A QUICK PRIMER ON MINERAL RIGHTS

A QUICK PRIMER ON MINERAL RIGHTS ROBERT L. THERIOT Liskow & Lewis 1001 Fannin St, Suite 1800 Houston TX 77002 State Bar of Texas NEW FRONTIERS IN MARITAL PROPERTY LAW October 4-5, 2012 New Orleans CHAPTER 2.2

TABLE OF CONTENTS I. WHAT ARE THE RIGHTS IN MINERALS? SOME BASIC CONCEPTS... 1 A. Ownership of Oil and Gas in the Ground and The Rule of Capture... 1 B. The Mineral Estate and Severance of Mineral Rights... 1 C. Dominance Over the Surface Estate... 2 II. THE MINERAL LEASE... 2 A. Granting Clause... 2 B. The Habendum Clause... 2 C. Bonus & Rentals... 3 D. The Secondary Term... 3 E. The Royalty Clause... 3 F. Statutory and Lease Protection of the Royalty... 4 G. Pooling Clause... 4 III. SPECIFIC TYPES OF INTERESTS... 4 A. Mineral Interest... 5 B. Leasehold Interest... 5 C. Working Interest... 5 D. Operator or Operating Interest... 5 E. Royalty Interests.... 5 1. Lessor s Royalty... 5 2. Overriding Royalty... 5 3. Nonparticipating Royalty Interest... 6 F. Executive and Non-Executive Interest... 6 G. Net Profits Interest... 7 H. Carried Interest... 7 I. Production Payment... 7 J. Wellbore Interests... 7 IV. CO-OWNERSHIP AND SPLIT INTERESTS... 7 A. The Rights of Cotenants... 8 B. Partition... 8 C. Life Estates... 8 D. Dealing in Fractional Interests... 9 1. Division of Interests NWI and NRI... 9 2. Grants and Reservations... 9 3. Double Fractions... 10 V. OTHER CONTRACTUAL AND CONTINGENT INTERESTS... 11 A. JOAs, Participation, and AMI Agreements... 11 B. Farmouts... 11 VI. CONCLUSION AND FURTHER READING... 12 i

A QUICK PRIMER ON MINERAL RIGHTS For the practitioner dealing with marital properties and family assets, this article is intended as introduction into the concepts of rights in natural resources, focusing on mineral rights. Most of the more familiar and common terms and interests such as leases, royalties, overrides, and mineral estates are discussed. Issues commonly arising in divisions of marital and community assets, such as co-owned interests, life estates, fractional and portioned interests are also mentioned. A full exposition of these issues is beyond the scope of this primer, but a bibliography is included at the end suggesting a few excellent, more in-depth, resources for the practitioner. I. WHAT ARE THE RIGHTS IN MINERALS? SOME BASIC CONCEPTS A. Ownership of Oil and Gas in the Ground and The Rule of Capture The landowner has the exclusive right to work his land for the exploration, development and production of minerals that lie underneath. This concept has been accepted in all producing states, including Texas. States differ on the conceptual basis of this right. Texas recognizes that the landowner actually owns the oil and gas in place beneath his land. Texas Co. v. Daugherty, 176 S.W. 717, 720 (Tex. 1915). Other states, such as Oklahoma and Louisiana, conclude that the landowner does not the oil and gas under his land until produced; until then he owns only the exclusive right to develop and produce that oil. The practical difference between these two concepts is usually nil, however, and similar practices, terms, and manners of exercising mineral rights exists in all producing states with the unique exception in Louisiana that severed mineral rights revert back to the landowner after ten years of non-use. Elsewhere, such as Texas, severed mineral remained severed in perpetuity, unless the deed is for a term or condition. Ownership of oil and gas is subject to the rule of capture. Early in the history of oil production, courts assumed that oil ran underground like rivers of water. Thus, for numerous legal and practical reasons, early courts in virtually all states adopted the rule of capture, under which the owner of minerals under a tract of land owns all the oil and gas that he can produce from a well on that land, even if some of that oil is drained from under his neighbor s land. In other words, although one may own the oil under his land, he has no complaint (at least not in property law) if that oil is drained by his neighbor s well. In the early years, the combination of the rules of ownership and capture resulted in the over-development and wasteful exploration practices seen in those early black-and-white photographs of the original Texas oil fields, where it seemed there was a well every few feet. Everyone was trying to get his oil out as fast as possible before being drained by his neighbor. For years now, this wasteful practice has been eliminated by a combination of regulatory and industry practices. On the regulatory side, the Texas Railroad Commission ( RRC ) regulates well spacing and allowables. Its basic spacing rule requires the producer to own (or have pooled together) the mineral rights covering, in effect, the 40 acres surrounding his well. Under the correlative rights doctrine and concept of fair share, the RRC s rules must ensure that every owner of mineral rights has an opportunity to produce his fair share of the minerals under his land without being unfairly limited by the spacing rules or being allowed to produce excess production to the detriment of his neighbors. Private practices included pooling agreements and joint operating agreements whereby multiple mineral owners can combine their interest to allow shared and efficient development. B. The Mineral Estate and Severance of Mineral Rights The landowner may sever the right to minerals from whether by grant or reservation in a deed. Stephens County v. Mid-Kansas Oil & Gas Co., 254 S.W. 290 (Tex. 1923). Once severed, the right in minerals is called the mineral estate and the remainder is the surface estate. Unless the severance is conditioned or for a term, the severance is permanent. In Texas, particularly in large estates in oil and gas producing areas, it is quite common for the minerals to have been severed, in whole or part, from the land years ago. A mineral estate is a real property interest of equal dignity as the surface estate and, as a general rule, all of the laws and rules applicable to real property, such as conveyancing, recordation, statute of frauds, etc. are applicable. Interests in minerals, whether held by the landowner unsevered, or held separately as a mineral estate can be further divided and severed. Courts recognized five attributes of a mineral estate (sometimes referred to as the bundle of sticks that make up the mineral estate), all or any of which can be severed separately: 1. Right to develop 2. Right to lease 3. Right to receive bonus payments 4. Right to receive delay rentals 5. Right to receive royalty payments 1

Altman v. Blake, 712 S.W.2d 117, 118 (Tex. 1986). This division is more of a recognition of the common rights granted or reserved in practice, rather than an exclusive list of what can and cannot be severed. The exact nature and type of the rights that may be created out of the mineral estate is limited only by the parties imagination and a few legal limitations such as rule against perpetuities and restrictions on contractual provisions that take property out of commerce. The author, in his practice, has seen some fairly unusually rights created out of the mineral interests. By far, the most common and prevalent means by which oil and gas is developed is under a mineral lease or oil and gas lease. Through decades of custom and practice, the mineral leases has become the principal document by which oil and gas rights are granted and minerals developed. In its basic form, the mineral lease is a grant by the mineral owner (the lessor) to another (the lessee) authorizing the lessee to explore, drill, and produce minerals at its own cost and risk, in exchange for an upfront bonus, a fractional royalty of any production obtained, and perhaps annual delay rentals. The lease is granted for a term (typically one to five years) during which the lessee has the right to attempt to drill and obtain production, and, if production is obtained, as long thereafter as production is maintained. Much of the law of oil and gas, including the denomination of the rights listed above, has developed around the mineral lease and the considerations that typically flow from leases. C. Dominance Over the Surface Estate The mineral estate (and any right to develop that is leased or severed from the estate) is considered the dominant estate over the surface estate, and the mineral owner therefore has the right to use as much of the surface as is reasonably necessary to explore, drill, and produce the minerals underlying the land, including the building of roads, the use of subsurface water, laying of pipelines, and the placement of drilling and production equipment. Sun Oil Co. v. Whitaker, 483 S.W.2d 808 (Tex. 1972). It is often a surprise and disappointment to a landowner, whose mineral rights were severed long before, that an oil company can come upon his land and drill a well and he has little say or compensation in the matter. However, the mineral estate s dominance is not absolute. Under the accommodation doctrine, the mineral owner must locate and conduct his operations with reasonable accommodation of the surface owner s existing uses, which may require such things as relocating equipment or drill sites to avoid undue interference with the surface owner s activities Getty Oil Co. v. Jones, 483 S.W.2d 808 (Tex. 1972); Texas Genco, LP v. Valence Operating Co., 187 S.W.3d 118 (Tex. App. Waco 2006, pet. denied). Additionally, the right to use the surface is limited to operations necessary to produce minerals from underneath the same tract, not for operations that may be conducted to produce oil and gas from neighboring tracts in the area. More commonly today, by the terms of the deed or lease, the mineral owner or lessee s rights to use the surface may also be limited and restricted, or may require additional compensation for use. II. THE MINERAL LEASE Although purporting to be a lease, Texas treats a mineral lease as a deed, creating a fee simple determinable estate in the minerals. Stephens County v. Mid-Kansas Oil & Gas Co., 254 S.W. 290 (Tex. 1923) It can be granted by anyone who owns the mineral interests, whether the landowner of an unsevered estate, the owner of a severed mineral estate, or even by the mineral lessee itself, in the case of a sublease. Although, Texas recognizes freedom of contract in the context of conveying mineral rights, through decades of custom, almost all mineral leases follow the same basic form with the following clauses. A. Granting Clause The granting clause describes the rights granted; i.e., the right to enter the land and explore for and produce the minerals. Typically, most lease forms specify the rights of surface use that would otherwise be implied, such as the rights of ingress and access, the right to build roads, lay pipelines, erect facilities, etc.. The granting clause may also extend generally to all minerals, or be limited to only oil and gas, or may exclude specifically certain types of minerals. Absent specification, Texas courts have developed rules interpreting general grants to minerals essentially, the term refers to oil, gas, sulfur, and other minerals obtained from drilling, but excludes soil, gravel, and surface minerals. The granting clause will also describe the property covered by the lease, including any limitations or exclusions. For example, it is not uncommon for a lease to cover only certain depths or subsurface horizons. B. The Habendum Clause The Habendum clause provides the term of the lease. A simple formulation is This lease shall be for years from this date (the primary term ) and as long as thereafter as oil, gas, or other minerals or produced therefrom or from lands pooled therewith. The initial period is called the primary term. This is the term during which the oil company has must drill a well and obtain production if it is to maintain the lease. Today, a primary term of three years appears to be the most common, though terms of one to five are often seen as well. If production is obtained, the lease can be then be maintained past the primary term, or into what is called the secondary term. It is not 2

unusual to find leases fifty years or older still active in Texas that have been maintained for all that time by continuous production. The end of the primary term (without production) or the end of production during the secondary term is the determinable event of the fee simple that terminates the lease. Note that most leases do not actually obligate the lessee to drill a well; rather, it has the right, but not the obligation, to drill a well and obtain production to maintain the lease. C. Bonus & Rentals The Habendum clause will state the bonus and rentals necessary to acquire and maintain the lease through the primary term. There are three general types of leases, depending on the how the primary term is maintained. Historically, the most common form in Texas was the unless lease. This lease provided for an initial bonus, usually computed on an per-acre basis, and an annual rental, also computed (although usually at a lesser rate) on a per-acre basis. The clause is constructed so that the lease terminates on its anniversary date unless the lessee either drills or pays the rental for the next year. The right to pay the rental extends through the end of the primary term, but no longer. If the lessee does not drill or pay, the lease automatically terminates. The second type is the or lease. Under this lease, the lessee must drill or pay the rental through the end of the primary term. The failure to drill or pay does not terminate the lease (until the end of the primary term), but simply gives the lessor a contractual claim for the rental. The third lease, which the author finds is becoming more prevalent, is the paid up lease. In this lease, there is only one payment, the initial bonus payment, which maintains the lease through the entire primary term. No rentals are owed on any anniversary date; although sometimes a paid-up lease is combined with a one-time option to renew for an extended period by paying an additional one-time rental. D. The Secondary Term Under the basic lease form, once production has been obtained, the lease continues into its secondary term until production ceases, at which time the lease terminates. Much controversy has centered over what constitutes a cessation of production; case law has resolve many controversies and modern lease forms typically address them. As a fundamental rule, actual production of oil or gas is necessary to maintain a lease, and the production must be in paying quantities ; that is, a sufficient amount to exceed the continued cost of operating, or at least enough that a reasonable operator would continue operating the well in anticipation of future profitability. Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959). Related to this concept is the temporary-cessation-of-production doctrine. Under this rule, a temporary cessation of production will not terminate the lease. Whether the cessation is temporary is determined by a combination of factors such as the reason for the stoppage, the duration, and the lessee s diligence in restoring production. Because of the uncertainty of what will constitute a temporary cessation, many leases now contain specific clauses providing that production is deemed continuous if there is no gap of more than a certain amount of days (e.g., 90 days). Some leases also contained interrelated provisions such as the continuous drilling clause or the continuous operations clause which allow the lessee to maintain the lease into and through the secondary term by conducting continuous drilling operations, regardless of whether production is obtained or maintained continuously, as long as the lessee is continuous in its drilling efforts. E. The Royalty Clause For the lessor, the greatest potential benefit from leasing his mineral rights is the royalty. This is a fraction of production reserved to the lessor, paid out of production free of production costs. Historically, the royalty fraction was one-eighth. Today, higher royalties are common, up to one-fourth. Of course, the higher the royalty the longer it takes the lessee to recover his costs of development, since the royalty is paid off the top starting with the first barrel out of the ground. Royalty clauses vary greatly in their specific terminology, but, essentially, their economic effect is to entitle the lessor to a fraction of the value obtained by the lessee on the oil and gas produced. Generally, Texas follows at the well valuation, meaning that the royalty value is determined at the well and before the product is gathered, treated, and transported to market. Thus, under a standard royalty clause, the lessee who sells the product at some market distant from the well can deduct, as necessary, its costs of gathering, processing, and transporting the product to market to derive a value at the well, unless the lease expressly provides for a different location or method for determining value. Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). Usually, leases provide a separate royalty clause for oil and for natural gas. Oil royalty clauses commonly provide for delivery of the royalty fraction to the lessor, or to his credit at the lease or pipeline, or to pay the market price or value thereof, of some combination of these terms. Although many variations literally contemplate that the 3

lessor has the right to physically take his royalty share (the right to take-in-kind), few lessors do so, and it is commonly accepted that the lessee may take all of the oil and pay the lessor for his royalty share. Gas royalty clauses typically provide that the royalty is to be paid in value, either on the market value of the gas or on the amount realized from its sale, or some variation between these two. Although in practice, lessees almost always pay their gas royalty on the basis of their sales prices, courts do recognize differences between these two clauses, such that market value means the comparable price in the market, even if different from the lessee s actual sales price. Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866 (Tex. 1968); Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368 (Tex. 2001). Much litigation has occurred over the years involving proper gas royalty valuation. As a result, it is becoming more common to see leases containing detailed royalty clauses that, among other things, limit deductions, require payment on certain market indices, restrict affiliate sales, and otherwise specify the valuation methodology in detail. Leases will sometimes provide an alternative royalty in certain situations For example, most leases provide for a shut-in royalty which is a payment, usually a fixed sum per well, which is owed on a gas well that is completed but shut-in awaiting a pipeline connection to market. In most variations, the shut-in royalty is deemed an in lieu of royalty and operates to maintain the lease as if the well were actually producing. Some leases also provide for a minimum royalty which is a minimum amount which must be paid annually, even if actual production is insufficient to meet that amount. The minimum royalty is more in the nature of a rental which acts to maintain the lease. F. Statutory and Lease Protection of the Royalty Payment of royalty is not considered a condition of the lease; thus nonpayment, late payment, or underpayment will not operate to terminate the lease or permit a suit for cancellation, unless the lease expressly provides otherwise. In addition to any contractual or common law remedies, the lessee can invoke the statutory remedies under Tex. Natural Resources Code. 91-401 et. seq., which impose certain statutory duties on payors of royalties, and provide statutory interest for late payments under certain conditions. Upon the completion of a new well, it is common practice for lessees (or the operator of the well) to issue division orders to all royalty owners in the well for them to execute. Historically, the division order was, essentially, a contract of sale by which the lessee or operator purchased the royalty share from the lessor according to the terms of the division order. Early cases had held that, accordingly, the division order could modify or supersede the lease terms. Today, the practice of issuing division orders is more for the practice of confirming the payment information of the recipient and the ability of the division order terms to modify the lease (or the ability of the lessee to withhold payment until a division order is signed) is circumscribed by the division order statute, Natural Resources Code. 91-401 et. seq., which regulates the issuance of division orders and proscribes the terms that they may contain. G. Pooling Clause Because of spacing requirements necessary to drill and develop mineral rights, lessors usually insist on a pooling clause in the lease. A pooling clause allows the lessor to pool all or part of the lease with adjacent lands so as to create a large enough area to satisfy spacing requirements and geological considerations. The effect of pooling is treat all of the land within the pool as one leased tract so that production from a well on any part of the pool is allocable to the entire tract, usually proportionately by surface acreage. Pooling rights are usually limited to certain sizes, commonly 40 acres for oil units and 640 acres for gas units, often with several exceptions for tolerances, specific RRC field rules, and the like. Also, leases usually provide that the pool must be platted and filed in the county records. By combination of the pooling clause and the habendum clause, a well drilled off the lease, but on lands pooled therewith, maintains the lease as if it were actually drilled on the lease. Especially for larger tracts, the lessor will seek to avoid a pooled well from holding his entire lease by adding a Pugh Clause. A Pugh clause provides that a well on a pooled area only maintains that portion of the lease within the pool. As to the other areas of the lease outside the pool, the lessor will have to pay rentals, drill wells, or obtain production as necessary to maintain that outside acreage, or else it terminates. The effect of a Pugh clause is to ensure adequate exploration and development of the entire tract. Pugh clauses can also be used to limit the area within a lease that can be maintained by a well on the lease, or to provide that a well can only maintain lease rights down to the depth of the deepest well, resulting in the release of unexplored deep rights, the latter provision sometimes called a vertical Pugh clause. III. SPECIFIC TYPES OF INTERESTS The nature of the oil and gas industry is that the interests in minerals is often severed, split, and shared in numerous ways with the resulting differences having different rights. Many of these result in the context of the mineral lease as described above, but these interests can arise in other contexts as well. Often the same right is called 4

different things depending on the context in which the term is used. Also, it is sometimes the case that the parties call a certain interest one thing when, in reality, it is something else. Texas courts usually look to the content and character of the interest, rather than what the parties name it, to determine its true nature. The more common interests one may encounter are described below. A. Mineral Interest The term mineral interest is often used loosely to mean anyone who owns the mineral rights in land, whether it is the landowner of an unsevered estate, the owner of a severed mineral estate, or the lessee under a mineral lease. In its more exacting usage, it would refer to the owner of the severed mineral estate. B. Leasehold Interest The interest granted to the lessee under a mineral lease is called the leasehold interest. It enjoys all of the rights of a owner the mineral interests to develop and produce the minerals from the land, subject only to the burdens of the lease and the lessor s reversionary interest upon termination of the lease. C. Working Interest The person who owns the mineral interest, or the leasehold interest in case of a lease, is also called the working interest because they are the person entitled to work the land; i.e. drill and develop the minerals. Conversely, the working interest owner is also liable for all of the costs of drilling, development and operations. The term working interest is usually used to distinguish that interest from the royalty and other non-cost bearing or non-participating interests. D. Operator or Operating Interest The person who actually drills and operates a well is called the operator. All operators have a working interest, by not all working interest owners have a operating interest. In situations of co-ownership, such as where several coown the mineral interests or leasehold (or owners of different leaseholds combine and pool their interests), one working interest owner may be designated the operator on behalf of all with the right to operate the property. Operators must also be approved and permitted by the RRC. In some cases, the official operator will be a contract operator, who does not actually own an interest in the property, but is paid a fee by the working interest owners to conduct operations on their behalf. E. Royalty Interests. The royalty interest in a nonpossessory, incorporeal right to a share of production or its value free of the cost of production. It is a real property right and a right in land, subject to all of the same rules of conveyancing and recordation as any other real property right. The royalty owner does not have the right to explore for minerals or drill wells. The royalty owner is entitled only to receive his share of production. He does not share in any other revenues attributable to the mineral rights, such as bonuses, rentals, or other proceeds from the sale or lease of the mineral rights in the ground. Because it is a share of production free of costs it is often described as a burden on the mineral rights, such that the working interest owners must pay the royalty off the top and out of their share, thus reducing their revenue needed to recoup their drilling and operating costs and turn a profit. 1. Lessor s Royalty As discussed above, in its usual form, royalty is the share reserved by the lessor under a mineral lease. In that form, it is called the lessor s royalty. 2. Overriding Royalty There is much confusion over the meaning and origin of the term overriding royalty, although it is a common interest in the industry. Probably, it originated during the time that the standard royalty was considered oneeighth, and some doubted whether a higher royalty percentage was permissible under a lease. Thus, a lessor who wanted a higher royalty might ask for an additional overriding royalty, in addition to the standard one-eighth royalty. Today, it is most commonly used and understood to mean any royalty which is carved out of the lessee s working interest as opposed to being carved out directly from the mineral interest or from another royalty interest. In most respects, the overriding royalty is of the same nature and operates the same as any other royalty. It is a right in land, a burden on the mineral interest, and must be paid out of production free of costs. Overriding royalty interests, or overrides for short, can originate in numerous transactions. Often, an override is granted as a fee or additional consideration for some service provided to the mineral lessee, or in connection with the promotion or acquisition of leaseholds from another. For example, a lease broker or promoter may sell a lease or 5

package of leases to an oil company in exchange for a sales price plus a small override. In a situation where the going royalty rate for new leases is one-sixth, someone who owns an older lease with an one-eighth royalty may sell it to another oil company, and pocket the difference between one-sixth and one-eighth (i.e., 1/24th) as an override. Smaller oil companies sometimes set up employee override pools as bonus compensation for their key employees and management. In the good ol days, oil and gas attorneys were often compensated for their services by receiving small overrides on the leases of their clients. Unfortunately for the author, those days were long gone before he joined the practice. An important aspect of an overriding royalty interest is that, because it is typically carved out of the lessee s working interest under a lease, it depends on the continuation of the lease for its existence. If the lease from which it is carved out terminates, then the override terminates. Thus creates the risk for a wash out, by which the lessee can relieve itself of its override burdens by letting the lease lapse, and then taking a new lease from the mineral owner. This can be financially advantageous to the lessee, albeit unfair to the overrides, if the extra bonus or royalty that must be paid for the new lease is less than the overrides that would be washed out. Wash-outs can be prevented by a preservation clause in the conveyance creating the override that stipulates that the override shall attach to any replacement, renewal, or new lease covering the same property. Another issue that can arise with overrides involves co-ownership or joint operations and the question of who is responsible for the override. Typically, the operator pays, out of production, all royalty and override burdens, deducting those burdens from the working interest owners whose interests are burdened by such royalties and overrides. However, sometimes working interest owners may not be entitled to any revenue from a well because they have not contributed their costs, or elected, under a joint operating agreement, not to participate in a certain well. In that case, an override carved out of the non-participating working interest owner s share may not be entitled to share in production until such time, if any, that his working interest owner begins to share. Boldrick v. BTA Oil Producers, No. 11-06-00029-CV, 2007 WL 865811 (Tex. App. Eastland March 22, 2007. Depending on the terms of the conveyance creating the override, the working interest owner who created it may have to pay it out-ofpocket even though the working interest owner is not receiving any well revenue. Id. 3. Nonparticipating Royalty Interest A royalty interest that is created directly out of the mineral estate (or by the landowner of unsevered minerals) is call a nonparticipating royalty. It, like any other royalty, is a right to share in a percentage of any production from the land free of production costs. It is called nonparticipating because the owner has no right to develop, does not participate in the costs of drilling, and does not participate in any bonuses or rentals received by the landowner or mineral owner from leasing. Historically, nonparticipating royalty interests came about in one of two common ways. One was a landowner who wanted to raise some money by selling a royalty to a speculator in minerals. That speculator was not interested in developing the property, but only a royalty right that might, some time later, pay off if the land was leased and a well drilled. Conversely, a landowner who sold his land might reserve a royalty as a hedge against the possibility that the land he was selling would prove, one day, to be productive of minerals. The grant of a nonparticipating royalty diminishes the royalty share that the landowner or mineral estate owner can expect to receive from later leasing the land. For example, if Rancher Brown sells an 1/8th royalty to Speculator Sam then later leases the land to Exxon for a 1/6th royalty, Rancher Brown will only receive a 1/24 royalty in the end; Sam s 1/8th gets paid first, and the balance (1/6 1/8) is only 1/24. Thus, as a practical consequence, there is an upper limit to the total amount of nonparticipating royalty interests that can be granted before a property because unleasable. In today s market, that is probably about 1/4th. An important thing to remember about a nonparticipating royalty interest is that it is perpetual, unless the grant specifies a specific term. It is not uncommon to find lands in Texas that are subject to a nonparticipating royalty granted decades ago Even if the right lay dormant and unused all that time, if an oil company comes today and drills a well on the land burdened by that old, dormant royalty, some great-grandchild of the original owner will suddenly be receiving new found money. F. Executive and Non-Executive Interest The right to lease is called the executive interest. Anyone who owns a mineral interest has the right to lease that interest, and thus holds an executive interest. However the right to lease can be separately granted or reserved from the rest of the mineral estate. This most commonly happens in co-ownership situations. For example, a landowner may sell half of his mineral interest, but retain the sole executive right. Thus, only he can grant a lease and the non-executive is dependent on him to obtain a lease. Severance of the executive right is often sought by the surface owner who, in granting away part of his mineral rights, may want to control the terms and conditions by which his land is leased and the burdens it imposes on his surface uses. Similarly, one who intends to retain the 6

majority of the mineral rights, may want the entire executive right so that he can ensure the terms of any lease and prevent a balky minority owner from obstructing a potential lease. Because the severance of the executive rights leaves the non-executive at the mercy of the executive, courts have imposed duties on the executive to act as a fiduciary toward the non-executive. Traditionally, this means the executive must treat the non-executive fairly and not obtain any benefits from leasing that are not shared with the non-executive; it certain situations, it may also impose an affirmative duty upon the executive to execute a lease for the non-executive s benefit. Lesley v. Veterans Land Bd., 352 S.W.3d 479 (Tex. 2011). G. Net Profits Interest A net profits interest is an interest in production, payable after all costs of production are deducted. Thus, it is a share in net profits only. It is like an overriding royalty in its limitations and its character, and is often created in the same sort of situations that give rise to an override. But, unlike an override, or other royalty, it is not free of costs. Moreover, it is more likely to be granted on a specific well or a group of wells, rather than on entire tract or leasehold. H. Carried Interest A carried interest is like a net profits interest in that it is payable only on profits. A carried interest typically arises in one of two ways. First, it can operate by contract, such as in a promotion situation, where a promoter of a prospect sells a share of it to someone else, who provides all the up-front money. That person fronts the money to drill the prospect, thus carrying the other while he recovers his investment out of the production from the well. Once the well has paid out; that is, has recovered enough money to pay off drilling costs and operating cost to date, the carried interest then begins to share in the net revenue from the well. A common situation is that the carry last until payout, at which time it converts to a regular working interest. Similarly, the carried interest can operate under common law in the case of a co-ownership situation. Under the rules of co-tenancy of mineral interests (discussed further below), each co-owner of a working interest in a well is liable for his share of the costs of the well. Unless the co-owner agrees to participate up front and advance his costs (under a joint operating agreement or other similar contract) the co-owner who does not participate must contribute his costs out of his share of production. He will not be liable directly for those costs if the well is a dry hole or not profitable; rather his contribution will be paid out of production from the well until the well has paid out; at which time, the non-participating owner will be entitled to share the in the subsequent net revenue from the well. I. Production Payment A production payment is simply a conveyance of a certain fixed value of production. Typically, a production payment is used as collateral and a repayment mechanism for financing or to secure credit extended in a sale of oil properties. The owner of the production payment is entitled to specified percentage of production (usually free of costs, like an override), until a certain sum is paid, at which time the interest terminates. J. Wellbore Interests Sometimes a party is assigned or retains an interest only in a single well called a wellbore interest. For example, a lessee may decide to sell a lease that he does not intend to develop further, but wants to retain an interest in the one well he did drill. Accordingly, he will assign the lease and reserve a wellbore interest in the existing well. Although not an uncommon practice, no case had addressed the nature of a wellbore interest until Petro Pro, Ltd. v. Upland Resources., No. 07-05 -0327-CV, 2007 WL 1717178 (Tex. App. Amarillo, June 14, 2007, no pet. h.). The court concluded that a wellbore assignment conveys a determinable fee interest in the oil and gas in place, subject to the physical width and depth of the wellbore at the time of the assignment. This includes the right to use the so much of the surface as is necessary to continue to operate the well. It does not include, however, the right to deepen the well, or to sidetrack the well, or to prevent others from drilling wells nearby and draining the area that could otherwise be drained by the well. IV. CO-OWNERSHIP AND SPLIT INTERESTS Mineral interests can be co-owned, whether at the land, mineral estate, or lease level. It is not unusually for a mineral interest under a tract of land to have dozens (or sometimes hundreds) of co-owners. This is particularly true in Texas where, although there is a natural tendency for split surface ownership to consolidate over time, severed minerals remained severed in perpetuity; and tend to further split over time, with each new group of heirs, assignees, etc. 7

Co-ownership also occurs on the lessee side, where several oil companies might pool together to share the risks of a large project; or combine and pool their lease interests as necessary to meet spacing requirements or achieve economies of scale to profitably develop an area where they have scattered interests. A. The Rights of Cotenants Under general Texas law of cotenancy, any co-owner of real property has a right to use the land as much as any other cotenant. Likewise, in the mineral context, any cotenant of the mineral estate has the legal right to develop or lease the minerals on his own, even without the consent or over the objection of his cotenants. Realistically, a cotenant who owns a minority interest is not going to drill a well on his own. He will have to front all the costs, yet only receive a fraction of the well revenue. Under cotenancy law, every cotenancy is entitled to an accounting for his proportionate share of minerals produced from a well on his interests, subject to his share of costs being deducted from his share of revenue. Although the nonparticipating cotenant pays his share of costs out of production, he takes no risk. All of the risk is on the participating cotenant who will be left paying out of pocket if the well is dry or unprofitable. Likewise, an old company may take leases from any cotenant of a mineral estate, but usually will not undertake the risk of drilling until it has leased all or substantially all of the mineral interests. An oil company can often justify carrying an unleased mineral owner if it is dealing with only a small percent. But an oil company will not usually undertake the risk and costs of drilling if it only has 50% of the mineral interests leased. Even if they do not sign a lease, the other cotenants can ratify a lease purporting to cover their lands, either by an express document to that effect, or tacitly, by accepting royalty payments or other lease benefits. B. Partition The mineral estate, as a real possessory right, can be partitioned under the same rules generally applicable to other real property interests. The mineral estate can be partitioned in kind, with each co-owner receiving a designated tract, or it can be partitioned by sale. Commonly, co-owners, such as related family members, will partition the surface in kind, while maintain undivided ownership of the minerals underneath. This type of partition essentially operates as a severance of the mineral estate creating separate surface tracts owned separately by each individual, each subject to a single mineral estate co-owned by all of the parties. This type of partition has many advantages, the chief of which is fairness and family harmony, because should oil or gas be later discovered, all will share regardless of what tract it is produced from. Judicial partition is available if consent cannot be obtained for a voluntary partition, and minerals interests can be partitioned whether or not they have been severed from the surface. Texas Property Code 23.001; Moseley v. Hearrell, 171 S.W.2d 337 (Tex. 1943). Mineral interests can also be partitioned even if they are subject to an existing lease; however, the partition will not split the lease, such that the lessee would have to satisfy his drilling and other obligations separately as to each tract. Garza v. DeMontalvo, 147 Tex. 525, 217 S.W.2d 988 (1949). C. Life Estates A life estate can be granted in minerals. The rules governing the relationship between the life tenant and the remainderman are, in concept, the same as any other life estate in property. However, because of the unique aspects of mineral rights, particularly those subject to a mineral lease, some special issues arise. The life tenant has the right of occupancy and use, but not the right to dispose of the property. In regard to the mineral estate, the life tenant does not have the right to develop and produce, which would be considered a disposition or waste of the property. Thus, the life tenant is not authorized to grant a mineral lease. Conversely, the remainderman has no authority to lease either, during the existence of the life tenancy, because he cannot alienate property subject to a life estate. Accordingly, absent a special trust or other agreement providing for authority to lease, the agreement of both the life tenant and the remainderman is required to grant a lease. The issue is further complicated if a lease is granted over the property. Although a life tenant is normally entitled to the income generated by the property, in the mineral lease context, the bonus and the royalties are considered proceeds from the disposition of the property, not income. Andrews v. Brown, 283 S.W. 288 (Tex. Civ. App. Austin 1926), aff d 10 S.W.2d 707 (Tex. Comm n App. 1928); Stephens v. Stephens, 292 S.W. 290 (Tex. Civ. App. Amarillo 1927, writ dism d w.o.j.). Only the delay rentals, if any, or considered income. Commissioner v. Wilson, 76 F.2d 766 (5th Cir. 1935). Thus, absent a contrary agreement to the disposition of these proceeds, the life tenant will be entitled only to the delay rentals and the remainderman will be entitled to the bonus and royalties. However, the remainderman, although entitled to the funds, cannot use them; rather, the life tenant is entitled to possession of the funds and the right to any interest or income generated by the funds. Davis v. Bond, 158 S.W.2d 297 (Tex. 1942). Courts can administer the funds, or appoint a receiver, in case of a conflict and to protect the interests of both the life tenant and the remainderman. Enserch Exploration, Inc. v. Wimmer, 718 S.W.2d 308 (Tex. 8

Civ. App. Amarillo 1986, writ ref d n.r.e.). The most practical method to handle a life estate in mineral is through a trust agreement, which authorizes the trustee to lease and manage the proceeds for the benefit of the life tenant. One important exception to these rules is the open mine doctrine. It applies to oil and gas wells that were in existence at the time the life estate was created. Under this doctrine, royalties from an open mine are considered "income" from the property intended for the benefit of the life tenant. Youngman v. Shular, 288 S.W.2d 494 (Tex. 1956). D. Dealing in Fractional Interests 1. Division of Interests NWI and NRI Because mineral interests are often severed and divided multiple times, clear understanding of the allocation of interests is essential to the operator planning to drill a well. Operators obtain title opinions to confirm the interests in the properties they plan to acquire and develop. Operators often additionally obtain a drillsite title opinion for each individual well they intend to drill to verify the interest allocation unique to that well. The confirmation of title is necessary to prepare a division of interest ( DOI ), which is a document used by the operator to list all of the interests in the well, by decimal amount and the type of interest (cost-bearing, non-cost-bearing) and to instruct its accounting department for invoicing of well costs and remittances of well revenues. The DOI lists all Net Working Interests (NWI). The total of all NWI should equal 100%. These fractions are used by the operator to charge well costs to the working interest owners. The DOI will also list all the Net Revenue Interests (NRI). This is the total all participants working interests, royalty, overrides, etc. with their respective decimal share in revenue. A simple example is shown below. Assume Alpha Oil Company and Beta Oil Company each own 50% of the leasehold under a lease with a 1/5th (20%) royalty in favor of Larry and Lucy Landowners equally. The listing of NWI and NRI would look like this: Name NWI NRI Alpha Oil Company.50.40 Beta Oil Company.50.40 Larry Landowner.10 Lucy Landowner.10 1.00 1.00 Note that, for the working interest owners, the total royalty (.20) is deducted proportionately from their NWI to get their NRI. That is why royalty and overrides are called a burden on the working interest, because it is paid out of their interest and reduces their revenue interest. For oil companies looking to buy existing leases, one of the first thing they consider is the total royalty and overriding royalty that burdens the working interest. 2. Grants and Reservations Reservations and exceptions in mineral conveyances, along with grants subject to prior conveyances, are a fertile source of confusion, litigation, and ambiguity. The problems arise in a myriad set of circumstances, all of which reflect the fact that mineral interests are commonly divided and fractionalized. Most of these potential problems can be avoided by careful drafting and a little appreciation for math. Nevertheless, ambiguities can creep in by inconsistent use of terms, the difficulties inherent in defining fractional interests, awkward placement of exceptions, and the unintentional consequences of commonly used (but often misunderstood) drafting conventions. Assignment of a fractional interest, reserving to the grantor the remaining fraction, can be accomplished in many ways. The most straightforward method is to simply describe in the granting or property description clauses, or by combination of both, the specific fractional interest to be conveyed to the grantee. Whatever is excluded from the grant remains in the Grantor. Assume the following example. Able owns 100% of the surface and 50% of the minerals in land described as Section 12. How might Able effectively convey 1/2 of everything he owns (or 50% of the surface and 25% of the minerals) to Baker, reserving the balance to himself? Ex. 1: Grantor grants an undivided ½ interest in the surface and undivided ¼ interest in the minerals on or under the following described land: Section 12 of. Ex. 2: Grantor grants an undivided ½ interest in all of Grantor s right, title, and interest, in the following described land: Section 12 of. 9

Ex. 3: Grantor grants conveys and an undivided ½ interest in the following described property: The entirety of the surface and an undivided ½ interest in the minerals on or under Section 12 of. Each of the above examples is sufficient in accomplishing the same thing the transfer of one-half of Able s interest, such that Baker receives 50% of the surface rights and 25% of the mineral rights. However, in the author's opinion Examples 1 and 3 are preferable because they unequivocably describe exactly what is conveyed. While Example 2 is workable, the specific fraction conveyed can be ascertained only be examination of Grantor's title (to determine the extent of his title). Also, Example 3 may not be a sufficiently certain grant to support a warranty claim, since it does not purport to state what exactly grantor owns. By common convention, fractional conveyances can also be made using exception or reservation clauses. An example of such a reservation might be: Grantor grants the following described land: Section 12 of. Less and except an undivided ½ of the minerals on or under said land, which are reserved by Grantor herein. A number of cases involve the apparent ambiguity of whether a reservation or exception is intended to withhold the minerals or a fraction thereof in favor of the grantor, or is intended merely to relieve the grantor from liability under warranty for previously conveyed or severed minerals. This ambiguity can arise if the exception is located following the warranty language, does not contain clear language that the excepted mineral interest is being reserved in favor of the grantor, or is expressed in relation to an exception or reservation in a prior deed. Such ambiguities can be resolved by clearly stating that the excepted mineral interest is being reserved in favor of the Grantor. 3. Double Fractions Problems can arise in conveying fractional interests out of a fractional interest if the granting or property description language is not carefully drafted or is inconsistent. Commonly, these problems can arise in the conveyancing of nonparticipating interest, such as overrides, out of the lessee s interest. The problem can arise, however, in any situation where the interest conveyed is a fraction of a fraction. For example, assume a lessee of a 50% working interest in a lease covering the entirety of Blackacre, with a 1/8th royalty in favor of the lessor. The lessee desires to grant a 2% overriding royalty in favor of A. How can this be accurately described: Ex 1. grants an undivided 2% overriding royalty in all minerals on and under Blackacre This grant conveys the correct quantum 2% but, the lessee does not own all the minerals (only 50% of the leasehold), and may be concerned about breaching an implied warranty by purporting to burden minerals he does not own. Ex. 2. grants an undivided 2% overriding royalty interest in grantor s undivided 50% leasehold interest in Blackacre. The problem with this grant is that it probably grants A only 2% of 50% of 7/8ths not the entire 2% intended, because the grant is described as 2% of the lessor s interest, rather than 2% of the 8/8ths (i.e., the total interest). A better solution would be to describe the grant as follows: Ex. 3. grants an undivided 2% overriding royalty interest in 8/8ths of gross production, payable out of Grantor s 50% leasehold interest in Blackacre. In Texas, courts have concludedthat a grant of 1/4 of 1/2 means 1/8 of the 8/8ths, while the grant of 1/4 out of 1/2 means 1/4 of the 8/8ths, payable out of the grantor's 1/2. Likewise, a grant of 1/8th of royalty, means 1/8th of the royalty fraction (or 1/64th of gross production, in cases of a 1/8th royalty). However, a grant of 1/8th royalty or 1/8th out of royalty means 1/8th of gross production. In short, the word of means to reduce by multiplying the two fractions, whereas the words out of means the total amount, to be subtracted out of the grantor's interest. Very small word differences can mean very big economic differences. 10

In conveying fractional working interests, it is often helpful to describe both the working interest and the net revenue interest that is being conveyed out of the total 8/8ths this avoids any ambiguity as to whether the fraction conveyed is a fraction of the entire mineral estate or a fraction of the leasehold or working interest, net of the lessor s royalty and other pre-existing overrides. V. OTHER CONTRACTUAL AND CONTINGENT INTERESTS A. JOAs, Participation, and AMI Agreements As mentioned, lessees often combine their interests under agreements to jointly participate in the development of a prospect area, which may include several leases, either presently owned or to be obtained in the future. the parties may enter into a participation agreement, an Area of Mutual Interest (AMI) agreement, or a Joint Operating Agreement, or some sequence of these agreements. These agreements will provide for how the parties intend to combine their interests, what rights and obligations they have in relationship to the leases to be jointly developed within the area of mutual interest, and may contemplate the execution of future cross-conveyances among the parties as the properties are developed. Such agreements therefore may give rise to options or future contingent interests. For example, a common AMI provision is that, if any party acquires a lease in the AMI area, all other parties have a right (or obligation) to receive an assignment of their proportionate share of that lease. The JOA, specifically, is concerned with the terms of the joint operation of co-owned or contributed leases. One party is designated as the Operator, who will manage the physical and accounting operations of the joint operation, and the other parties are considered the Non-Operators. The JOA will specify the terms by which the participants must contribute to the costs of the joint operations, how they will share revenues, and what rights they have to decide what wells and other operations are to be conducted. JOA s commonly provide that each party must affirmatively elect to participate in each proposed well, or may have the right to elect to not participate in subsequent wells to go non-consent. Typically, a party who goes non-consent in a proposed well forfeits his interest in the well, until a multiple (perhaps 200% - 400%) of the well costs are recovered out of revenue. Note how this compares to the common law rule, under which a non-participating co-owner must contribute, out of his revenue, only 100% of his costs. The purpose of the penalty provision, therefore, is to additionally compensate the participating owners who bear all of the risk of a dry hole and to encourage all non-operators to share in the up-front risk. B. Farmouts In a farmout, a lease owner that is not currently interested in drilling a property contingently assigns the lease or a portion of the lease to another party that wants to drill it. Young Refining Corp. v. Pennzoil Co., 46 S.W.3d 380, 389 (Tex. App. Houston [1st Dist.] 2001). The farmout agreement obligates the assignee to drill one or more wells on the tract to a certain depth or in accordance with set conditions within a specified amount of time in order to earn the contingent interest. The assignor may reserve a fractional share of the working interest, an overriding royalty, or a production payment in the lease upon assignment. If an overriding royalty interest is retained, it may be convertible to a working interest at some point in time upon the occurrence of certain conditions, i.e., payout of the well. Farmouts serve many purposes, including allowing a lessee with a soon-to-be-expiring lease to prevent lease termination by allowing another party to commence timely drilling operations. Similarly, a lessee with a lease that is being drained by operations on neighboring properties may enter into a farmout to expedite the drilling of an offset well. Farmouts may also be used in circumstances involving a marginal property to assign all or part of the acreage to another company that is willing to drill and accept a lower profit margin than the farmor requires. From a farmee s perspective, a farmout may be the easiest or only way to obtain acreage in a given area or the farmee may just view the prospect differently than the farmor. Often farmouts are used simply as a mechanism to allocate and spread risk among companies with respect to drilling operations. A farmout can be structured in a variety of ways, but often a farmee will receive the rights to earn the entire working interest in the drilling unit acreage and a percentage working interest in additional acreage adjacent to the drilling site. It is typical for the farmee to negotiate for acreage in addition to the drilling site acreage because of the risks being undertaken to develop the property, which may even extend to acreage subsequently obtained by the farmor through inclusion of an area of mutual interest provision. The farmee has no legal interest upon commencement of drilling and earns such rights only upon completion of a well or wells according to the terms of the farmout. To the extent that a farmout with a retained non-operating interest allows the grantor to convert it to a working interest of a specified amount at a later date, it is called a back-in. A back-in generally occurs when a set amount of costs have been recovered from production, i.e., payout of the well or wells drilled by the farmee. 11

VI. CONCLUSION AND FURTHER READING Oil and gas law is well developed and described in Texas. This primer touches only on the highlights. For further reading, the author recommends three particularly sources as good general references on oil and gas law: ERNEST E. SMITH & JACQUELINE LANG WEAVER, TEXAS LAW OF OIL AND GAS. This is an excellent three volume treatise focusing on Texas oil and gas law. Professors Smith and Weaver are the two experts in this area. WILLIAMS & MEYERS OIL AND GAS LAW (Patrick H. Martin & Bruce M. Kramer eds.) This is a multiple edition treatise, regularly updated, that is the go-to source for courts and practitioners. It comprehensively covers all issues in oil and gas law across all jurisdictions, with extensive case references. Often, all of one's answers for a difficult problem can be answered from Williams and Meyers. WILLIAMS & MEYERS, MANUAL OF OIL AND GAS TERMS. The last volume of the Williams and Meyers treatise, the Manual is also available as a separate one volume desk reference. It is an great quick reference containing definitions, brief explanations, and case references for essential oil and gas terms a good starting point for someone trying to figure out where to start. 12