The 1989 AAPL Model Form Operating Agreement: Why are you not using it?
By Andrew B. Derman and Isabel Amadeo
To facilitate the annual drilling of thousands of wells within the United States, the oil
industry has relied on form agreements. The American Association of Professional Landmen
(AAPL) has, since 1956, provided the industry with standardized Joint Operating Agreements
(JOA). The 1956 form was revisited in 1977, 1982 and again in 1989.
The 1989 AAPL 610 Model Form Operating Agreement is clearly superior to the prior
AAPL form operating agreements. Why then is it still not universally accepted and used? Is it
because the drafting committee that developed the new form was viewed by many as
exclusionary and not transparent? Is it because the drafting committee was thought to be
controlled by the “independents,” the “majors” or “outside law firms?” Is it because one or two
early drafts were circulated “before their time?” Is the 1982 AAPL 610 Model Form simply
The 1989 AAPL form is an improvement over its predecessor. We live in a dynamic age
where rules should be modified to fit the times. The 1982 AAPL 610 Form Operating Agreement
has served the industry well, but as the oil industry evolves so must the form. The 1989 AAPL
610 Form Operating Agreement was, in part, a reaction to the 1986 pricing collapse and, in part,
a general improvement in the form.
The 1989 form significantly influenced the Association of International Petroleum
Negotiators (AIPN) 1990 International Model Form Operating Agreement (as well as the
updated 1995 and 2002 AIPN International JOAs). The AIPN International JOA is now
customarily used worldwide, outside the United States and the United Kingdom where
standardized model operating agreements have been adopted. It is rather ironic that the 1989
form contains provisions that are today used worldwide, but the industry has not universally
adopted this provision for use in the onshore United States. Why?
The Debate: Investors vs. Operator
Certain authors suggest that the standard AAPL JOA form fails to provide adequate
protection for non-operators, while others contend that as experienced and sophisticated non-
operators there is no need for special protection.
John McArthur in “Coming of Age: Initiating the Oilfield into Performance Disclosure,”
50 S.M.U.L.Rev. 663,745-750 (1997) suggests that the JOA does not fully address and protect
investors or non-operators. AAPL was not motivated to protect investors over operators.
Ernest E. Smith in “Joint Operating Agreement Jurisprudence,” 33 Wasburn L.J. 834,
840 (1994) argues that the disparity in bargaining position between parties to a JOA is rarely
present. He claims that “[n]on-operators are never marginal farmers and ranchers and are rarely
lacking either in financial resources or in formal education.” Smith goes on saying that “the
parties to an operating agreement are either oil and gas companies or experienced investors.” The
author concludes that non-operators can include special provisions to protect themselves in the
Parties to a JOA are able to negotiate and establish their rights and duties and they can
tailor the JOA to accommodate their objectives. The AAPL form is a standardized form that does
not contain language that fits every situation nor that is always acceptable to all the parties to the
JOA. The AAPL form is destined to provide a basis from which negotiations may be
commenced. Standardized forms are widely used in the oil and gas industry in order to reduce
negotiation and drafting expenses, provide the parties with well-written, comprehensive
agreements and to allow for efficient interpretation of the agreement in the future.
Review of the Provisions of the 1989 AAPL 610 Model Form Agreement
For those who have not been using the 1989 AAPL 610 Model Form, consider re-
examining your reasons for using an “old” form. Within the text of this article, we offer a
sampling of the improvements contained in the 1989 AAPL 610 Model Form.
Definitions – Article I
Definitions are important. Several additional terms have been defined in the 1989 form.
The inclusion of definitions for the terms “sidetrack, rework, zone, plug back, completion or
complete, deepen, nonconsent well, initial well and AFE” should eliminate ambiguity and,
consequently, conflict. The word “affiliate” is used several times, and it also should be defined.
Affiliate can be defined as “a company, partnership or other legal entity which controls, or is
controlled by or which is controlled by an entity which controls a party to this agreement.
Control means the ownership directly or indirectly of more than 50 percent of the shares or
voting rights in a company, partnership or legal entity.” The term “related party” appears in the
last sentence of Article V.D.1. and it should be deleted to avoid confusion.
The definitions of the terms “completion” or “complete” are extremely broad. They are
defined as a “single operation intended to complete a well as a producer of oil and gas in one or
more zones, including, but not limited to, the setting of production casing, perforating, artificial
stimulation and production testing conducted in such operation.”1 The terms “completion” or
“complete” have traditionally not been clearly defined. Rather, the definition was one determined
in the eyes of the beholder. It has been argued that completion occurred when a well was
connected to a pipeline or was capable of pumping into a tank truck and all that was required was
the turning of a valve. It has also been argued (sometimes by the same party) that completion
occurred after a well had been tested or just perforated. Note that since the operating agreement
may be attached as an exhibit to a farmout agreement or an exploration agreement, the definition
of completion in the operating agreement may be used to help define this otherwise undefined
term in the farmout agreement or exploration agreement.
If drilling a horizontal well is contemplated, the definition of “deepen” should be
expanded. Consider including language such as, “deepen as used in conjunction with horizontal
drilling shall mean a simple operation whereby a well is drilled to a distance greater than the
proposed horizontal targeted total measured distance.” In addition, the terms “initial objective”
or “objective zone” as used in conjunction with horizontal drilling, shall also mean the proposed
horizontal targeted total measured distance.
Define other terms as may be desired. Ensure that the language used in the agreement is
consistent with the defined terms.
Exhibits – Article II
The JOA contemplates the attachment of several exhibits. Exhibit A identifies the
Contract Area; Exhibit B requires that the form of lease be included; Exhibit C establishes the
billing procedures; Exhibit D lists the types and amounts of insurance; Exhibit E requires that the
gas balancing agreements be attached; Exhibit F contemplates a statement of non-discrimination;
and Exhibit G requires that a tax partnership agreement be included. The last three exhibits may
or may not be included in the JOA depending upon the circumstances of each particular
transaction. Finally, Exhibit H is for other attachments, such as an attachment dealing with an
“Area of Mutual Interest Clause.”
Check the appropriate boxes to indicate those exhibits that are attached. Frequently,
Exhibit B, Form of Lease, will not be attached. To ensure the form is properly completed, pay
special attention to only check those exhibits that are included.
As a consequence of an addition incorporated in the 1989 form, Exhibit A now must
contain the phone numbers of the parties for notice purposes. This is an improvement. Consider
also including the parties‟ telecommunications information.
In addition, all “[b]urdens on production” must now be disclosed in Exhibit A. This is
also an improvement, although, because all existing burdens may not be known at the time of
preparation of Exhibit A, the parties may have to provide a mechanism for the assumption or
sharing of certain then unknown burdens.
While the drafters added a category H for other exhibits, the drafters did not elevate a
memorandum of operating agreement and financing statement to the status of a designated
exhibit. I believe this was a mistake. A properly drafted memorandum of operating agreement
and financing statement can secure and protect a creditor‟s interest. By including a memorandum
of operating agreement and financing statement as a designated exhibit, the drafters would have
encouraged its use.
Interests of Parties in Costs and Production – Article III.B
Production is owed as allocated in Exhibit A. The JOA does not pool revenues. Pursuant
to Article VI.G or Article VI.H each party is to take (or separately dispose of) its own share of
production. Royalties are likewise not pooled. Each party is responsible for paying its share of
the royalty and other burdens. The 1989 form clarifies that “shared” royalties include all burdens
on production up to the specified amount included in the blank, not merely lessor royalties. It
should be noted that the 1982 form spoke about the “payment of royalties” while the 1989 form
addresses “all burdens.” The 1989 form attempts to clarify what has confused many, by
explicitly providing that the parties should share burdens up to the amount provided for in the
blank and individually shoulder all excess burdens. That is, all burdens in excess of the amount
provided for in the blank. Interestingly, the drafters included an additional sentence which
mandates that each party shall pay all burdens on the leases contributed by such party if the
contract area is identical with the drilling unit for productive zone(s).2 This curious sentence
protects a party who agrees to insert an amount in the blank which exceeds its actual burdens.
Why is such a sentence necessary?
Subsequently Created Interests – Article III.C
The 1989 form revised this provision to include in the definition of Subsequently Created
Interest “a lease or interest that is burdened with an assignment of production given as security
for the payment of money.”3 In addition, the revised provision requires all existing burdens to be
shown on Exhibit A. If the burden is not included in Exhibit A, it will be deemed a Subsequently
Created Interest. It is now absolutely critical that the parties fully disclose existing burdens on
The second paragraph provides that if a burdened party fails to timely pay its share of
expenses and the burdened party has created a Subsequently Created Interest, the financial
obligations are enforceable against the Subsequently Created Interest. It is unclear whether this
provision binds a subsequently created interest acquired by a bona fide purchaser for value –
such a result is questionable at best. This provision is only effective to the extent a subsequent
owner is provided notice of the terms of the operating agreement. The filing of a memorandum
of operating agreement and financing statement would likely provide suitable notice.
Titles – Article IV.A
The 1989 form clarifies an often contentious point by providing that a title examination
of the drilling unit, as opposed to only the drillsite, shall be done if requested by “a majority in
interest of the drilling parties” or by the operator.4 This is an improvement, as the 1982 form
required that all the drilling parties consent to a drilling unit title opinion for the costs thereof to
be shared. The 1982 form provides that copies of the drilling title opinion are to be given to all
parties. In the 1989 form, copies of all drilling title opinions are to be given only to the drilling
parties, who paid for the opinions. The cost of title opinions are borne by the drilling parties. The
1989 Form eliminates the option to charge title costs against the operator‟s administrative
overhead. In addition, outside attorney‟s fees associated with hearings before government
agencies are now chargeable to the joint account
Loss or Failure of Title – Article IV.B
A curious provision was added which provides that the ownership of only a wellbore
lease will not, in and of itself, give a party an interest in the contract area. In some areas,
especially Oklahoma, wellbore assignments have become prevalent. Unless Exhibit A gives the
owner of only a wellbore interest an interest in the contract area, the owner of the wellbore is not
considered a party to the operating agreement for purposes of contractual pooling.
As drafted, this provision imposes certain losses upon the party contributing a lease. If a
lease is lost as a result of failure of title, and the party is unable within 90 days to secure a new
lease, Exhibit A shall be adjusted to reflect changes of ownership. The party whose title fails is
responsible for all development and operating costs which have been paid or incurred.
As a consequence of another new provision, any lease or interest lost as a result of the
operation of an express or implied covenant (other than the payment of money) or the running of
the primary term is expressly considered to be a joint loss.
The Fifth Circuit Court of Appeals held in Fuller v. Phillips Petroleum Co., 872 F.2d 655
(5 Cir. 1989) that the JOA contained no expressed or implied obligation to notify a non-
operator of an impending lease termination. The operator in this case notified the non-operator of
the lease termination after the lease had expired. The non-operator alleged that the operator had a
duty under the JOA to notify the non-operator of the lease termination date prior to such
termination. The court rejected the non-operator‟s arguments that the JOA provisions dealing
with plugging and abandonment and surrender require prior notice of a lease termination.
Finally, the drafters provided that any lease or interest acquired by a party to the
operating agreement within 90 days of its expiration, shall be offered at cost to the party who has
lost the lease or interest to enable that party to maintain its interest in the contract area.
Designation and Responsibilities of Operator – Article V.A
The operator “shall conduct and direct and have full control of all operations.” The
operator has control over how the operations are to be conducted, not necessarily which
operations should be conducted or terminated.
The operator‟s standard of care under the 1989 form has been expanded. Under the 1989
form, the operator shall conduct its activities “as a reasonable prudent operator, in a good
workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice,
and in compliance with applicable law and regulation.” The 1982 form only provided that the
operator “shall conduct all such operations in a good and workmanlike manner.”
The operator is exonerated from all losses sustained or liabilities incurred, except those
losses or liabilities which “may result from gross negligence or willful misconduct.” The
meaning of this phrase, which exculpates the operator, has been widely debated. In the
interesting case of Stine v. Marathon Oil Co.,5 the Fifth Circuit held that this phrase shields an
operator from actions against it from non-operators who allege that operator has violated specific
provisions of the operation agreement. The court states: “…in the present case, Marathon is not
liable for any action taken in connection with the completion, testing or turnover, or any well
drilled under the provisions of the JOA unless Stine can prove Marathon‟s actions were grossly
negligent or willful.” The court goes on to say, “It is clear to us that the protection of the
exculpatory clause extends not only to „acts unique to the operator,‟ as the district court
expressed it, but also to any acts done under the authority of the JOA as operator.”6
The court concluded that the exculpatory clause shielded the operator from liability for
any acts taken in its capacity as operator if authorized by the operating agreement, except for
gross negligence or willful misconduct.
Several authors have raised the question of whether the exculpatory or indemnity
provision contained in Article V.A, which only holds the operator liable for “gross negligence or
willful misconduct,” is sufficient to allow the operator to avoid the full consequence of his
negligence. Courts, in the name of public policy, have been growing reluctant to sanction
exculpatory or indemnity provisions, which insulate a party from his own negligence.
Frequently, it is required that such provision be bold and conspicuous, especially under Texas
law. Pursuant to the JOA, a negligent operator is liable for only its percentage interest, not the
percentage interest of the non-operators.
According to Smith in “Duties and Obligations Owed by an Operator to Non-Operators,
Investors and Other Interest Owners,” 32 Rocky Mt.Min.L.Inst. (1986), the appropriate standard
of care to be applied to the operator “…may range from simple compliance with contractual
obligations to observance of strict fiduciary duties, depending upon the language of the operating
agreement and the context of the dispute.” Brian R. Bjella in “Removing the Operator Under the
Joint Operating Agreement: Breaking Up is Hard to Do”, 45 Rocky Mt. Min.L.Inst. (1999)
suggests that when construing an AAPL JOA the “… reasonably prudent operator standard
should govern.” Bjella goes on to say that the 1989 form expands the standard of conduct upon
the operator, but an operator is only liable where gross negligence or willful misconduct can be
proven and these standards are notoriously difficult to prove.
No AAPL form, including the 1989 form, has addressed the issue of operator‟s liability
for consequential and punitive damages which could be sought by non-operators and third parties
where the loss sustained is caused by the operators gross negligence or willful misconduct. The
governing law would control the imposition of such damages.
Resignation or Removal of Operator – Article V.B
The operator may resign at any time after providing notice to the non-operators. The
operator shall be deemed to have resigned if it “terminates its legal existence, no longer owns an
interest hereunder in the contract area, or is no longer capable of serving the operator.” Should a
dispute occur, the last of these requirements may result in protracted litigation as this
requirement will, no doubt, be interpreted differently by the parties. The second requirement, “no
longer owns an interest in the contract area,” is frequently triggered. It is this requirement that
prohibits a party, who is the operator, from passing operatorship to a purchaser or an assignee.
Operatorship is personal to the party and cannot be assigned. In Abraxas Petroleum Corporation
v. Hornburg, 20 S.W.3d 741 (Tex. App. 2000) Abraxus bought an interest of the operator and
assumed the operator‟s functions, but was never elected operator. Abraxas argued it was the
operator by virtue of the assignment. At trial, the court determined that Abraxas had never been
formally selected as operator, pursuant to the provisions of the JOA. The Court of Appeals,
however, overruled and determined that the appellees waived the JOA‟s requirement that
Abraxas be formally selected as operator.
Due to the contentious nature of the removal issue, the drafters of the 1989 form only
incorporated relatively minor changes. In a prior draft, the revisions committee proposed two
options. One provided for removal only for good cause. The other required removal “without
cause by the affirmative vote of non-operators owning ___ percent interest.” A removal without
cause option might tend to keep overhead expenses down, give non-operators the ability to
replace ineffectual operators and provide an effective solution to removing an operator who has
financial problems - before such operator files for bankruptcy. Where the operator owns more
than 50 percent of the interest it is easy to understand why it should perpetuate its position as
operator. But where the operator owns less than 50 percent of the interest it is not easy to
understand why an operator should be granted an inalienable right to perpetuate its position as
The drafters of the 1989 form defined “good cause” to include not only gross negligence
or willful misconduct, but also the material breach of or inability to meet the standards of
operation contained in Article V.A or material failure or inability to perform its obligations under
this agreement.7 When viewed along with Article V.D2 which requires that the operator
“promptly pay the discharge expenses incurred in the development and operation of the contract
areas…”8 and the final sentence of the operating agreement in Article XV.D which provides that
“the failure of any party to this agreement to comply with all of its financial obligations provided
herein shall be a material default,”9 an operator who fails to timely pay his bills may be removed
prior to the filing of a bankruptcy petition and prior to the institution of the bankruptcy court‟s
jurisdiction. By so doing, the bankruptcy court should not have the requisite authority to stay or
reverse the operator‟s removal. For this provision to be effective, however, the non-operators
must act before the operator voluntarily or involuntarily comes within the jurisdiction of the
A resigning or removed operator shall give the non-operators 90 days to name a
successor operator, unless the successor operator has been selected and wishes to assume such
duties at an earlier date. The Louisiana Court of Appeals in Lancaster v. Petroleum Corp. of
Delaware, 491 So.2d 768 (La. Ct. App. 1986), concluded that the operator‟s resignation without
90 days advance written notice to the non-operators constituted a breach of the JOA.
Additionally, the court held that the operator had breached its duty under the JOA when it
threatened to resign, unless the parties to the JOA consented to plug and abandon a well that had
experienced a blowout or took over the well.
The 1989 form provides that a successor operator shall be selected by an affirmative vote
of two or more of the parties owning a majority interest. In Pennmark Resources Co. v.
Oklahoma Corporation Commission, 6 P.3d 1076 (Okl.Civ.App. 2000) the operator intended to
avoid removal by assigning a significant part of its working interest to a wholly owned
subsidiary who would vote against the operator removal. Pennmark asked the Oklahoma
Corporation Commission to enforce the JOA by examining the procedures followed in the
election of the operator. The commission concluded that Pennmark failed to sustain its burden of
proof for removal of the operator because “the evidence presented by Penmark did not establish
that the partent/subsidiary corporations were so closely linked and so inextricably intertwined as
to be effective one entity.” In the appeal from the Oklahoma Corporation Commission decision,
the Oklahoma Court of Civil Appeals, Division III, held that “there was overwhelming evidence”
that the subsidiary was an instrumentality of the operator and reversed and remanded the case.
In Tri-Star Pet v. Tipperary, 08-02-00107-CV (Tex.App.-EP [8th Dist.] 2003), Tri-Star
and Tipperary were parties to a JOA dated May 15, 1992 that designated Tri-Star as the operator
of the project and Tipperary as one of the non-operators. Tipperary filed a suit against Tri-Star
seeking money damages for a breach to the JOA by Tri-Star alleging that Tri-Star had failed to
operate in a good and workmanlike manner and that cause existed to remove Tri-Star as operator.
Later, in January 1999, a majority of non-operators affirmatively voted to remove Tri-Star as
operator and selected Tipperary as successor operator. In November 2000, the non-operating
working interest owners again affirmatively voted to remove Tri-Star as operator and to replace
Tri-Star with Tippery. Tri-Star refused to step down as operator and Tipperary filed an
application for a temporary injunction seeking removal of Tri-Star as operator. The trial court
granted a temporary injunction in favor of Tipperary finding that Tipperary was the current
lawful operator by vote of the majority interest under the terms of the JOA and that Tri-Star was
prohibited from interfering with Tipperary‟s assumption of control and operation of the project.
The Court of Appeals of Texas affirmed the trial court‟s decision.
The Supreme Court of Oklahoma was presented in Pitco Production Co. v. Chaparral
Energy, Inc., 2003 OK 5, 63 P.3d 541 (2003) with an issue on certiorari of whether the terms of a
1956 Form JOA that designates one party as operator of the unit area and whose language refers
to the “operator” in singular form, permits the election of more than one unit operator in an
Oklahoma Corporation Commission designated spacing and drilling unit. The Supreme Court of
Oklahoma answered in the negative holding that “… the JOA in contest clearly manifests the
parties‟ intention to allow but one operator who has full and complete control over operations on
the unit area.”
As discussed previously, the incorporation of a removal standard for reasons other than
the insolvency, bankruptcy or gross negligence of the operator is a substantial improvement.
Historically, it has been extremely difficult to remove an operator for violating the standard of
“gross negligence or willful misconduct.” The incorporation of the concept of removal for “good
cause” provides the non-operators with leverage to replace a defaulting operator.
The 1989 form also requires the former operator to deliver records and data to the
successor operator. Copying costs are to be charged to the joint account.
To protect non-operators from the insolvent or bankrupt operator, a new provision states
that if an “operator becomes insolvent, bankrupt or is placed in receivership, it shall be deemed
to have resigned without any action by non-operators, except the selection of a successor.”10
Where the removal of an operator is prevented by the bankruptcy court, an operating committee,
called an interim operating committee comprised of all parties, is to operate until the operating
agreement has been accepted or rejected.
If there is only one non-operator, a third party acceptable to non-operator, operator and
the bankruptcy court will be chosen to sit as the swing vote on the operating committee. It may
be extremely difficult and time consuming to select a third party acceptable to the operator and
the non-operator. To facilitate the replacement of the operator (in two-party agreement), a non-
operator will, of course, always have the ability to consent to the entity chosen by the operator.
This provision assumes that the bankruptcy court will enforce this provision. Bankruptcy
courts may view this provision as an incursion into their jurisdiction and declare the provision
Rights and Duties of Operator – Article V.D
The 1989 form explicitly requires the operator to timely pay all expenses and keep the
Contract Area free of liens. The operator shall hold non-operator‟s funds, although the operator
is not to be considered a fiduciary. In Oklahoma, however, the operator may be held to be a
trustee, which owes a fiduciary duty to the non-operators. (See Reserve Oil Inc. v Dixon, 711 F2d
951 (10th Cir. 1983).
The operator is not required to establish an escrow account nor a separate account unless
otherwise specifically agreed. One of the early JOA drafts circulated by the committee preparing
the 1989 form mandated that an escrow account be established for the drilling of every well. This
requirement, as might be expected, did not sit well with many operators – especially the majors
at the time. If nothing else, this suggestion galvanized opposition by some of the larger operators
and this opposition was able to influence the development of the 1989 form.
Non-operators are given greater access under the 1989 form to visit the operation
site, to review the operator‟s books and records and to request production related
information. In addition, the operator is now obligated to:
1. Advise the non-operators of the date the well is spud or commenced.
2. Provide progress reports and test results if requested.
3. “Adequately test all zones encountered which may reasonably be expected to be
capable of producing oil and gas in paying quantities as a result of examination of
the electrical logs or other logs or cores or test, conducted hereunder.”
4. Furnish to any consenting party estimates of current and cumulative cost incurred
for the joint account.11
Operators may object to providing the non-operators and especially non-consenting
parties with progress reports and test results. It has frequently been contended that non-
consenting parties should not get well information. And in specific instances, this provision
should be amended to deny or withhold certain technical information from the non-consenting
parties. This is different from financial information which should be disseminated to both
consenting and non-consenting parties. Non-consenting parties need such financial information
to monitor the recoupment account.
These revisions offer non-operators greater ability to monitor operational and financial
aspects of the project. Beyond these protections, the 1989 form requires operators to test all
zones that may reasonably be expected to be capable of production. This obligation or
requirement applies to both the initial well and all subsequent wells. The 1982 form does not
clearly address this issue with regard to the initial well and does not at all address this issue with
regard to subsequent operations. This ambiguity has precipitated differences and conflicts.
Initial Well – Article VI.A
A new sentence has been added which clearly states that the drilling of the initial well is
obligatory. The 1989 form unfortunately does not address the drilling of horizontal wells. If the
initial well proposed is a horizontal well, one of the following provisions should be incorporated:
1. [A] total vertical depth of ______ feet, and a horizontal targeted total measured
distance of feet; [or]
2. [A] total vertical depth of ______ feet or to a depth sufficient to test the _______
formation, whichever is the lesser depth; and a horizontal targeted total measured
distance which operator deems advisable.
Subsequent Operations – Article VI.B
The new language clarifies the requisite processes and procedures under the subsequent
operations provision. In this regard, an additional sentence has been added which states that
those “parties that did not participate in the drilling of a well for which a proposal to deepen or
sidetrack is made hereunder shall, if such parties desire to participate in the proposed deepening
or sidetracking operation, reimburse the drilling parties…” for their drilling expenses.12 This
addition clarifies the unresolved question of whether a non-consenting party can participate in
the deepening or sidetracking operation if it did not participate in the drilling of the well. The
1982 form does not address this question, and numerous controversies have followed.
Companies may not like the result of this provision, but at least the issue has been
addressed. If the parties to the operating agreement agree, the provision can, of course, be
revised to provide for either the payment of a penalty or the denial of the ability to participate in
a deepening or sidetracking, under certain specified circumstances.
Although the early drafts of the 1989 form generally decreased the time periods for
responding to proposals by replacing the term “exclusive of Saturday, Sunday and legal
holidays” with “inclusive of Saturday, Sunday and legal holidays,” the 1989 form continues to
use the word “exclusive.” Consideration might be made to replace “exclusive” with “inclusive.”
Such a revision would reduce stand-by time and allow for more efficient (less expensive)
Before specific language was included in the JOA addressing sidetracking, it was unclear
if sidetracking was or was not a subsequent operation requiring a party‟s consent to be liable for
such associated cost. In Holt Oil & Gas Corp. v. Harvey, 801 F.2d 773 (5th Cir. 1986), reh. den.
(1986) the court ruled that a JOA did not clearly provide that sidetracking was a subsequent
operation. And, therefore, even though the non-operator elected not to participate, he was still
liable for its share of costs. This problem should not arise under the 1989 form as sidetracking is
explicitly referred to in Article VI.B.1 as a subsequent operation.
A party proposing to conduct a subsequent operation under a JOA must provide proper
written notice to the other parties. In Acadienergy, Inc. v. McCord Exploration Company, 596
So. 2d 1334 (La.Ct.App. 1992) the Lousiana Court of Appeals held that the non-operator had not
received written notice of the requisite five facts as to the proposed subsequent well, before it
was drilled, in order to make a determination of whether to participate in the well. The court
explained that under Article VI.B.1 of the 1977 AAPL Form, the parties must be given written
notice of the following five facts: (1) the work to be performed; (2) the location of the proposed
well; (3) the proposed depth of the proposed well; (4) the objective formation and (5) the
estimate cost of the operation.
The 1989 form does not address the non-consenting parties‟ liability for a well that
causes environmental damage where the well fails to produce enough to allow the consenting
parties to recoup their expenses plus the associated penalties. Is a non-consenting party
responsible, under the operating agreement, for its share of environmental damages when
recoupment of expenses plus the associated penalties has not occurred? Under the Texas
Railroad Commission rules, a non-consenting party may well be responsible for plugging and
abandoning a well, even if the well has yet to reach recoupment of expenses plus associated
penalties.13 That is, even if the non-consenting party‟s interest has been “temporarily”
relinquished to the consenting parties, the party who “temporarily” relinquished their interest are
still liable. The Texas Railroad Commission contends that because the non-consenting party has
an economic interest in the well it remains liable.
However, it does not seem equitable to impose environmental obligations and liabilities
on a party who elects not to participate in the drilling of a well. Appropriate language could be
inserted to provide that only those parties currently owning an interest in the well or sharing in
production should be liable for any environmental damage. Under certain circumstances,
indemnities will also be necessary.
Operations by Less than All Parties – Article VI.B.2 (b)
The new provision clarifies that “non-consenting parties who participated in the drilling
of the well to the point of attempted completion, deepening or plugging back shall remain liable
for and shall pay their proportionate shares of the well and restoring the surface location insofar
only as those costs were not increased by the subsequent operations of the consenting parties.”14
The 1982 form does not specifically address the allocation of plugging costs in such
situations. While the approach taken in the 1989 form may precipitate disputes over the
individual party‟s proper financial contribution, it is the most equitable and an improvement.
Another new provision provides that if the well is not drilled to its objective depth due to
reasons other than encountering mechanical problems or impenetrable substances, those non-
consenting parties, who voted for an alternative proposal to drill to a shallower depth, shall be
entitled to participate in the completion effort by paying its share of the drilling cost to the actual
depth drilled. Once again, the drafters have clarified a previously unresolved matter.
Reworking or Plugging Back – Article VI.B.2 (c)
The 1982 form provided for a 100 percent penalty for any reworking or plugging back
operation conducted during the recoupment period of a non-consent operation. The 1989 form
replaces the 100 percent penalty with a blank. Rarely did parties revise the 1982 form to increase
or decrease the penalty. However, with the incorporation of a blank, parties will likely seek a
higher penalty as compensation for the risk involved in such operation and the time value of
In Texstar North Am., Inc. v. Ladd Petroleum Coporation, 809 S.W.2d 672 (Tex.App.
1991), the Texas Court of Appeals considered whether the 1982 AAPL Form contained an
implied duty of good faith and fair dealing. Under Article VI.B.I “Proposed Operations” and
Article VII.D.2 “Rework or Plug Back” of the operating agreement, the operator could not
conduct a fracture simulation on the subject well without the consent to all parties to the
agreement. The non-operator refused to consent to such operations. The operator brought an
action against the non-operator for breach of an alleged implied duty of good faith and fair
dealing under the JOA. The court determined that under Articles VI.B.I and VII.D.2. the operator
must obtain approval of all of the non-operators prior to conducting such fracture operations. The
court held that Articles V.I.B.1 and VII.D.2. of the 1982 form expressly and unambiguously
provide the terms under which a party may withhold consent to a rework procedure and that the
operator‟s reliance upon an implied duty of good faith and fair dealing was without merit.
Deepening – Article VI.B.4
A detailed provision on deepening has been added. In summary, non-consenting parties
can participate in the deepening of a well. If the proposal to deepen is made prior to the
completion of a commercial well, the non-consenting party wishing to participate in the
deepening shall reimburse the drilling parties for its proportionate share of expenses.
The non-consenting party is not obligated for the costs of testing and completion prior to
the deepening operation. If, however, the well has been previously completed as a commercial
well, but is no longer producing in paying quantities, the nonconsenting party wishing to
participate in the deepening shall reimburse the drilling parties for its proportionate share of
expenses, less those costs recouped by the consenting parties from the sale of production from
the well. The non-consenting parties shall pay its proportionate share of the costs of salvable
equipment in the hole and on the surface.
Sidetracking – Article VI.B.5
A sidetracking provision similar to that of the deepening provision has been incorporated.
Order of Preference of Operations – Article VI.B.6
Under the 1982 form, proposals are considered on a first-come-first-served basis. The
1989 form provides for a procedure to choose between conflicting proposals. Alternative
proposals can be offered if disseminated within 15 days 24 hours if a drilling rig is on location,
of the initial proposal. Five days after the running of the proposal period, or 24 hours if a drilling
rig is on location, each party must vote on the competing proposals. The majority interest
prevails. In the event of a tie, the initial proposal prevails.
This provision is a significant improvement over the 1982 form. Under the 1982 form, a
poorly thought out or manipulative proposal if proposed first could force the other parties to elect
not to participate or to participate in an unreasonably risky and/or needlessly expensive
Paying Wells – Article VI.B.8
This new provision brings certainty to the issue of what can be done to a commercial well
by stating that “[n]o party shall conduct any reworking, deepening, plugging back, completion or
sidetracking operation under this agreement with respect to any well then capable of producing
in paying quantities except with the consent of all parties that have not relinquished interests in
the well at the time of such operation.”15
Completion of Wells; Reworking and Plugging Back – Article VI.C
The casing point election (option no. 2) has been expanded to require the dissemination
of completion cost AFE (Authority for Expenditure). The AFE must list the estimated costs of an
operation. In addition, a procedure similar to that which is used for subsequent operations has
been incorporated to handle conflicting completion proposals. Finally, it is now possible to elect
to not participate in one completion attempt and should that completion attempt fail, participate
in another completion attempt.
Once again, certain parties may not like the results of the new language, but at least the
new form resolves an ambiguity in the prior JOA forms. If the parties wish, they can revise this
provision to eliminate a party‟s ability to elect not to participate in one completion, and if the
completion should fail, to participate in subsequent completion attempts.
AFEs are disseminated to satisfy Article VI.B.1, which mandates that notice be given of
any proposed operation, specifying work to be performed, location, proposed depth, objective
formations and estimated cost of the operation. AFEs are generally considered estimates of the
costs anticipated and not firm commitments. In M&T, Inc. v. Fuel Resources Development Co.,
518 F.Supp.285 (D.Colo.1981), a non-operator declared his intention to non-consent a well that
had exceeded the AFE, but had not reached objective depth. The court held that (1) the JOA did
not permit a party to non-consent a well during the drilling phase and (2) the AFE was only an
estimate of the costs and not a limitation on the operator‟s authority.
As explained by Professor Smith (“Duties and Obligations Owed by an Operator to Non-
Operators, Investors and Other Interest Owners”, 32 Rocky Mt.Min.L.Inst. (1986)) the AFE may
restrict the types of agreements the operator may enter into. In Haas v. Gulf Coast Natural Gas
Co., 484 S.W.2d 127 (Tex. Civ. App. 1972) the non-operators resisted the payment of their share
of drilling costs because they did not follow the footage basis established in the AFE.
Other Operations – Article VI.D
The 1989 form improves the efficiency of production operations. In the 1982 Form, project
expenses in excess of what is provided by the parties in the operating agreement (by inserting a
number in the blank) have to be approved by all consenting parties. Compliance with the
provision is often lax by the operator. Under the 1989 Form, repair work, the installation of
artificial lift equipment or ancillary production facilities and certain other work can be
undertaken with the “written consent of any party or parties owning at least ___ percent percent
of the interest of the parties entitled to participate in such operation…”16 The inclusion of such
extension of the concept is an improvement.
Abandonment of Wells – Article VI.E
The drafters have improved the 1982 form by requiring that a party who elects to take
over a well must provide satisfactory proof of its financial capability. In light of the possibility of
environmental liability, parties need to be increasingly vigilant to ensure that successor operators
have the financial wherewithal to make good on their indemnities. To this end, the 1989 form
requires that a successor operator provide “proof reasonably satisfactory to operator of its
financial capacity to conduct such operations or to takeover the well17 and indemnify the
abandoning parties, before taking over the well. It would be advisable to amend the provision to
require not just an “indemnity,” but also an “indemnity to the reasonable satisfaction of
operator.” This satisfactory indemnity requirement shall be imposed on both dry holes and wells
that have produced.
A sentence has been added which makes it clear that if the costs of plugging and
abandoning and surface restoration exceed the salvage value, the abandoning parties will have to
pay the party taking over the well for its proportionate share of the difference.
Termination of Operations – Article VI.F
Previously, operations could only be terminated prematurely if impenetrable substances
were encountered or if conditions in the hole were encountered which made further operations
impractical in the initial well. In Lerblance v. Continental Oil Company, 433 F. Supp. 233 (E.D.
Okla. 1976) the court determined that the operator had encountered a “practically impenetrable
substance” and under the circumstances the operator was relieved of its obligation to continue
further operations in the test well. No mention was made of any subsequent operations. This
concept was expanded to cover subsequent operations in the 1989 form. The word “impractical”
is not defined in the prior JOA forms, and its definition is open to interpretation. Arkla
Exploration Co. v. Boren, 411 F.2d 879 (8th Cir. 1969) supports the proposition that the operator
can prematurely terminate drilling subsequent wells when the costs become prohibitive.
As a consequence of an addition to the 1989 form, an operation can be ended prematurely
if a to-be-determined percentage of the parties wish to terminate such operations. This provision
will foreclose one participating party, who may only be a small minority interest owner, from
requiring the other participating parties to pursue an operation that was previously approved, but
due to unanticipated events, has become extremely expensive, although it may not be
“impractical.” The percentage to be inserted in the blank will be subject to negotiations and will
depend on the number of parties and their proportionate ownership interest. Alternatively, the
operator may terminate operations where the well encounters “granite or other practically
impenetrable substance or condition in the hole…which renders further operations impractical”
Cost Overrun, Not Included in 1989 Form
The prior drafts of the 1989 form included innovative cost overrun provisions. While the
previously proposed provisions could have certainly been simplified, users of the 1989 form do
not have benefit of such innovative thinking. In summary, two options were proposed. Pursuant
to option no. 1, the parties agreed to proportionally pay cost overruns. Under option no. 2, if the
cost overruns exceeded a to be specified percentage, a party could elect not to participate in all
future operations, subject to the payment of the non-consent penalty on such additional
Taking Production in Kind – Article VI.G
Each JOA participant owns a share of production in accordance with its proportionate
interest in the Contract Area and “shall take in kind or separately dispose of its proportionate
share.” JOAs typically contain a provision authorizing the operator to purchase the non-
operator‟s share or to sell such share for the account of the non-operator “at the best price
obtainable in the area.”
Several changes have been incorporated which improve the language from that of
the 1982 form. For example: (1) any purchase or sale of production by the operator may be
terminated by giving at least 10 days notice to the owner of production; (2) an owner of
production must give the operator at least 10 days notice before it can take production in kind,
although this 10 day period can be extended for a period not exceed 90 days; (3) the operator is
not under any duty to share its market or to obtain a specific price; and (4) the sale by the
operator of a non-operator‟s production does not give the non-operator any right in the operator‟s
For antitrust and tax reasons, the operator, even if it has the permission of the non-
operator, is only able to buy or sell the non-operator‟s oil for a limited period of time. An
agreement which is for a duration in excess of one year could arguably run afoul of the
antitrust laws or could be used by the Internal Revenue Service to support its contention
that the parties had a joint profit motive, which could result in adverse tax consequences.
The 1989 form includes a requirement that all parties advise the operator in writing of
their gas marketing arrangements for the following month, excluding price, and notify the
operator of any change in such arrangements. The operator shall maintain records of all
marketing arrangements including all volumes sold, or transported by each party, and such
records shall be given to the non-operators upon request.
Split stream gas deliveries shall be handled pursuant to the terms of the relevant gas
balancing agreement. This new provision was made necessary as a consequence of the new
marketing arrangements. Operators are frequently responsible for accounting for gas sales, but
they are often not contemporaneously supplied with the requisite information. Operators are
often furnished information from the pipelines; hence, this information is frequently months old.
With the introduction of this language, operators will be contemporaneously given such requisite
information by each of the non-operators.
Use of Alternative 2
The use of alternative 2 continues to be deceptive. It gives some parties a false sense of
comfort that a gas balancing agreement is not necessary. Alternative 2 only gives the operator the
right to buy the non-operator‟s oil and gas (alternative 1 only gives the operator the right to buy a
non-operator‟s oil). The use of alternative 2 is not a substitute for a gas balancing agreement.
Consideration should be given to deleting the last sentence of the first paragraph. This
sentence states that “[a]ny party taking its share of production in kind shall be required to pay for
only its proportionate share of such part of operator‟s surface facilities which it uses.” Although
this provision has some equitable appeal, it is administratively difficult to ascertain who is using
what part of the surface facilities, where one or more parties is taking its production in kind. This
presents special problems where a party intermittently takes its production in kind or where a
party only takes part of its production in kind. Surface facilities are available to be used by all the
parties and it is expedient to allocate the cost of surface facilities in proportion to a party‟s
interest. As currently worded, a party is only required to pay for the proportionate part of the
surface facilities that it uses. Although parties are only required to pay for the surface facilities
they use, operators frequently charge the parties for surface equipment in proportion to the
party‟s interest in the operating agreement, regardless of a party‟s actual use.
Liability of Parties – Article VII.A
The liability of the parties for costs of operations is several, not joint, and this provision
explicitly disclaims any intent to create a partnership. The 1989 form now clearly states that “no
party shall have any liability to third parties hereunder to satisfy the default of any other party in
the payment of any expense or obligation hereunder” and “the parties shall not be considered
fiduciaries.” So broad is the renunciation of responsibility that the provision reminds the parties
that the right to pursue their respective self-interest is limited by a duty to deal in good faith with
each other. Although these additions will not stop third-party lawsuits that attempt to hold the
non-operator liable for the operator‟s debts, they should act to deter such lawsuits.
This provision explicitly disclaims any intent to create a partnership. A mining
partnership is created where co-owners unite to operate the property and share any profits
earned. Such a mining partnership may be imposed by law even if the parties explicitly agree in
writing not to create a mining partnership. Courts have found that a mining partnership exists
where each party to an operating agreement has the requisite “mutual control” or “active
participation” in operations. Dresser Industries, Inc. v. Crystal Exploration and Production Co.,
No. 83-1275 (D. Okla. Jan. 17, 1984), aff’d., No. 84-1160 (10th Cir. July 12, 1985).
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 profits and losses. This mining partnership test has been adopted in the jurisdictions which
have addressed this issue. See Fiske, Mining Partnership, 26 Inst. on Oil & Gas L. & Tax‟n 187,
193 (1975). If a mining partnership exists, the partners are characterized as operators and have a
limited power to bind other members of the partnership. Co-ownership alone does not give rise
to a mining partnership.
In Blocker Exploration Co. v. Frontier Exploration, Inc., 740 P.2d 983 (Colo.1987) the
Colorado Supreme Court held that a non-operator was not liable for the debts of the operator
where the non-operator only had the right to receive certain data, to have access to the site and to
be consulted. In Berchelmann v. Western Co., 363 S.W.2d 875 (Tex.Civ.App. 1962), the
appellants were held not liable as partners because “the very operating agreements themselves,
wherein appellants were designated as the „non-operators‟ and Texita as the „operator‟ do not
contain the basic elements of sharing of liability, control, risk and profits, along with the
elements of agency, necessary to constitute a partnership or mining partnership.” 19
Professor Ernest E. Smith in an interesting article (“Duties and Obligations Owed by an
Operator to Non-Operators, Investors and Other Interest Owners”, 32 Rocky Mt.Min.L.Inst.
(1986), explains the arguments for imposing a fiduciary obligation on the operator and
enumerates four lines of analysis used by the courts to justify the standard of conduct upon the
operator: (i) the operator as agent; (ii) the operator as trustee; (iii) the operator as co-tenant and
(iv) the joint venture analysis. Professor Smith concludes that “[t]o the extent that the operating
agreement contains specific provisions setting out the operator‟s rights and duties, such
provisions will normally prevail over any obligations which would be imposed by the general
law of fiduciaries.” This observation makes good sense, the parties have the opportunity to
define their relationship and such definition should be respected.
For an excellent discussion of the issue of whether the notion of “fiduciary duties” exist
under the terms of the operating agreement, see Randal C. Stongy, Recent Jurisprudence
Regarding Operating Agreements, the Landman, November/December 1992.
Liens and Security Interests – Article VII.B
This provision has been expanded to increase the scope of the lien and security interest.
The lien now covers real property as well as present and future acquired personal property and
fixtures. The provision now expansively lists the property rights covered by the lien and security
interest. Pursuant to this provision, each non-operator grants to the operator a lien on its oil and
gas rights and a security interest on its share of production. Moreover, each party now represents
that the lien and security interest granted shall be a first and prior lien and that the party will
maintain the priority of such lien and security interest. Although Article VII.B grants a lien and a
security interest, this provision may not provide the necessary security unless it is perfected by
There is some authority, under Texas law, that the statutory lien (Tex. Code Ann. Prop.
Code, 56.001-56.003 (Vernon 1984)) extends to the operator, because the operator is the person
with whom the contract with the mechanic or materialman is made. An argument could be made
that the statutory lien protects and secures the operator when it is acting as an independent
contractor for the benefit of the non-operators. The statutory lien provisions of Wyoming,
Montana, New Mexico and Colorado are similar to what exists in Texas. In Amarex, Inc. v. El
Paso Natural Gas Co., 772 P.2d 905 (1987), the Oklahoma Supreme Court held that although
the filing of the JOA is the preferred method of perfection of an oil and gas lien,a Memorandum
of Operating Agreement and Financing Statement would suffice. Moreover, the court ruled that
the Oklahoma statutory oil and gas lien is available to the operator, and is enforceable against the
owner of the leasehold interest, if the operator follows the requirements of the statute and that the
operator‟s managerial functions qualify as labor within the statute.
It is clear that the intent under the 1989 form is to give effect to the ruling of the
Oklahoma Supreme Court in Amarex to ensure that each party is adequately protected. This form
provides that each party agrees that all other parties shall be entitled to utilize the state‟s oil and
gas lien law and related statutes and that the operator may utilize the mechanic‟s or material-
man‟s lien law.
To ensure the execution of a memorandum of operating agreement and financing
statement, each party agrees to execute and acknowledge the necessary lien and financing
statement documents. What happens if one or more parties fail to execute the memorandum of
operating agreement and financing statement, as required by this provision? In Mbank Abilene,
N.A. v. Westwood Energy, Inc., 723 S.W.2d 246 (Tex.Ct.App. 1986) the court held that the bank
was deemed to have notice of an un-recorded JOA which was referred to in a document in the
chain of title that was of record.
To avoid having to seek judicial involvement to force a party to sign the memorandum of
operating and financing statement, the lien and financing statement should be executed
contemporaneously with the JOA and filed of record soon thereafter. Moreover, the non-
defaulting parties can, by taking production, offset any amounts owed by a defaulting party. This
explicit offset right is important from a bankruptcy perspective. Many states have statutes that
limit the use of offsets. The 1989 form also includes an expedited foreclosure provision.
Defaults and Remedies – Article VII.D
Under the 1989 form, a defaulting party automatically has certain rights suspended. An
operator who is in default can be replaced by a vote of the non-operators owning a majority
interest. A defaulting party is denied the following rights, among others: to receive operational
information; to elect to participate in an operation, whether or not the defaulting party has
previously elected to participate and to receive proceeds from the sale of production. Non-
defaulting parties can sue (at joint account expense) to recover money owed, interest,
consequential damages, attorneys‟ fees and costs.
Surrender of Leases – Article VIII.A
If a participant wishes to surrender a lease, which he has contributed to the Contract
Area, he must obtain the consent of all the parties to the JOA. Note that the surrender of a lease
or an oil and gas interest does not reduce the surrendering party‟s interest in the Contract Area.
As written, the 1989 form provides that a party‟s failure to reply within the designated
time is deemed to be its consent to receive all or a portion of the surrendered interest. Due to
environmental concerns, the failure to respond might be better deemed a rejection or denial of
the surrender offer. Due to an administrative oversight, a party who fails to respond may
unknowingly inherit a future superfund site.
Renewal or Extension of Leases – Article VIII.B
The 1989 form now addresses renewals, replacements and extensions of leases.
This clarifies an ambiguity in the 1982 form is and another improvement. The third paragraph of
this provision states in its entirety “[i]f the interests of the parties in the Contract Area vary
according to depth, then their right to participate proportionately in renewal or replacement
leases and their right to receive and assignment of interest shall also reflect such depth
variances.”20 How will the individual allocations be valued in situations where the interests of the
parties vary according to depth? Moreover, if there is no individual allocation, would a party
who contributed two leases, which have depth limitations of 10,000 feet and 12,000 feet, average
the two leases and pay its proportionate share for an 11,000 foot assignment?
Assignment; Maintenance of Uniform Interest – Article VIII.D
The new assignment of provision makes clear that the transfer of ownership, with regard
to the parties to the JOA, is not recognized until 30 days after satisfactory notice has been
received. In addition, the transferor is liable for all costs incurred prior to making such
assignment. In light of environmental concerns and the fact that the preferential right to transfer
is often deleted, it would be advisable to restrict transfers to financially responsible parties or
those who can provide good security and require appropriate indemnities.
The drafters chose not to amend the uniform maintenance of interest provision. This
provision is frequently ignored. With the advent of computers, the administration of varying
interests is now easy. Consideration should be given to deleting this provision.
Preferential Right to Purchase – Article VIII.F
The preferential right to purchase clause is now an optional provision. The assumption is
that if the box is not checked, the preferential right to purchase provision is not applicable and
the parties do not need to physically strike through the language in the form agreement.
The drafters have refused to address the age-old question of whether the word “sell”
includes “farmout.” Prior drafts of the 1989 form stated that should “any party desire to sell or
farmout or make other similar disposition” it should give notice to the other parties. For the sake
of clarity, this portion of the 1989 form should be amended accordingly. The provision does not
address large package sales which although are not “substantially all of its oil and gas assets” are
nevertheless significant. In light of the sale of large packages of oil and gas properties and the
concomitant disputes that have arisen, it may be worthwhile to examine whether an exception
should also be made for significant package sales.
The preferential right provision should be retained if a party anticipates that it might wish
to increase its interest in the JOA; it provides the right to purchase the interest of any party who
has offered it for sale to a third person. Article VIII.F provides the parties to a JOA some
assurance that they will not have to deal with entities with whom they do not want to do
business. If a party wishes to sell its interest and another party to the JOA is concerned about the
entity that might purchase the interest, this provision can be used to acquire the selling party‟s
Questions have arisen with regard to whether mergers and corporate restructurings trigger
the preferential purchase right provision. In Fina Oil and Chemical Co. v. Amoco Production
Co., 673 So. 2d 668 (La.App.1996) the Court of Appeals of Louisiana, First Circuit affirmed the
trial court‟s decision that held that the clause was not triggered when a participant transferred its
interest in the Contract Area to its subsidiary in connection with a reorganization. The Court of
Appeals of Louisiana found that “… [u]nder the corporate of Louisiana, sale of corporate shares
does not result in the transfer of the corporate property….[w]ithout a sale or transfer of the lease
interests the provisions of the preferential right clauses were not triggered.”
In Questa Energy Corporation v. Vantage Point Energy, Inc., 887 S.W.2d 217 (Tex.
App. 1994), the Texas Court of Appeals held that prior to the transaction in question, the
interests covered by the JOA were held by subsidiaries of a Canadian company, and that the
transaction simply transferred those interests to another entity controlled by the Canadian
company rather than to an outside entity. The plaintiff was not exposed to the risk of an
“undesirable outsider” holding the interests. Thus, the court found that the transaction did not
trigger the plaintiff‟s right under the preferential right to purchase provision of the JOA.
In the interesting case of Murphy Exploration v. Sun Operating, 747 So.2d 260 (Miss.
1999), the issue on appeal was whether the preferential right to purchase in a JOA is barred by
the Rule Against Perpetuities. The JOA provided that a co-tenant had to provide prior notice of a
sale to the other co-tenants so that they could meet the proposed purchase price if they desired.
Sun sold its interests to a third party without giving notice to Murphy and the other co-tenants.
Murphy and the other co-tenants filed a suit against Sun requesting specific performance of the
preferential right to purchase. Sun asserted that the Rule Against Perpetuities invalidated
Murphy‟s preferential right. Sun filed a motion for summary judgment based on this proposition.
The lower court granted the motion. The Court of Appeals of Mississippi held that “…[b]ecause
the preferential right to purchase does not offend the public policy considerations inherent in the
Rule Against Perpetuities, the Rule should not be applied herein” stating that the court erred in
granting summary judgment to Sun on this issue. The case was reversed and remanded. In
Producers Oil Company v. Gore, 610 P.2d 772 (Okla. 1980) the Oklahoma Supreme Court found
that the Rule Against Perpetuities did not invalidate a JOA preferential purchase position.
Claims and Lawsuits – Article X
This provision states that “operator may settle any single uninsured their party damage
claim or suit arising from operations hereunder if the expenditure does not exceed”21 a specified
amount. If $10,000 is inserted in the blank, does the operator have the right to settle 75 claims,
none of which exceed $10,000, but total $700,000 in the aggregate? Although a literal
interpretation may give the operator authority to settle 75 single uninsured third party damage
claims, none of which individually exceed $10,000, such a result is not consistent with the
purpose and intent of this provision which gives the non-operators the right to provide input on
how to handle a problem where settlement will exceed the amount specified.
Force Majeure – Article XI
This provision has been amended to state that in addition to the payment of money, the
furnishing of security shall not be affected by a force majeure event. This is a worthwhile
Notice – Article XII
The 1989 Form clarifies that oral notices are to be “confirmed immediately” in writing,
that originating notices are deemed delivered when received, and that responsive notices are
deemed delivered when deposited in the mail, deposited at the office of the courier or telegraph
service, transmitted by telecommunications equipment or personally delivered.
Terms of the Agreement – Article XIII
Several revisions have been introduced which clarify issues that have surrounded option
no. 2. under the 1982 form, the term of the JOA is extended if a well “results in production of oil
and/or gas in paying quantities.”
The 1989 form revises this language to read “results in a completion of a well as a well
capable of production of oil and/or gas in paying quantities.” This change clarifies the fact that a
well need not be producing to perpetuate the JOA.
Conflicts have arisen regarding the term of JOA, where a marginal well has been
completed within the Contract Area but is not producing and there is a question of whether it will
ever produce. Some parties may want to perpetuate the JOA and others may want to terminate
A new provision has been added that addresses this situation. A well is deemed
“abandoned” and, consequently, the JOA terminates if the parties decide not to conduct any
further operations on the well or 180 days elapse from the conduct of any operations on the well,
which ever occurs first. Care must be exercised to ensure that a legitimately shut-in well waiting
the construction of a pipeline or other facilities which shut-in period exceeds 180 days does not
trigger the termination of the JOA. Note that pursuant to state law, a financing agreement must
be released when the underlying security agreement terminates.
The 1989 form anticipates that a memorandum of operating agreement and financing
statement will be executed and recorded. To aid in obtaining the requisite release or notice of
termination, language has been added which provides that upon the termination of the operating
agreement and the satisfaction of all debts, all parties will execute the notice of termination.
This provision could be improved by providing that all parties agree that upon
termination of the operating agreement and the satisfaction of all debts that the operator is to file
a release and termination or notice of termination.
Governing Law – Article XIV.B
If all the acreage within the Contract Area is located in one state, there is no need to
complete the blank.
This provision has not been amended, although the 1989 form uses boldface type to
specify the governing law, to comply with state statutes.
Miscellaneous – Article XV
A new article has been incorporated. This article addresses execution, successors and
assigns counterparts and severability.
The provision addressing execution attempts to cure the all too common problem of a
well spudding before the JOA is fully executed. While this practice is universally agreed to be
bad, many wells spud without a fully executed JOA. This provision institutes several new rules.
The JOA is binding as to those who execute the document, notwithstanding that it is not
fully executed by the parties listed on Exhibit A. Although not so stated, it is assumed that a new
Exhibit A would be created on an acreage ownership basis within the Contract Area. The
operator can, by written notice, terminate a JOA if it is not fully executed (at any time prior to
the actual spud date of the initial well, but in no event later than 5 days prior to the date specified
for commencement of the initial well) if the operator in its sole discretion determines there is
insufficient participation to justify drilling.
If the operations are terminated, all obligations are extinguished and all money advanced
must be returned, without interest. If, however, the operator proceeds with drilling operations for
the initial well and the JOA has not been fully executed, the operator must “indemnify non-
operators with respect to all cost incurred for the initial well which would have been charged to
such person under this agreement if such person had executed the same, and operator shall
receive all revenues which would have been received by such person under this agreement if
such person had executed the same.”22
How extensive is the definition of the word “indemnify?” Is it limited by the term “with
respect to all costs incurred for the initial well…?” In addition to paying drilling and completing
costs, is the operator also responsible for ensuring that interest of each non-operator in
production remains at a level specified in the original Exhibit A?
What if the operator does not personally have enough production to give a non-operator
sufficient production to equal what he would have been entitled had the JOA been executed by
every party listed in Exhibit A? For example, assume that the Contract Area consists of 160
acres, being the NE/4. Derman Oil owns the NE/NE. Amadeo Petroleum owns the NE/SE.
ChevronTexaco owns the SW/NE. Derman Oil and ExxonMobil jointly own the NW/NE,
Derman Oil owning an undivided 10 percent and ExxonMobil owning an undivided 90 percent.
ExxonMobil never executes the JOA.
A prolific well is drilled in the NW/NE on a 40 acre drilling and spacing unit by Derman
Oil, as operator. Obviously, Derman Oil is required to reimburse Amadeo Petroleum and
ChevronTexaco for all their expenditures relating to this well. Is Derman Oil liable to Amadeo
Petroleum and ChevronTexaco for the production they would have received (25 percent) had
Derman Oil obtained ExxonMobil‟s signature on the JOA? It is assumed that the indemnity is
only limited to costs; and consequently, Derman Oil is not liable to Amadeo Petroleum and
ChevronTexaco for the production they would have received had ExxonMobil executed the JOA.
The 1989 form clearly states that the terms and obligations of the JOA are not personal,
but rather run with the leases or interests. While this recitation is nice, it does not bind
subsequent bona fide purchasers for value that are not aware of particular burdens or
encumbrances. It would be advisable for assignees to ratify the JOA. The JOA may be signed in
counterpart. While the practice in the United States with regard to transfers of interests in a JOA
anticipates simple assignments, the proper practice is novations where the assignee accepts the
rights and the obligations and the other parties to the JOA agree to look to the assignee for all
purposes associated with the JOA.
The “severability” provision now attempts to prohibit a bankruptcy court from assuming
or rejecting only a part of the JOA. This provision unambiguously states that “[f]or the purpose
of assuming or rejecting this agreement as an executory contract pursuant to federal bankruptcy
law, this agreement shall not be severable.”
In addition, to addressing situations where a party is insolvent, an additional
sentence has been included that provides, “the failure of any party to this agreement to comply
with all of its financial obligations provided herein shall be a material default.”23 As mentioned
previously, the inclusion of this sentence may well aid non-operators in their efforts to replace an
operator that is material default of the JOA.
The 1989 AAPL 610 Model Form incorporates many improvements over the 1982 form,
yet for historical reasons the 1989 form has never attained universal acceptance. A review of the
1989 form by landmen and lawyers will substantiate that the 1989 form contains many valuable
provisions that clarify the rules that govern the relationship between the operator and the non-
operator. The time spent familiarizing oneself with the benefits of the 1989 Form will clearly
offset the time spent in the future when commercial or operational questions arise that are simply
not addressed within the 1982 form, but are addressed in the 1989 form.
AAPL 610 Model Op. Agree. art. 1.
Id. art. III.B.
Id. art. III.C.1
Id. art. IV.A.
976 F.2d 254 (5th Cir 1992)
Id. at 261
Id. art. V.B.I.
Id. art. V.D.2
Id. art. XV.D
Id. art. V.D.
Id. art. VI.B.
Railroad Comm’n of Texas v. Olin Corp., 690 S.W. 2d 628 (Tex. App. – Austin 1985),
writ ref’d n.r.e., 701 S.W. 2d 641 (Tex. 1985)
AAPL 610 Model Op. Agree. art. VI.B.2(b).
Id. art. VI.B.8.
Id. art. VI.D
17 Id. art. VI.E
18 Id. art. VI.F
19 Berchelmann v. Western Co., 363 S.W. 2d. 875 (Tex. Civ. App. 1962)
20 Id. art. VIII.B.
Id. art. X.
AAPL 610 Model Op. Agree. art. XV.