstate pipelines, was significant.
151
Id.
152
Id.
153
Id. at 919.
TransCanada produced undisputed
evidence that it would transport crude
petroleum owned by third-party shippers
unaffiliated with TransCanada or its parent
companies or affiliates.159 Thus, because
TransCanada complied with the reasonable
probability test, it established itself as a
common carrier with eminent domain
authority.
Walton v. City of Midland160 held that
granting a permit to drill an oil and gas well
did not constitute a regulatory taking by the
city of the surface owner’s property. Walton,
an owner of a surface estate inside
Midland’s city limits, brought an inverse
condemnation claim against the city,
claiming that granting a permit to drill a well
to an operator constituted a regulatory
taking pursuant to the Texas Constitution.161
The permit required the operator to plant
and maintain trees near the well and to drill
a water well (to maintain the trees), no
closer than 500 feet from the oil and gas
154
Id. (quoting Cameron v. Terrell & Garrett,
Inc., 618 S.W.2d 535, 540 (Tex. 1981)).
155
Id. at 921.
156
Id. at 922.
158
Id. at 923 (quoting Denbury, 363 S.W.3d at
202).
159
Id. at 924.
160
409 S.W.3d 926 (Tex. App.—Eastland 2013,
pet. denied).
157
Id. (citing Tex. Rice Land Partners, Ltd.
v. Denbury
Green
Pipeline-Tex.,
LLC,
363 S.W.3d 192, 200, 202 (Tex. 2012)).
161
76
Id. at 928.
well.162 Walton’s evidence demonstrated
that his property had a value of at least
$3,000 per acre after the oil and gas well
was drilled.163 Walton asserted that
requiring the water well constituted an
invasion of his surface estate and
groundwater and that permitting the oil and
gas well deprived him of all economically
beneficial use of his property.164 The city
brought a plea to the jurisdiction, arguing
governmental immunity, the trial court
granted the plea and Walton appealed.165
Addressing permanent physical
invasions, the appeals court determined that
the water well did not constitute a physical
invasion
because
the
only
permit
requirement as to the water well was that
the well could not be located within 500 feet
of the oil and gas well. Thus, the water well
could have been drilled on someone else’s
property.169 Granting the permit to allow the
operator to drill an oil and gas well also did
not constitute a physical invasion because
“a permit to drill an oil and gas well is ‘purely
a negative pronouncement’ that ‘grants no
affirmative rights to the permittee to occupy
the property.’”170 The court also cited FPL
Farming Ltd. v. Environmental Processing
Systems, L.C.171 for the general rule that a
permit granted by an agency does not act to
immunize the permit holder from civil tort
liability from private parties for actions
arising out of the use of the permit. This
particular permit was not a physical invasion
by the city because it did not grant an
affirmative right to the operator to use the
property, did not shield the operator from
any liability to Walton, did not require
Walton to acquiesce in the operator’s
actions, and did not limit the compensation
Walton could seek from the operator.172
A court is deprived of subject matter
jurisdiction when a governmental entity is
immune from suit.166 The Texas Constitution
waives immunity from suit for condemnation
claims under the takings clause. The waiver
does not apply if a plaintiff cannot establish
a viable takings claim.167
In analyzing the present case to
determine whether a regulatory taking had
occurred, the court relied upon established
authority in considering the two instances in
which per se regulatory takings could occur:
(1) where the government required an
owner to suffer a permanent physical
invasion, and (2) where a regulation
completely deprived an owner of all
economically beneficial use of the
property.168
162
Id. at 929.
163
Id. at 932.
164
Id. at 928, 932.
165
Id. at 928–29.
166
Id. at 929.
167
Id. at 930.
Finally, the permit did not deprive
Walton of all economic benefit from the
property because the evidence showed that
after the well was drilled, the property had a
value of at least $3,000 an acre.173
Therefore, the court held that the permit did
not constitute a taking, governmental
immunity from suit had not been waived,
169
Id. at 931.
170
Id. (quoting Magnolia Petroleum Co. v. R.R.
Comm’n, 170 S.W.2d 189, 191 (Tex. 1943)).
168
Id. at 930 (citing Lucas v. South Carolina
Coastal Council, 505 U.S. 1003, 1019 (1992);
Loretto v. Teleprompter Manhattan CATV Corp.,
458 U.S. 419 (1982); Penn Central Transp. Co.
v. New York City, 438 U.S. 104 (1978); Edwards
Aquifer Authority v. Day, 369 S.W.3d 814, 837–
41 (Tex. 2012)).
77
171
351 S.W.3d 306, 310–12 (Tex. 2011).
172
Walton, 409 S.W.3d at 932.
173
Id.
and the plea to jurisdiction was properly
granted.174
The court expressed no opinion on
the oil and gas lessee’s potential liability to
Walton.175 This is particularly relevant
because it is not clear that the owner of the
mineral estate has the right to water
belonging to the owner of the surface estate
when the water is to be used to water trees.
The case continues the trend most
recently expressed in FPL Farming to
protect the state and its political
subdivisions from any liability for the
granting of permits, because the granting of
a permit simply removes a governmental
impediment
without
conferring
any
additional rights. As between the parties
and as to their respective property rights,
nothing is changed by the granting of the
permit.
174
Id. at 933.
175
Id. at 932 n.1.
78