term assignment oil and gas

Assignment of Oil and Gas Lease

An oil or gas lease provides the lessee with many rights regarding the use of the land and the minerals buried underneath it. When that lease is signed, it creates a real estate, which can be further divided or assigned to other parties. That’s where the term assignment comes from in the oil and gas industry. 

But the assignment of oil and gas lease can include the transfer or conveyance of various things. So for anyone involved in an oil or gas lease in any capacity, it’s beneficial to understand the meaning of assignment and its implications for the lease itself. 

Assignment of Oil and Gas Lease Meaning

The definition of assignment in real estate is the sale, transfer, or conveyance of a whole property ownership/rights or part of it to another party. 

The term in the oil and gas industry is used for sale, transfer, or conveyance of working interest, lease, royalty, overriding royalty interest, or net profit interest. 

Since real estate property rights or mineral rights in the case of oil and gas are divisible, mineral rights owners or lessees often sell or convey parts of the mineral rights to other companies. The legal instrument used for this purpose is called an assignment. 

The party assigning the rights is called the assignor, and the party receiving the rights is called the assignee. 

Assignments are filed in the same way as an oil and gas lease or a title deed to a property. These legal documents need to be drafted in accordance with the state requirements and filled with the relevant county or municipality authorities. 

Of the different assignment transactions in the oil and gas industry, the assignment of rights in the oil and gas lease is the most common. While the lease itself is the negotiable instrument in the scenario, the assignment establishes the successful transfer of the rights. 

It may look like a simple document, but the rights and duties of the different parties can make it complex. As a result of the assignment, the property interests, rights, and obligations of the lessor, lessee, and assignee may alter. 

On top of this, any local laws governing such a transfer also need to be accommodated. Now, federal regulations also impact the transfer of oil and gas interests. 

What Can Be Assigned?

The lessee of an oil or gas lease can assign the entire lease or part of it. In other words, the lessee can sell or transfer part of the estate or the entire estate to which they have the working rights. 

The assignee is assigned the working interest and lease obligations, including override royalty. The assignment document will state the percentage of override royalty, which is the percentage of the mineral removed from the land under lease and the net profits received by the assignee by the sale of the minerals. 

An overriding royalty interest is an undivided interest that gives the holder the right to receive a certain percentage of the revenue from the sale of the mineral. This differs from royalty interest in that the overriding interest cannot be divided and doesn’t grant ownership of the mineral rights once the assignment expires. 

In other words, the original mineral owner (the lessor) retains a royalty interest, whereas the lessee assigning the lease to an assignee gets the overriding royalty interest. 

Multiple Lease Assignments

Normally, the assignment mentions and describes the lease assigned to an assignee. 

However, an oil or gas company often may have multiple lease agreements with different mineral owners from the same field or formation. On the other hand, the leases involving different lessees may have undergone unitization to increase production and reduce competition. 

In such cases, the assignment may include multiple leases. If multiple leases are in an assignment, they are typically described in an exhibit with the document. However, in cases of unitization, the assignment may not necessarily list or describe the leases. Instead, it will just mention all the lease agreements in a particular unit or tract of land. 

It all comes down to the document’s language, as sometimes the focus is on the rights and obligations rather than the actual lease or property. 

Assignment Limitations

Oil and gas leases are pretty flexible regarding how they can be further leased or assigned. An assignor may choose to assign the lease as is or set limitations that may not exist in the original lease. An assignor may set the following limitations for the assignee:

• Wellbore Limits: The assignment may set the production to the wellbore only. In other words, the assignee can only produce the mineral from the wellbore of a particular well, and all the interests outside of this wellbore are not assigned. In such a case, the assignee cannot produce from deeper formations. 
• Depth Limits: The assignment may set the interest to a certain depth or a particular formation by mentioning the formation’s depth or name. For instance, the assignee may only have a working interest up to a depth of 8,000 ft. from the surface. These are more common in assignments than wellbore limitations. Such limitation may also automatically apply if the oil or gas lease also had depth limitations. 
• Horizontal Limits: The assignment may set horizontal limitations or, in other words, include only a part of the land. The assignee would not be able to produce from outside these parts of the land as described in the assignment, even if they are part of the actual lease. 

Assignment of oil and gas lease is a common instrument in the oil and gas industry in the US, used to assign lease rights and obligations to other companies. The companies with the lease can assign multiple leases to the same party. Similarly, they can divide a lease and assign it to different parties. 

The assignment procedure and documentation may vary based on state laws and the individual case. However, it’s a detailed document that specifies what is covered under the assignment, what duties befall the assignee, and what they need to pay the assignor. 

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Assignment Of Oil And Gas Lease

Jump to section, what is an assignment of oil and gas lease.

An assignment of oil and gas lease is a contractual agreement between a landowner and an oil or gas company in which the company gains the right to explore for, develop, and produce oil and gas from the property. The leaseholder typically compensates the owner with periodic payments (called royalties) based on the amount of oil or gas produced. Leases can be assigned to another party, such as a drilling contractor, if the original leaseholder decides not to pursue development. Assignment of an oil and gas lease should be done in writing and filed with the appropriate government authority.

Assignment Of Oil And Gas Lease Sample

Reference : Security Exchange Commission - Edgar Database, EX-10.1 6 exh101.htm ASSIGNMENT OF OIL AND GAS LEASES. , Viewed October 27, 2022, View Source on SEC .

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Oklahoma Bar Journal

Interpreting assignments of the oil and gas lease.

By Jereme M. Cowan

Under Oklahoma law, an oil and gas lease grants a cluster of rights in land,1 forming an estate in real property with the nature of fee.2 Like many of the sticks in the metaphorical bundle, the estate created under the oil and gas lease is freely assignable and divisible.3 As a result, oil and gas leaseholds can be transferred, in whole or in part, by the holder of the oil and gas lease, such practice being a central element to oil and gas development.4 Furthermore, the transfers of leasehold are usually executed and delivered by legal instruments ubiquitously titled “assignments,” which are filed of record in the same manner as any instrument affecting title to real property.5 Given the history of Oklahoma’s oil booms,6 not to mention Oklahoma’s current role in the U.S. shale boom, assignments inundate many of the county clerk records where oil and gas exploration is prevalent. Therefore, it is likely that an examination of oil and gas land titles in one of these counties will require the interpretation of assignments. BASIC RULES OF CONSTRUCTION Assignments are a contract and a conveyance.7 As such, they are to be read in accordance with the basic rules of contractual interpretation,8 which comprise not only those findings in Oklahoma’s case law but also the statutory provisions of 15 O.S. §§151-178. In a nutshell, Oklahoma’s rules on interpreting assignments begin with prioritizing the true intent of the parties, as gathered from the four corners of the instrument.9 If the assignment is unambiguous, then the written instrument will govern,10 along with all technical terms in the assignment being interpreted as commonly understood among persons in the oil and gas industry.11 However, if there is an ambiguity, then the contractual interpretation can be aided by extrinsic evidence in order to resolve the intrinsic uncertainties of the assignment.12

These rules make it imperative for an attorney conducting a title examination to understand the business and terminology of the oil and gas industry as it pertains to the transfer of leasehold, not to mention understanding general rules of land titles and the law of oil and gas. The purpose of this article is not to give a complete account of the oil and gas industry nor an account of all rules governing the transfer of oil and gas rights in the record title. Rather, the purpose is to give an introductory and cursory overview, presented on a step-by-step basis, for an attorney who may find themselves, either willingly or unwillingly, examining assignments of oil and gas leases filed in Oklahoma. STEP 1: WHAT TYPE OF INTEREST? First and foremost, the title examiner needs to determine the type of interest being assigned (or reserved) in the leasehold. More often than not, if the assignment is transferring an interest in a lease without overriding royalty language or net profits language, then a working interest is being assigned. When there is ambiguity, the title examiner should remember that a working interest is the right to  work  on the leased property — searching, developing and producing oil and gas. On the other hand, an overriding royalty interest is share in production attributable to a particular lease. STEP 2: WHAT AMOUNT OF INTEREST? Working interests tend to be relatively straightforward. Either the assignor is purporting to assign all of its right, title and interest under a lease, all of a lease (read 100 percent) or a fractional interest in a lease. Digressing a bit, now would be a good moment to discuss the difference between all right, title and interest  of the assignor  and 100 percent of a lease. All of the assignor’s right, title and interest could be 100 percent or could be some fractional interest. It depends on what the assignor owns of record. If an assignor assigns a lease without any fractional limitations or without the foregoing language limiting it to the assignor’s right, title and interest, then the assignor is purporting to assign 100 percent of the lease. The prudent examiner notes the distinction.

Overriding royalty interest can sometimes not be as straightforward. Often, the assignor decides to use a formula for the computation of the assigned or reserved overriding royalty interest. For example, a recitation in the assignment reads as follows: an overriding royalty interest equal to the difference between 20 percent and lease burdens. Here, the overriding royalty interest would be calculated by first adding up all the lease burdens, such as a one-eighth landowner’s royalty and a previously conveyed one-thirty-second overriding royalty interest, and then subtracting that number from 20 percent, which is represented mathematically as: 20% - (1/8 + 1/32) = 4.375%.

There are various business reasons for computing an assigned or reserved overriding royalty interest with the subtraction of lease burdens from a certain percentage, the most prominent being that assignments of leases typically cover a block of leases, which contain various lease net revenue interests. Showing the overriding royalty interest as a formula rather than a specific number allows the assignor to either retain or convey the leases at certain net revenue interest. In the prior example, assuming the assignor was assigning the overriding royalty interest, it was retaining an 80 percent net revenue interest in all the leases covered by the assignment except, of course, those leases which were already burdened greater than 20 percent. STEP 3: WHAT LEASE IS COVERED? All leasehold interests derive from a lease. Therefore, it is imperative that the examining attorney determine what lease is covered by an assignment. If the assignment covers one or just a few leases, then the lease(s) will probably be described somewhere in the body of the instrument. If the assignment covers multiple leases, then typically they will be described in an exhibit “A” attached thereto. However, it should be noted that in some cases an assignment may not describe a particular lease or leases but instead will include language that it is the intent to assign all leasehold rights in a particular tract of land, usually the unitized area. For example, an assignment may read that all of the assignor’s rights in the leasehold covering the SW/4 are transferred to the assignee without giving further explanation as to the underlying leases.  In this particular example, the assignor is conveying whatever leasehold rights it may own from whatever source such rights might derive as to the SW/4.

STEP 4: WHAT ARE THE LIMITATIONS TO THE ASSIGNED INTEREST? By far the most challenging (and often most ambiguous) aspect of an assignment is the limitations to the assigned interest. Like land itself, a lease is a bundle of sticks. A lease can be cut and carved any which way, limited only by the imagination of the oil and gas industry. If an assignor wants to assign a lease insofar as that lease covers a particular formation in the strata, then the assignor can do so. The following are standard limitations that the examining attorney should recognize.

An assignment can be limited to the wellbore of a well. A wellbore limitation means that the assignor is assigning only those rights to production from the wellbore of a certain well, arguably at the total depth it existed at the time of the assignment. All interest outside the wellbore are excluded from the assignment, entailing that a wellbore assignee can produce from shallower formations in the wellbore but cannot produce from deeper formations or lands outside the wellbore.

The central problem with wellbore only assignments is determining when in fact there is a wellbore only assignment. The title examiner should be aware that a wellbore assignment is the narrowest of assignments. Very limited rights to the lease are being assigned. It can be argued that the lease or unit and the lands covered by the lease or unit need only be described for informational purposes, as it is rights to the wellbore being assigned. Furthermore, the fact that a well or unit is mentioned in the description of the lease does not entail that the assignor intended to convey wellbore rights only. More often than not, a reference to a well or unit in Oklahoma is for informational purposes.

Some assignments are limited to certain depths or to a particular formation. For instances, an assignment may limit the assigned leases “insofar as said leases cover the Woodford Formation” or “insofar as from the surface to a depth of 8,100 feet.” Depth limitations are usually more prominent than wellbore limitations and are considerably less ambiguous. Furthermore, title examiners should always read an assignment thoroughly to determine whether a depth limitation is pertinent. Many times, such a limitation is buried in one of the numerous special provisions of the assignment or placed in one of the exhibits attached thereto.

In order to accommodate the formation of units, leases will often be assigned only as to a portion of the lands covered thereby. For example, a participant enters into a joint operating agreement with the operator that has proposed the drilling of a 40-acre unit well located in the NW/4 NW/4. If the participant owns all of a certain lease covering the N/2 NW/4, the participant may decide to assign only that portion of the lease covering the NW/4 NW/4, thereby retaining all rights in the NE/4 NW/4. Therefore, assignments may contain limitations as to the area acreage being conveyed.

CONCLUSION The foregoing steps serve as an introduction to interpreting assignments of oil and gas leases. Most certainly, each step of analysis could be accompanied by a more detailed explanation. That said, the key point to be made here is that the interpretation of assignments in oil and gas land titles requires a familiarization of the business practices of the oil and gas industry, not just an understanding of the governing law.

ABOUT THE AUTHOR Jereme M. Cowan is a managing partner at Cowan & Fleischer PLLC. Mr. Cowan’s practice fo-cuses on oil and gas land titles. He has planned, moderated and spoken at a number of oil and gas seminars sponsored by the Oklahoma Bar Association.

1.  See Hinds v. Phillips Petroleum Company , 1979 OK 22, 591 P.2d 697, 698 (1979) (stating that “[t]he cluster of rights comprised within an instrument we refer to ‘in deference to custom’ as an ‘oil and gas lease’ includes a great variety of common-law interests in land”). 2.  See Shields v. Moffitt , 1984 OK 42, 683 P.2d 530, 532-33 (1984) (finding that “the holder of an oil and gas lease during the primary term or as extended by production has a base or qualified fee,  i.e. , an estate in real property have the nature of a fee, but not a fee simple absolute”). 3.  See Hinds  at 699 (concluding that leasehold interests are freely alienable “in whole or in part”); Eugene Kuntz,  Kuntz, a Treatise on the Law of Oil and Gas , Volume Five, §64.1, 259 (1987) (asserting that the oil and gas lease is freely assignable “in the absence of a provision to the contrary”);  see also Shields  at 533 (holding that a lease clause restricting alienation was void). 4. John S. Lowe,  Oil and Gas Law in a Nutshell , Sixth Edition (2014). 5. Joyce Palomar,  Patton and Palomar on Land Titles , 3rd Edition, Volume One, 3 (2003). 6. Kenny A. Franks,  The Oklahoma Petroleum Industry  (Norman: University of Oklahoma Press, 1980). 7.  See Plano Petroleum, LLC v. GHK Exploration, L.P. , 2011 OK 18 (2011). 8.  K & K Food Servs. v. S & H, Inc. , 2000 OK 31, 3 P.3d 705, 708. 9.  See Messner v. Moorehead , 1990 OK 17, ¶8, 787 P.2d 1270, 1272. 10.  Messner  at 1273. 11. 15 O.S. §161. 12.  Crockett v. McKenzie , 1994 OK 3, ¶5, 867 P.2d 463, 465.

Originally published in the  Oklahoma Bar Journal --  OBJ 88 pg. 285 (Feb. 11, 2017)

• Apps & Integrations
• Books and Journals
• FNREL - Special Institute
• Advanced Landman's Institute (FNREL)
• CHAPTER 6 WELLBORE ASSIGNMENTS OF OIL AND GAS LEASES

TIMOTHY C. DOWD is an attorney with Elias, Books, Brown & Nelson, P.C., in Oklahoma City, Oklahoma. Mr. Dowd is a past President of the Oklahoma City Mineral Lawyers Society (1996-97); and is past Chairperson of the Oklahoma Bar Association Mineral Law Section (2005-06). Mr. Dowd is the author of the Oklahoma chapter of AAPL's Nationwide Comparison of Laws on Leasing, Exploration and Production (2011) and the chapter on Oil and Gas Titles in West Publishing Company's Oklahoma Real Estate Forms and Practice. Mr. Dowd has written numerous articles for publication including:

Trespass in the Age of Horizontal Drilling Under State Conservation Statutes , 63 Rocky Mt. Min. L. Inst. 6A-1 (2017);

Current and Emerging Issues in Oil and Gas, Title Examination , Oil & Gas 2 Nat. Resources & Energy J. 505 (2017);

Clearing Title of Long-Lost Mineral Owners , 54 Rocky Mt. Min. L. Inst. 30-1 (2008); and Preferential Rights to Purchase in Oil and Gas Transactions , 49 Rocky Mt. Min. L. Inst. 5-1 (2003).

Mr. Dowd's primary area of practice is oil and gas law, including the rendering of title opinions and the drafting and negotiation of industry contracts.

I. Introduction

Wellbore assignments present a unique challenge to the title examiner. As has been frequently noted, there is a dearth of case law interpreting wellbore assignments, 1 although that is beginning to change as the cases presented in this paper demonstrate. Wellbore assignments are frequently ambiguous. Drafters are often not relying on a form, not relying on a good form, or not thinking long term and anticipating future operations. The third situation is frequently the case with older assignments drafted prior to the frequency of horizontal drilling. This paper will discuss in turn the principals of contract interpretation necessary to interpret an assignment that is limited to less than the entire leasehold estate. Then the paper takes a look at the current state of case law regarding wellbore assignments. Finally, the paper offers tips for drafting an unambiguous assignment.

II. Principles of Contract Interpretation

Conveyances of interests in oil and gas leases are subject to the same general rules of interpretation as contracts. 2 The primary goal in construing an assignment or any conveyance is to determine the intent of the parties as expressed in the conveyance. 3 Often referred to as the "four corners" doctrine, a court will look at the conveyance in its entirety, 4 with effect given to every part of the conveyance. 5 Generally, if an instrument is clear and unambiguous on its face, then extrinsic evidence will not be admitted to

determine the intent of the parties. 6 Whether a contract or a conveyance is ambiguous is a question of law, and thus for the court to decide. 7

There are two basic approaches to contract interpretation that have been called the traditional view and the modern view. In jurisdictions that follow the traditional rule, contract interpretation is treated as a question of law for the court to decide based on the four corners of the instrument by applying rules of construction. Only after a court determines that the intent of the parties cannot be determined from the document itself (i.e. that it is ambiguous) will a court allow extrinsic evidence to determine the intent of the parties. 8

According to the modern view, as contract interpretation seeks to determine what the parties actually intended, the fact that the parties dispute intent makes the conveyance ambiguous. 9 A conveyance is ambiguous if it is "reasonably and fairly susceptible of different constructions" 10 or contains "an intrinsic uncertainty." 11

In specifically eschewing the four corners rule, New Mexico allows extrinsic evidence in order to determine whether a conveyance is ambiguous, even though it treats the question of whether a contract is ambiguous as a question of law. 12 It is also a rule of construction that a conveyance will be construed most strongly against the grantor. 13

In theory, a title examiner would apply the same rules of contract interpretation that a court would, especially in a situation where there is no extrinsic evidence of intent of the parties. In practice, a title attorney would consider outside factors in construing an instrument regardless of whether the instrument seems unambiguous. Frequently, two parties will argue that an instrument unambiguously supports each party's claim, only to have a court decide that the instrument is ambiguous. 14 Thus, it is difficult for a title examiner to determine what a court would decide is ambiguous. Further, a title examiner may be advised that a client claims a certain interest as a result of a conveyance. Whether or not the conveyance is ambiguous, the title examiner will likely credit his or her client with the interest claimed, subject to a title requirement to obtain some sort of stipulation or other curative. Thus, the cautious approach for a title examiner is to err on the side of

finding ambiguity, consider all available evidence as to the intent of the parties, and draft an appropriate requirement.

Given that construing wellbore assignments is so heavily fact-based, and that courts have interpreted cases in some surprising ways, it is instructive to look at some cases in further detail.

III. Case Law

A. Petro Pro, Ltd. v. Upland Resources, Inc . 15

Petro Pro, Ltd. v. Upland Resources, Inc . is probably the seminal case construing a wellbore-only assignment. The King "F" No. 2 Well was completed on a tract that was later pooled to create a 704-acre gas unit, producing from the Cleveland Formation between 6,500 and 6,600 feet, but also including the Brown Dolomite Formation between 3,400 and 3,600 feet. KCS Medallion Resources ("KCS") and MB Operating Co., Inc. ("MB") were the owners of this unit. In November 1998, KCS and MB conveyed to L & R Energy ("L & R"):

All of Seller's right, title and interest in and to the oil and gas leases described in Exhibit "A" attached hereto and made a part hereof ("Subject Leases") insofar and only insofar as said leases cover rights in the wellbore of the King "F" No. 2 Well. 16

Beginning in May 2003, Upland Resources ("Upland"), pursuant to a farmout agreement with KCS, drilled three wells in the Brown Dolomite Formation: the Skeeterbee No. 1 and Skeeterbee No. 2 Wells, both horizontal wells, and the Skeeterbee No. 3, a vertical well.

In April 2004, L & R assigned its interest in the King "F" No. 2 Well to Petro Pro, Ltd. ("Petro Pro"). Upon inquiry, Petro Pro determined that KCS and Upland were treating the interest of Petro Pro as a wellbore-only interest in the King "F" No. 2 Well.

In September 2004, Petro Pro filed suit seeking to quiet title to the entire 704-acre pooled unit, from the surface to a depth of 6,800 feet. Several royalty owners intervened, seeking damages for alleged breach of implied covenants and for tortious interference with existing contracts. The royalty owners argued that Petro Pro's lawsuit and claims of ownership prevented Upland from fully developing the lease from drainage from adjacent wells.

In cross motions for summary judgment, Upland contended that Petro Pro's interest was limited to production and enhancement of production from the Cleveland Formation from the confines of the King "F" No. 2 Well. The royalty owners contended that Petro Pro had the right to produce from any formation, subject to governmental regulations limiting Petro Pro's horizontal rights to forty acres surrounding the King "F" No. 2 wellbore. Petro Pro contended they were the exclusive owners of any portion of the leasehold estate that could reasonably be reached and produced through the King "F" No. 2 wellbore. At trial, the court found the assignment unambiguous and granted Upland's motion for summary judgment.

The court of appeals found that the judgment entered by the trial court failed to resolve the rights conveyed by the assignment. The court of appeals construed the limitation to "rights in the wellbore" as limiting the assignment to production from the wellbore of the King "F" No. 2 Well at the depth it existed at the time of the conveyance. This meant that Petro Pro's rights included the right to produce from shallower formations, including the Brown Dolomite, but not the right to extend the wellbore vertically or horizontally, and not the right to share in production from any other well that may be drilled on the lease.

Important points in this case are that the court relies on Texas' ownership-in-place theory to support its finding that the assignment was unambiguously limited to the gas that may be produced from the wellbore of the King "F" No. 2 Well. Thus, the court effectively gave some guidance on how to interpret an assignment limited to a wellbore absent greater definition. The only geographical area conveyed and owned by Petro Pro was that required to operate and produce the King "F" No. 2 Well, and the depths conveyed to Petro Pro are the depths (both horizontally and vertically) penetrated by the existing wellbore. Further, Petro Pro had the right to use the wellbore to produce from any uphole formations.

B. Key Production Company, Inc. v. Quality Operating, Inc . 17

Key Production Company, Inc. v. Quality Operating, Inc . follows Petro Pro in finding that the language "insofar and only insofar as" described is a limitation on the grant but neither reserves nor conveys any interest.

In Key Production Company, Inc. v. Quality Operating, Inc . the Texas Court of Appeals construed a purchase and sale agreement, an assignment, and an amendment of the assignment, a joint operating agreement, and a declaration of unit in order to determine the intent of the parties. Exxon was an owner of an interest in the Pearline...

To continue reading

• Table of Contents
• CHAPTER 1 OPERATING AGREEMENTS, FARMOUTS, TERM ASSIGNMENTS, AREAS OF MUTUAL INTEREST, REASSIGNMENT OBLIGATIONS, AND RIGHTS OF FIRST REFUSAL
• CHAPTER 2 CUSTOMIZING THE OIL AND GAS LEASE FROM THE LESSEE'S PERSPECTIVE
• CHAPTER 3 NEGOTIATING THE OIL AND GAS LEASE FROM THE LANDOWNER'S PERSPECTIVE
• CHAPTER 4 DIVIDING, SURRENDERING, AND ASSIGNING THE LEASE: HOW PUGH CLAUSES AND OTHER PROVISIONS CAN ALTER THE INTEREST COVERED BY A LEASE
• CHAPTER 5 NON-TRADITIONAL LEASE TERMS AND HOW AND WHEN TO USE LEASE RATIFICATIONS - UPDATED
• CHAPTER 7 EXTRA PROVISIONS - THE FINAL WORD IN THE AAPL MODEL FORM OPERATING AGREEMENT
• THE BLM'S MANAGEMENT OF FLUID MINERAL DEVELOPMENT ON SPLIT ESTATE: ACCESS ISSUES AND FEE-FEE-FED WELLS
• CHAPTER 10 APPLYING TITLE DEFECTS UNDER A TYPICAL PURCHASE AGREEMENT
• STATE LAW REGIMES GOVERNING SURFACE USE - WYOMING AND COLORADO
• STATE LAW REGIMES GOVERNING SURFACE USE - TEXAS AND NEW MEXICO
• CHAPTER 12 SINGLE WELL SPACING AND POOLING: STATE SPACING AND JURISDICTION OVER CONSERVATION
• CHAPTER 13 ETHICAL OBLIGATIONS OF LAWYERS AND LANDMEN IN NEGOTIATING LEASES

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The Oil and Gas Report

What Are the Types of Interests in Federal Oil and Gas Leases and How Are They Assigned?

Federal oil and gas leases are administered by the Bureau of Land Management (“BLM”) pursuant to the Mineral Leasing Act of 1920, as amended (“MLA”), and the implementing federal regulations. Federal leases have a slightly different ownership scheme than fee oil and gas leases. As to fee leases, the lessee owns a leasehold interest that includes the right to drill for and produce the leased substances, subject to royalty payments to the lessor. The term “working interest” is commonly used and is generally considered synonymous with the lessee’s interest and the term “leasehold interest.” As to federal leases, the lessee’s leasehold interest includes both record title and operating rights. Initially, these two types of interests are merged together as  the record title interest, but the operating rights interest can be severed from the record title interest by assignment.  The record title interest includes the obligation to pay rent and the rights to assign and relinquish the lease. [1] The operating rights interest authorizes the holder to drill for and conduct operations and produce the leased substances. [2] When all or a portion of the operating rights have been severed from the record title, the operating rights interest owner is primarily liable for its pro rata share of payment obligations under the lease while the record title interest owner is secondarily liable. [3] At the extreme, if all of the operating rights as to all depths are severed by assignment from the record title interest, the lessee owns “bare” record title interest and has no rights to drill for and produce the leased substances. The term “working interest” is generically associated with the operating rights interest unless said operating rights interest has not been severed from the record title interest, then it is associated with the record title interest. Otherwise, the range of interests that may be created out of federal leases is nearly the same as fee leases.

The interests in federal leases are generally conveyed by a “transfer,” being defined in the federal regulations as “any conveyance of an interest in a lease by assignment, sublease or otherwise.” [4] Set forth below is a discussion of the different types of interests that may be transferred in federal leases and whether the instrument transferring the interest must be filed with and approved by the BLM. [5]

Record Title Interests

The MLA and federal regulations use the term “assignment” for a transfer of all or a portion of the lessee’s record title interest in a lease. [6] All assignments of record title interests must be on the currently approved BLM form Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources, Form 3000-003. [7] Record title interests may be transferred as to all or part of the acreage in the lease or as to either a divided or undivided interest therein. [8] Record title interests may not be transferred as to limited depths or horizons, separately as to either oil or gas, less than part of a legal subdivision, [9] or less than 640 acres (outside of Alaska). [10]

Upon receipt of the assignment, the BLM will engage in an “adjudication” process whereby the BLM will determine and identify the owners of interests and their percentage interest in the lease as a consequence of the assignment and approve the assignment if it meets all statutory and regulatory requirements. The rights of the assignee will not be recognized by the BLM until the assignment has been approved. [11]

Operating Rights Interests

The MLA and federal regulations use the term “sublease” for a transfer of a non-record title interest in a lease, including a transfer of operating rights. All transfers of operating rights interests must be on the currently approved BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources, Form 3000-3a. [12] For transfers of operating rights interests, the MLA and federal regulations do not contain any limitations on such transfers other than it must be as to “all or part of the acreage in the lease.” [13]

Upon receipt of the transfer, the BLM will engage in the adjudication process to determine and identify the owners of interests and their percentage interest in the lease as a consequence of the transfer and approve the assignment if it meets all statutory and regulatory requirements. The rights of the transferee will not be recognized by the BLM until the transfer has been approved. [14]   However there was a period of time where most state offices of the BLM did not adjudicate transfers of operating rights.

Beginning in 1985, the BLM issued internal guidance, Washington Office Instruction Memorandum No. 1986-175 (Dec. 30, 1985) (“IM 1986-175”), stating that it was not necessary for the BLM to “adjudicate” operating rights assignments [15] on the grounds that they are third-party contracts. The BLM adjudicators were instructed to stop adjudicating operating rights transfers, and to instead “rubber stamp” them within 30 days of their submission when there was no “evidence to the contrary regarding qualifications and proper bonding.” [16] Accordingly, most BLM offices began accepting transfers of operating rights and “approved” the transfers without confirming and determining the ownership of the operating rights interests. In 2013, the BLM issued Instruction Memorandum No. 2013-105 (April 4, 2013) (“IM 2013-105”), directing all BLM offices to immediately begin again adjudicate transfers of operating rights interests. [17]  Understanding that there would be a backlog to carry this out this directive, IM 2013-105 provides a priority schedule for adjudicating existing and future transfers of operating rights as follows: if first production occurs on or after October 1, 2012, adjudicate all transfers of operating rights immediately; if first production occurred prior to October 1, 2012, adjudicate as necessary to enable the Office of Natural Resources Revenue (“ONRR”) to issue appropriate orders to the owners; and adjudicate all remaining unadjudicated operating rights transfers when time and staffing allows.

Obviously, the BLM offices are faced with trying to adjudicate and determine the current operating rights interest owners based on over thirty years of potentially incomplete and possibly erroneous transfers contained in the BLM lease files. A survey was conducted in 2017 of the following BLM State Offices to determine how they were implementing IM 2013-105 and adjudicating transfers of operating rights. [18]

For leases occurring prior to 2012, the Colorado State Office is only conducting reviews for leases with production at the request of ONRR. When it discovers discrepancies, it considers those transfers null and void from their inception and does not provide or send out unapproved operating rights decision letters because the transfers were never adjudicated. Colorado is not willing to accept county records or other outside sources to assist in curing title deficiencies. For leases occurring after October 1, 2012, the Colorado Office will adjudicate all transfers accordingly.

Montana, North Dakota, South Dakota, and Utah [19]

The Montana and Utah State Office never stopped adjudicating transfers of operating rights; accordingly, IM 2013-105 did not change how they are adjudicating such transfers.

New Mexico, Kansas, Oklahoma, and Texas [20]

The New Mexico State Office is conducting a piecemeal review of its lease files. Initially, when the New Mexico State Office received a new assignment and could not account for the purported interest to be assigned, they retroactively denied previously approved transfers either (a) all the way back until the title examiner could account for the purported interest; or (b) through 1991. It appears that recently, the New Mexico State Office has become willing to consider outside records in examining title to fill in gaps in currently filed assignments, such as recorded assignments, evidence of corporate successions, etc.

The Wyoming State Office adjudicates operating rights for all new leases, as well as any adjudications requested by ONRR. It also has plans to adjudicate operating rights for all producing leases according to staff availability. The Wyoming State Office is currently using the Lease Interest Worksheet to chain title retroactively and adjudicate operating rights at the request of the ONRR. During this review, and when any new transfer is filed, if the State Office examiner cannot account for the purported interest to be assigned, they stamp the Lease Interest Worksheet “discrepancy.” Thereafter, the Wyoming State Office will not approve any subsequent transfer until the problem in the chain of title is resolved. No notice of the discrepancy is provided to the parties who received interests through transfers now marked with a discrepancy, so without review of the current BLM case file for each lease or subsequently denied transfer, parties who believed they previously owned operating rights are not aware their rights have been called into question. This requires the Wyoming State Office to deny any subsequent transfers for leases containing a discrepancy, and to disregard any assignments occurring before the discrepancy that were previously approved.

In an attempt to complete a chain of title, bring current its files, and resolve any discrepancies, the Wyoming State Office is accepting a certified copy of an assignment recorded in the county records and attached to a BLM form Transfer of Operating Rights that is completed by general references to the attached county assignment. The Wyoming State Office will issue a decision stating that its records are incomplete and in order to complete its records, it is accepting and approving the assignment.

Overriding Royalty Interests, Production Payments, and Other Interests

The federal regulations make specific reference to only two other types of interests, overriding royalty interests and production payments. [21] Transfers of these interests must be filed with the BLM and will be included in the lease file, but are not subject to BLM approval. [22] While they can be filed on either a BLM form assignment, [23] any form of assignment may be used.

While net profits interests and carried interests are not expressly mentioned in the regulations governing assignments of interests, such interests are included in the definition of “interest.” [24] The usual practice is to follow the same filing procedures prescribed from assignments of overriding royalty interests and production payments above.

Liens and Security Interests under Mortgages and Other Financing Instruments

Liens and security interests in federal leases created under mortgages and other financing instruments do not fall within the definition of “interests” under the regulations and are not required to be accepted for filing under the regulations. Most BLM offices will discourage or even reject the filing of mortgages and other financing instruments. As a result, mortgages and other financing instruments are typically only filed in the county records.

Transfers by Operation of Law

The regulations identify two types of transfers by operation of law: death and corporate reorganization. When an owner dies, his or her rights will be recognized as having been transferred to the heirs, devisees, executor, or administrator of the estate, upon the filing of a statement that all parties are qualified to hold an interest in a federal lease. [25] The BLM office will typically also require, along with the statement, supporting information concerning the demise of the owner.

In the case of corporate name change, merger, or conversion, no assignment is required unless otherwise required by state law. The regulations require that notification of the name change, merger, or conversion be furnished in the proper BLM office. [26]

_____________________

Prior to filing any transfer with the BLM, it is always to the advantage of the parties to the transfer to make inquiry of the oil and gas adjudication personnel at the applicable BLM office to confirm that the parties have prepared the transfer in compliance with the office’s policies and procedures.

[1] 43 CFR § 3100.0-5(c). Record title is the ownership in a federal lease as recognized by the BLM.  Therefore, it has no connection to the title or leasehold ownership reflected in the applicable county records.

[2] 43 CFR § 3100.0-5(d). The term “operating rights” should not be confused with the right to serve as operator on the ground. An operator is the person or entity that is responsible under the terms and conditions of the lease for operations being conducted on the leased lands; it can include, but is not limited to, the lessee record title interest owner or operating rights interest owner. See 43 CFR § 3160.0-5

[3] See 43 CFR §§ 3106.7-6(b), 3216.12.

[4] Id. § 3100.0-5(e).

[5] Not addressed herein are the qualifications to own an interest in a federal lease and the specific filing requirements.

[6] Id. § 3100.0-5(e).

[7] Most recent revision date is August 1, 2015.

[8] Id. § 3106.1(a). Note, the assignment of the entire interest in a portion of the leasehold will result in a segregation of the lease.

[9] Generally, requiring all of a governmental lot or quarter-quarter section under the Public Land Survey System.

[10] 30 USC § 1987a; 43 CFR § 3106.1. The 640 acre limitation was added to Section 30A of the MLA in 1987 pursuant to the Federal Oil and Gas Onshore Leasing Reform Act. Assignments of record title of less than 640 acres will be approved if the assignment constitutes the entire lease or is demonstrated to further the development of oil and gas.

[11] 43 CFR § 3106.1(b).

[12] Most recent revision date is August 1, 2015.

[13] 43 CFR § 3106.1. There is no written guidance defining “part of the acreage” or addressing this apparent acreage requirement. It appears that at least some minimal amount of acreage must be transferred to comply. Accordingly, although some BLM State offices will accept transfers of operating rights for less than 40 acres, they will not accept for approval, or even for filing purposes only, transfers of operating rights in a wellbore only.

[14] Id. § 3106.1(b).

[15] The term “assignment” is used generically in the IM applying to an assignment of either a record title interest or an operating rights interest.

[16] IM 1986-175.

[17] IM 2013-105 was issued in direct response to the 1996 amendment to Section 102(a) of the Federal Oil and Gas Royalty Management Act, 30 USC § 1712(a), providing that the owner of the operating rights shall be primarily liable for its pro rata share of payment obligations under the lease and the owner of the record title interest (if different from the owner of the operating rights interest) became secondarily liable. The federal regulations at 43 CFR Section 3016.7-6 and 3216.12, reflect these same principals. Furthermore, the BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources specifically provides that the transferee’s signature “constitutes acceptance of all applicable terms, conditions, stipulations, and restrictions pertaining to the lease… (Part B, paragraph 3) and “upon approval of a transfer of operating rights (sublease), the sublessee is responsible for all lease obligations under the lease rights transferred to the sublessee” (Part C, paragraph 8).

[18] See Jared A. Hembree and Uriah J. Price, Holding a Wolf by the Ears – A Look into BLM’s Policy on the Retroactive Adjudication of Operating Rights, 63 Rocky Mt. Min. L. Inst., Paper 11 (2017) (not yet published).

[19] The Montana State Office administers federal lands in Montana, North Dakota, and South Dakota. The Utah State Office administers federal lands in Utah only.

[20] The New Mexico State Office administers federal lands in New Mexico, Kansas, Oklahoma, and Texas.

[21] 43 CFR § 3106.1.

[22] 43 CFR § 3106.1(b).

[23] Both of the current BLM forms include a box that can be checked to indicate that it is for an overriding royalty interest assignment.

[24] 43 CFR § 3000.0-5(1).

[25] Id. § 3106.8-1.

[26] Id. § 3106.8-3.

Understanding an oil and gas lease: What does it really mean?

Know what a landman is offering in an oil and gas lease before you sign.

We have all heard the old adage ‘the devil is in the details.’  This holds particularly true in oil and gas leasing. The story line has repeated itself time and time again since the Marcellus Shale land rush came to Pennsylvania.  A landman contracted by the gas exploration company knocks on a landowner’s door, puts a lease in front of them, and asks them to sign on the dotted line.  Stories have percolated up that some unscrupulous landmen use ‘scare tactics’ to entice landowners to sign quickly – suggesting that the company will drill under their land even if the landowner doesn’t sign a lease, or that if they don’t sign now the landman won’t be back…neither of which are true.

Many times a landowner signs a lease presented by a landman without a firm understanding of the implications either with respect to their rights or the rights of generation after generation of their family members who inherit the land.

Below are some of the provisions that may be included in oil and gas leases.  It is by no means a complete list, but it provides examples of what may be discussed and negotiated with the landman and the gas exploration company.

A lease provision might state that:

The Lease is granted for any or all of the following purposes: the right to stimulate all coal seams or other strata or formations using any and all methods and technology available at the time of stimulation;

This means that the lease is not limited to exploration of the Marcellus Shale formation which sits 5,000 or more feet below the surface.  Coal seams are located much closer to the surface and the operations to extract natural gas from such coals seams is a markedly different process than extraction from the Marcellus Shale strata deep below the surface.  There are other natural gas bearing formations that lie below the Marcellus Shale strata, such as the Utica Shale, and those will be developed in time as well.

A lease might include this language:

…to transport by pipelines or otherwise across and through the Leased Premises Oil and Gas from the lands covered by the Lease, for so long as the transportation of such production may be desired by LESSEE;

This provision allows the oil and gas exploration company (the “Lessee”) to lay natural gas pipelines across your land even if your land is not used for the well pad.  Many leases include a provision that the company’s right to keep these pipelines in place remains even after the lease you signed has terminated and you are no longer receiving royalties.  Often a lease will state that no additional money is paid to the landowner for use of their land for pipelines.

Most leases provide something like the following:

…the placing of tanks, equipment, electric power lines, telephone lines, water lines, impoundments and ponds, compression and collection facilities, roads, structures for the production of Oil and Gas, together with the right to enter into and upon the lands covered by the Lease at all times for the aforesaid purposes.

Many landowners say that the landman assured them that there will be no ‘surface operations’ on their property – that their land will only be ‘drilled under.’  While that may be true, the lease will often still provide that the company can do much more than drill under the landowner’s property.  The sentence above is common in oil and gas leases and one can only imagine the impact of any of these structures on their land.  The last sentence permits the company to enter your land “at all times.”  Drilling operations run around the clock so this might mean at 5:00 in the morning, or after midnight, or whenever.

All leases will describe the leased premises:

The lands covered by the Lease are situated in [        ] Township, [       ]  County, Commonwealth of Pennsylvania, Tax Parcel Number(s) [          ], being all the property owned by LESSOR or to which LESSOR may have any rights in said Township, and including all adjacent or contiguous lands owned or claimed by LESSOR, although not included within the boundaries of the land particularly described above.

This language can take a landowner by surprise.  Suppose that you own several parcels of real estate in a county or different counties – one parcel you live on, and the other parcels are farmland that you inherited years ago.  You intend to only lease the minerals rights to the farmland (which is identified specifically by Tax Parcel ID and a description of the deed) and you sign the lease with the language above included.  You have just leased the mineral rights to the land under your home.

Oil and gas companies may want to aggregate your land with adjacent lands:

LESSOR grants to LESSEE the right at any time to pool or consolidate the Leased Premises with other lands, whether owned by or leased to LESSEE or owned by or leased to others, to form an oil, gas, and/or coalbed methane gas pooled unit for the purpose of drilling a well or wells thereon.

Oil and gas exploration operations have two footprints – one above ground and one below ground.  Above ground, operations include such things as the well pad, impoundment pit, the well head, etc.  A well pad can cover several acres.  Add to that the hundreds of other acres that are needed for a staging area for water trucks, access roads, metering or compression facilities, pipeline routing, etc. and one can see why the company needs to lease large swaths of acreage.  Even if you lease your mineral rights your surface land may never be touched.  The companies need the leases also to cover the subsurface area that will be drilled and fracked.  To accomplish all of this the companies combine the leased lands into a ‘pool’ or ‘unit.’  This is important to understand because whatever royalties are paid from a producing well will be split among the landowners in the ‘unit’ and will be based on their respective acreage.  It is also important because companies can rely on ‘commencing operations’ on lands other than yours, but you are still bound by the terms of the lease that you signed.

Many oil exploration companies buy and sell leases as part of their business model:

LESSEE shall have the right to assign and transfer this Lease in whole or in part at anytime, and LESSOR waives notice of any assignment or transfer of this Lease.

Signing an oil and gas lease is a business deal, but it has a personal side as well.  You hopefully have researched the company you intend to lease with, you have some idea how fiscally strong it is, how environmentally conscious it is, how long it has been around.  To the companies, these lease holdings are commodities that are sometimes bought and sold.  It is only fair that you get to decide who holds the lease to your mineral rights, Right? If you signed a lease that includes the language above, the answer is ‘Wrong.’

Every lease will have a primary term and circumstances for extending that term:

This Lease shall continue in force and the rights granted to LESSEE shall be quietly enjoyed by LESSEE for a term of Five (5) years (the “Primary Term”), and as long thereafter as operations are conducted on the Leased Premises, or as long as well(s) producing Oil and Gas in paying quantities or well(s) capable of producing Oil and Gas in paying quantities from the Leased Premises or from lands unitized or pooled therewith, in the sole judgment of LESSEE.

This is a short paragraph in the typical oil and gas lease, but it is arguably one of the most important.

Oil and gas exploration companies generally want to hold the leased mineral rights for a period of years until they actually begin drilling.  This could be because the price for natural gas is down, or their rigs are operating elsewhere, or for any number of business reasons.  So the company will pay you a ‘bonus’ (a set dollar amount per acre leased) as part of a ‘paid up lease’ and their obligations to you are fulfilled for the Primary Term, generally five (5) years.

What happens when the Primary Term expires?  What if the company has not yet started drilling, and may not be ready for some time beyond expiration of the five (5) year Primary Term, but it would like to still hold the lease to your mineral rights.  Often companies will attempt to extend the Primary Term, sometimes without additional money paid to you, by relying on “and as long thereafter as operations are conducted on the Leased Premises” or “well(s) capable of producing Oil and Gas in paying quantities from the Leased Premises or from lands unitized or pooled therewith” language in the lease.  “Operations” are sometimes defined in the lease, sometimes not, but in nearly every case the term “Operations” is more expansive than actually drilling a hole in the ground.  It may include seismic testing, or it may include putting up a fence or excavating an access road (on your lands or lands that you don’t own but that have been ‘pooled’ or ‘unitized’ with your land).  A “well capable of production in paying quantities” has been determined by Pennsylvania courts to be generally at the sole discretion of the oil and gas exploration company.  Whichever vice is used, the effect is the same – your mineral rights remained leased out to the company despite the fact you may not have received a dime in royalties.

As noted above, this article discusses some of the most common, and important, provisions you will find in an oil and gas lease, but each lease and each situation brings with it specific issues.

Remember that an oil and gas lease might affect your rights to your land for generations to come.  Do your homework and learn about the company you are dealing with and most importantly if you are not an oil and gas leasing expert it is in your best interest to get help from someone who is.

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General Oil and Gas Leasing Instructions 

The BLM issues competitive leases for oil and gas exploration and development on lands owned or controlled by the Federal government.

Congress passed the Inflation Reduction Act of 2022 which rescinded the BLM’s authority to issue noncompetitive leases.

Congress passed the Federal Onshore Oil and Gas Leasing Reform Act of 1987 requiring that all public lands eligible and available for oil and gas leasing be offered by competitive leasing.

The maximum competitive parcel size is 2,560 acres in the lower 48 states and 5,760 acres in Alaska outside of the National Petroleum Reserve-Alaska. The BLM issues a competitive lease for a 10-year period. 

BLM State Offices conduct lease sales quarterly when parcels are eligible and available for lease. Each State Office publishes a Notice of Competitive Lease Sale (Sale Notice), which lists parcels to be offered at the auction, usually 45 days before the auction. This notice is posted in the  National Fluids Lease Sale System  and by the State Office that administers the sale.  The Sale Notice specifies lease stipulations applicable to each parcel. The BLM may conduct lease sales in-person or through internet-based auctions.

Lands offered in the Sale Notice come from two sources:

• Lands identified by informal expressions of interest from the public; or,
• Bureau motion, or lands identified by the BLM.

The successful bidder must submit a properly executed 3000.002 lease bid form , which constitutes a legally binding lease offer. The bidder must also pay an administrative fee, the first year's advance rental ($3.00 per acre or fraction thereof), and not less than a $10-per-acre minimum bonus bid. The balance of the bonus bid must be paid within 10 working days from the last day of the auction.

Expenses associated with a lease 

Bonds:  Before an operator conducts any surface-disturbing activities related to drilling, a bond must be provided to the BLM to ensure compliance with all the lease terms, including environmental protection. Form 3000-004, Oil and Gas or Geothermal Lease Bond may be used for coverage of the principal on individual, statewide, or nationwide coverage with personal or surety bonds. The minimum required bond amount is $10,000 for an individual bond and will provide coverage for the principal on the single Federal lease. The minimum required bond amount is $25,000 for a statewide bond and will provide coverage for the principal on Federal leases in the state or states named on the bond form. A minimum of $25,000 for each state you name on the form is required. The minimum required bond amount is $150,000 for a nationwide bond and will provide coverage for the principal on Federal leases in the United States, except for the National Petroleum Reserve in Alaska. (Federal leases do not include Indian leases.)  The BLM will require an increase in the bond amount whenever conditions warrant.

Bonding can be secured by using a corporate surety bond, or a personal bond accompanied by negotiable Treasury securities, a cashier’s check, a certified check, a certificate of deposit, or an irrevocable letter of credit.

When a new person or company becomes the operator on a well, that new person or company must notify the appropriate BLM Field Office of the change in operator. The new operator must specify to the BLM what bond will cover its operations.

Rents:  Annual rental rates for a competitive lease is $3.00 per acre (or fraction thereof) in the first 2 years; $5.00 per acre for lease years 3 through 8; and $15.00 per acre each year thereafter. The first year’s rental payment is filed with a winning bid in the proper BLM office. Once a lease is issued, the second and all subsequent rental payments must be paid to the Department of the Office of Natural Resources Revenue (ONRR)  on or before the lease anniversary date. If the rental is not received by the anniversary date each year, the lease will automatically terminate through operation of law. A lessee will not receive advance notice of imminent rental due and lease termination. It is the responsibility of the lessee to pay timely rentals.

Royalties:   The ONRR collects a royalty on production for Federal onshore leases. The Federal onshore oil and gas rate is 16.67% for leases issued after August 16, 2022. However, there are a few exceptions, including different royalty rates on older leases, reduced royalty rates on certain oil leases with declining production, and increased royalty rates for reinstated leases.

Lease Terms

Terms and conditions: A lessee, may explore and drill for, extract, remove, and dispose of oil and gas deposits, except helium, for the lands covered under the lease. Before conducting any surface-disturbing activities, the operator must obtain BLM approval. Drilling proposals are subject to the lease terms and stipulations that are attached to the lease and necessary mitigation measures that are consistent with the lease rights. Please see due diligence requirements in the lease instrument. The BLM may cancel the lease if the lessee fails to comply with lease terms.

Transfer of interest: Interest in a lease can be transferred by assignment of the record title interest or by transfer of the operating rights interest. The assignment or transfer must be submitted to the appropriate BLM office within 90 days from the date the transferor signs it and an administrative fee. Until the BLM approves the transfer, the U.S. Government does not recognize the rights of the transferee, and the transferor remains fully responsible for the lease. The BLM will not approve any assignment of record title for a separate zone, deposit, depth, formation, a specific well, or part of a legal subdivision, nor will the BLM approve any assignment of record title for less than 640 acres outside Alaska, or less than 2,560 acres within Alaska. However, the BLM may approve an assignment of record title for less than this acreage, if it is for the entire leasehold or the parties can demonstrate that approval will increase the chances of development.

For more information on transferring oil and gas leases view the handout:  Information and Procedures - Transferring Oil and Gas Lease Interests .

Expiration: A lease will expire at the end of its primary term, which is usually 10 years. However, the BLM may extend the lease, or the lease may continue under its own terms, if:

Qualifying drilling operations are in progress; the lease contains a well capable of producing in paying quantities; or the lease is entitled to receive an allocation of production from an off-lease well.

Relinquishment: Lessee(s) may give up all or part of the lease by filing a written relinquishment with the appropriate BLM office. A relinquishment takes effect on the date it is filed. However, all wells and other work as may be required by the BLM must be performed so the lease is in proper condition for abandonment. The lease account must be in good standing with the ONRR.

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Farmout: What it Means, How it Works, Example

Adam Hayes, Ph.D., CFA, is a financial writer with 15+ years Wall Street experience as a derivatives trader. Besides his extensive derivative trading expertise, Adam is an expert in economics and behavioral finance. Adam received his master's in economics from The New School for Social Research and his Ph.D. from the University of Wisconsin-Madison in sociology. He is a CFA charterholder as well as holding FINRA Series 7, 55 & 63 licenses. He currently researches and teaches economic sociology and the social studies of finance at the Hebrew University in Jerusalem.

Gordon Scott has been an active investor and technical analyst or 20+ years. He is a Chartered Market Technician (CMT).

What Is a Farmout?

A farmout is the assignment of part or all of an oil, natural gas, or mineral interest to a third party for development. The interest may be in any agreed-upon form, such as exploration blocks or drilling acreage. The third-party, called the "farmee," pays the "farmor" a sum of money upfront for the interest and also commits to spending money to perform a specific activity related to the interest, such as operating oil exploration blocks, funding expenditures, testing or drilling.

Income generated from the farmee's activities will go partly to the farmor as a royalty payment and partly to the farmee in percentages determined by the agreement.

More generically, a farmout may also refer to any other instance where some activities are outsourced , such as farming out investment strategies by a portfolio manager to a sub-manager .

Key Takeaways

• A farmout is when a resource-producing property is outsourced for development to a third party or farmee.
• The farmee pays the owner (farmor) royalties on income generated from the outsourced activities.
• Farmouts are most common in natural resources exploration and extraction, such as with oil, gas, or minerals mining.

Understanding Farmouts

A company may decide to enter into a farmout agreement with a third party if it wants to maintain its interest in an exploration block or drilling acreage but wants to reduce its risk or doesn't have the money to undertake the operations that are desirable for that interest. Farmout agreements give farmees a potential profit opportunity that they would not otherwise have access to. Government approval may be necessary before a farmout deal can be finalized.

The farmor usually receives a royalty payment once the field is developed and producing oil or gas, with the option to convert the royalty back into a specified working interest in the block after paying for drilling and production expenses that were incurred by the farmee. This type of option is commonly known as a back-in after payout (BIAPO) arrangement.

Farmout agreements are effective risk management tools for smaller oil companies. Without them, some oil fields would simply remain undeveloped due to the high risks facing any single operator.

Example of a Farmout

Farmout agreements are very popular with smaller oil and gas producers who own or have rights to oil fields that are expensive or difficult to develop. One company that makes frequent use of this type of arrangement is Kosmos Energy (NYSE: KOS ). Kosmos has rights to acreage off the coast of Ghana, but the cost and risks to develop these resources are high because they are underwater.

To help reduce these risks, Kosmos "farms out" its acreage to third parties like Hess ( HES ), Tullow Oil, and British Petroleum (BP). Doing so allows these offshore blocks to be developed and generate cash flow for all the parties involved. A farmee like Hess takes on the obligation to develop the field and, in return, has the right to sell oil that is produced there. Kosmos, as the farmor, earns a royalty payment from Hess for supplying the acreage and the natural resource.

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Farmout Agreements: The Basics, Negotiations and Motivations

Posted by: Austin Brister in Primers and Insights , The Deal Corner

The Basics:

A Farmout Agreement is an agreement with a working interest owner (“Farmor”) whereby the Farmor agrees to assign working interest to the Farmee in exchange for certain contractually agreed services. Typically these services include drilling a well to a certain depth, in a certain location, in a certain timeframe, and also typically stipulates that the well must obtain commercial production. After this contractually agreed service is rendered, the Farmee is said to have “earned” an assignment. This Assignment comes after the services were completed, and is subject to the reservation of an overriding royalty interest in favor of the Farmor.

This overriding royalty interest is usually said to be a “convertible override.” This means that upon payout, which is the point where the drilling costs have been recouped from production from the well, the Farmor can elect to convert this override into a portion of the working interest. This decision whether to convert or not depends on whether the Farmor wishes to join in production costs in exchange for the possibility of a larger return on NRI. If the Farmor does not wish to take the risks associated with the cost-bearing working interest, he will choose not to convert the override. If the Farmor is comfortable with the project costs and proceeds from the well, he will decide to convert his override into working interest. All of these terms are negotiable in the Farmout Agreement.

Here’s an example. You are working as a landman for David Oil Co. You have retained a small battalion of field landmen and leased up a nice large area your geologist believes will be productive. This gives you 100% of the working interest. You pay 100% of the expenses, and receive 100% of the net revenue interest (all the proceeds less royalty burdens, overriding royalty burdens, tax, etc.). Your geologist is excited and believes the geology is ripe to provide a high return. However, given the particular geology, you will need to drill directionally to a deep formation. The deeper the formation, the more it’s going to cost, and you’re not sure you have enough in your budget to pay for it.

In comes Goliath Oil Co., who was late to the play and wasn’t able to lease your area. Goliath has a lot of money and it wants in because its geologists agree that there is a lot of money to be made in your area. Rather than wait around for your leases to expire, Goliath chooses to approach you and offer to “farm in” to your working interest. It is willing to drill the well(s) for you and pay the drilling costs (what is known as a “drilling carry”), in exchange for you assigning them a percentage of your working interest. Another way to think of it is obtaining drilling services where the consideration is an assignment of working interest rather than cash.

Negotiating the Farmout Agreement

As with all negotiations, understanding the other party’s interests and motivations is key to effective negotiation and properly structuring a complete deal. You could Consider negotiation skills training to equip your people to negotiate with confidence and success to help in this aspect. You should be able to better estimate how far the other party will be willing to give and take in negotiating the terms of the Farmout Agreement. Knowing this will also help you understand the other party’s best alternative to the negotiated agreement . The following are the most common interests motivating Farmors and Farmees.

Interests Motivating the Farmor :

• Drilling so as to maintain the lease (satisfy primary term, avoid Pugh clause consequences, satisfy continuous drilling obligations, etc.);
• Monetizing an abandoned prospect;
• Sharing risk;
• Obtaining geological information from the farmee and the farmee’s operations; and

Interests Motivating the Farmee :

• Quickly obtain acreage;
• Obtain acreage without leasing operations, and without expending capital on buying leases;
• Utilize equipment and personnel that would otherwise not be utilized;
• Gain interest in a prospect area that is already leased, but the farmor is not developing; and

Thoroughly understanding both your motivations and the other party’s motivations are essential to effective negotiation and deal-making. This is crucial so that you understand you and your adversary’s must-haves and true bargaining room. Every good negotiator does this whether they consciously think of it or not . Understanding your motivations and alternatives are important to keep your head on straight and to ensure you are picking the right battles. On the other hand, understanding the other party’s motivations and alternatives is crucial for two main reasons: (1) you will better know how far you can push the other side to obtain favorable terms and conditions, (2) you will better understand and anticipate which terms the other side will insist on, and (3) you can make the other side’s alternatives less attractive, harder to implement, or less valuable, all of which may help your side of the negotiations.

In my experience, including when I was in the heavy construction industry, knowing what the other party was truly after made negotiations much easier. It is not always possible, but when we can closely narrow in on our motivations and confidently estimate the other side’s motivations, we seldomly fight tooth and nail over every provision, and are able to focus in on what actually matters to each party. In the end, we have better agreements.

If you want to know more, make sure to check out Key Provisions of a Farmout Agreement .

I’d love to hear your thoughts, comments, stories, and suggestions in the comments! What were the factors motivating your most recent Farmout Agreement?

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