II. UNCONVENTIONAL VS CONVENTIONAL RESERVOIRS
IV. NEED TO KNOW TERMINOLOGY AND VALUE METRICS
V. OPTIONS IN STRUCTURING THE SALE OF MINERAL RIGHTS
VI. PROS AND CONS OF SELLING A MINERAL RIGHT VS SELLING A ROYALTY INTEREST
FUNDAMENTALS OF LEASING AND SELLING MINERALS
The following is intended to give mineral owners an idea of how minerals are valued and how they are commonly leased and sold. The comments are purposely general in nature as the subject is fairly complex, details regarding size and location of mineral ownership vary widely and those variations are critical to determining value. Anyone considering the sale of minerals should seek the professional assistance of a landman or attorney experienced in the leasing and sale of mineral interests and familiar with the exploration and production history and current activity in the region where the minerals are located.
Generally speaking minerals have value based upon the perceptions of buyers. Those perceptions can be based on facts available in the public record, production history of wells near the area of the buyer's interest, personal interpretations of geology, respect for a particular Exploration and Production (E&P) company, publicity generated by stock analysts and energy bloggers, or a hunch, to name but a few factors. In my experience rarely does an offer come from a person or company that has privileged information from inside an energy company though some E&P companies may buy minerals in units they operate. Proprietary information is tightly held and unavailable to the majority of buyers and brokers. Buyer perception of value changes over time based on actual unitization, drilling, completion and production results, variations in the price of the hydrocarbons produced and calculations regarding risk and rate of return comparisons between established and emerging domestic plays. The fact that an E&P company spends millions or tens of millions of dollars leasing lands, building infrastructure and drilling wells is often interpreted by mineral owners as an indication that a particular geologic target is a guaranteed successful play. The reality is that the average E&P company is constantly generating new prospects with the knowledge that some will prove economic and some will not. Even the largest companies with decades of experience, command of the latest technological tools and world class intellectual talent backed by capital budgets in the billions of dollars probably have historic success rates in the 50% range.
Early in an emerging play there is little definitive information available to the public and the energy company or companies are basing their lease program off of limited data that they have interpreted to indicate potential but that cannot be a definitive indicator of success. Energy companies will sometimes use the term, well control, when referring to the cores and logs from existing historic wells penetrating their target formation. Some prospective formations or zones may have extensive well control because many wells have been drilled through the target prospect over time. The more recent the better owing to the ever advancing nature of technology. Some prospects will have little well control owing to depth and historic cost to drill deep formations which were not commercial under prior technical limitations. Although well control is of obvious value only the drill bit can prove a formation commercial and define its areal commercial extent.
UNCONVENTIONAL VS CONVENTIONAL RESERVOIRS
Major and mid-major energy companies have shifted their onshore exploration focus heavily to unconventional reservoirs over the last couple of decades. Historically hydrocarbons had been almost exclusively produced from conventional reservoirs where the properties of a formation (reservoir rock) allowed the migration of hydrocarbons over extended distances to a well bore. Discussions of the ability of a formation to allow that migration primarily include two properties, porosity and permeability. Porosity is the space between the grains of rock. The larger the pore space, the more hydrocarbon the rock can hold. Permeability is the measure of how connected those pores are one to the other throughout the formation. The better the connection, the more efficiently the hydrocarbon can flow through the formation over distance to a well bore. Conventional reservoirs have been successfully developed for one hundred years with vertical wells because of good porosity and permeability. Advancing technology (3D seismic, horizontal drilling and hydraulic fracture stimulation) now make it possible to produce hydrocarbons from unconventional reservoirs (source rock) that does not exhibit high degrees of porosity and permeability. Hydrocarbons cannot flow to a well bore by natural means in an unconventional reservoir. They are locked into the formation (low permeability) incapable of flowing over distance without the creation of artificial fractures to connect the reservoir to a well bore.
Much of the exploration and production that is discussed on GHS falls into the unconventional reservoir category. Indeed the website came into being because Keith's family was offered a lease in the early days of the emerging Haynesville Shale Play and he could not find any useful information through a search of the Internet. His response to their need to know was the creation of GoHaynesvilleShale.com. The general characteristic of an unconventional reservoir most pertinent to this blog is the fact that they are somewhat uniform in productive viability over large areas. Conventional reservoirs are accumulations of hydrocarbons that have migrated to an area where they are trapped and therefore are not generally productive over a wide expanse but are discrete, separate productive areas of limited size. For energy companies, an unconventional reservoir offers the possibility of repeatable productivity over a wide area that lends itself to economies of scale in development. In other words, low risk of dry holes with the opportunity to leverage operational efficiencies to drive down the cost to produce an mcf (one thousand cubic feet) of natural gas, a barrel of Natural Gas Liquids (NGLs)/condensate or a barrel of oil. Articles on the subject of unconventional reservoirs often use the analogy that development is more akin to manufacturing models than to traditional exploration and production of conventional reservoirs.
How energy companies approach the leasing and development of unconventional prospects should be understood when considering an offer to lease. A mineral owner has no control over the location of their mineral interest. They do have some level of control over the terms of the lease they execute. That control varies by the laws and regulations of the state where the minerals are located. The terms of a lease have direct and significant impact on the value of the underlying minerals. A buyer considers both location related data and lease terms. The royalty provision and other key lease clauses can significantly increase the value of a mineral interest.
The first indications of interest by the energy industry in a particular area are usually shared stories of lease offers. Those offers are made by landmen who work for a land company that represents a client. The client may be an energy company intending to drill wells (an operating company), an energy company that specializes in acquiring acreage with the intent to invest in wells drilled by an operating company (a working interest) or a company or individual who wishes to sell leases to a third party for a profit (speculative investor). It is common practice in the industry for a company to use one or more land companies to acquire leases in their name. The leases will be assigned by the land company to the client company at some future date.
No company, even major and mid-major E&P companies, employs the numbers of landmen required to take leases for an unconventional prospect that may cover hundreds of thousands of acres. Land companies are in the business of supplying the labor required to identify mineral owners, determine how to contact them and make the lease offers. Land companies maintain business relationships with as many energy companies as possible and the bulk of the landmen they employ work on day rates. They are contractors and are not guaranteed continuous employment. Landmen spend a lot of time looking for work and often travel considerable distances to work a project. The land department of the client company will provide the land company with the area to be leased and the terms to be offered. The client company does not provide the land company with the particulars of their development plans beyond the bare basics and specifies the lease and memorandum of lease forms to be used. The landmen employed by the land company are privy to even less information about the client company and its intentions. They usually have only a narrow scope of authority to negotiate lease terms and must clear anything beyond those terms with their employer. It is the intent of the landman and his employer to do as little negotiating as possible. Their job is to acquire leases for the assigned acreage at the approved terms as quickly and as quietly as possible.
The relationship between client, land company and landman is a practical reflection of the business needs of the energy industry. That relationship functions to provide the energy company with the opportunity to explore and produce hydrocarbons for a profit. Mineral owners should have a general grasp of this process and fully understand that although a lease represents the opportunity to monetize an asset otherwise beyond their reach, it is a legally binding business transaction that requires their due diligence as to terms. It is the responsibility of the mineral owner to decide what is acceptable either independently or through the assistance of qualified professionals. A lease agreement can remain in force for decades and generations of owners. No mineral owner should expect a landman or land company to look out for their best interests.
As leasing efforts progress the land company will begin to record leases or memorandums of lease in the public record for the county or parish. Documents recorded with the Clerk of Court are available for review by the general public. Some Clerks of Court provide remote access to their records by computer. Those scanned documents do not cover the entirety of the public records but usually include instruments filed over the last couple of decades. A recorded lease will include all the terms except the bonus payment. A Memorandum of Lease will generally only reference the name of the lessor (mineral owner) and the lessee (company taking the lease), a legal description of the lands covered by the lease and the length of time the lease is effective. A Paid Up lease will include a bonus payment for a specific primary term, typically three to five years, and may include an option for the lessee to extend the length of the primary term for additional years based upon payment of a specific amount of money prior to expiration of the primary term.
The usual progression of lease offers in an area follows a pattern. The first mineral owners to be approached are generally those with larger mineral interests. It makes sense to acquire as much acreage as possible in the early stages of leasing. The offers made are "opening offers" to get feedback as to what terms will be required to lease the targeted acreage. By leasing the larger mineral tracts across the target area a company effectively limits the possibility for competition. Energy companies that operate (drill wells) are focused on leasing acreage where they can drill. Although it is an unavoidable consequence of staking out a land position where two or more companies are acquiring leasehold operating companies generally don't wish to lease where a competitor has already acquired the majority of mineral acres. The most advantageous situation for mineral owners is when two or more companies begin competing for leases in a given area early in an emerging prospect. Eventually one company will win that contest and then the others will normally cease to offer leases there and shift their focus elsewhere in the prospective area.
As leasing progresses exploration follows. When an operating company is preparing to drill an area they will generally form drilling units and seek to lease the smaller previously unleased tracts. An application will be made to state regulators for a specifically defined surface area and depth definition for drilling & production units with a designated operator. The most common unit type is compulsory meaning that the state uses its authority under statute to compel all the mineral interests within that unit boundary to participate, to varying extents, in the development of the designated formation/zone. Each state uses variations in language to describe this process and common phrases are Force Pooling and Compulsory Integration. The rationale behind compelling parties to cooperate to allow for development of mineral resources is derived from the desire of mineral owners to monetize their asset and the state to generate revenue and incentivize the creation of jobs and stimulate economic growth. Without compulsory unitization of mineral ownership the whole process of acquiring the rights to drill and produce hydrocarbons would be difficult and in many cases insufficiently profitable for any company to make the required investment. Each state makes their own laws and regulations concerning the exploration and production of minerals and those laws and regulations as they pertain to compulsory unitization vary, sometimes significantly so. When negotiating a lease it is important to understand the specifics of unitization statutes. When the operator of an established unit cannot reach an agreement with a mineral owner they may choose to force pool those minerals and thereby have the right to produce those minerals through the authority vested in the state. In the vast majority of cases an operator prefers to have minerals in their unit under lease. Under some state regulations the unit operator recovers only their development costs and realizes no profit from minerals force pooled (Louisiana) or receives some profit limited by way of risk penalties set by the state (Texas, Arkansas and Mississippi). The specifics of risk penalties may vary depending on whether the interest force pooled is an individual mineral owner or a party holding a mineral lease or other mineral right. In Louisiana mineral law unleased and force pooled mineral owners are treated differently than companies, other than the operator, holding leases within a unit. Those non-operating companies are defined as Working Interests and are required to pay their share of the development costs or incur risk penalties set by state law. Unleased mineral owners are not required to pay their proportional share of costs out of pocket however the unit operator is not required to pay them until the well has reached payout. After the well has generated revenue sufficient to recover it's cost to drill and complete the operator is required to pay the unleased mineral owner 100% of their proportional share of unit production subject only to deductions for monthly lease operating expenses (LOE).
Lessors of mineral interests that are leased and included in a compulsory drilling unit receive royalty payments from any and all wells producing minerals within the unit boundary regardless of the surface location of the wells. That participation is based on two facts: the percentage of the total unit acres represented by any given tract; and the royalty percentage contained in the lease for that tract. For example, a ten acre tract in a one thousand acre drilling unit would represent a 1% ownership interest in the whole. The royalty percentage for that 1% determines the net mineral interest owned in unit production. To calculate a net mineral interest, the 0.01 interest is multiplied by the royalty fraction. If the royalty was one-fifth (20%) then, 0.01 X 0.20 = 0.002 and the royalty owner would receive payment based upon two thousandths of the income generated by unit production subject to applicable deductions. Some deductions, such as severance tax, are set by the state while other deductions are covered by lease terms and the interpretation of lease language by state courts. Post-production costs deducted from royalty payments cause a lot of controversy. To avoid this a lessor should negotiate a cost-free royalty clause in his lease whenever possible.
Mineral owners with modest to small acreage tracts often become concerned when they are not approached in the same time frame as neighbors with larger land holdings. Those who understand the leasing process will practice patience and wait to be contacted by the land company handling leasing in their area. As long as the public record contains up to date and accurate evidence of their mineral ownership interest the land company will find them. Those who panic and approach the land company may or may not receive an offer to lease but if they do it is, more often than not, the same as the opening offer. As leasing progresses and becomes more widely known publicly and/or competition from other companies materializes it is very common for lease offers to improve. Where early opening offers are for a one fifth royalty later offers may be for nine fortieths (22.5 %) or a quarter (25%). Particularly in the advent of competition for leases and/or public announcements of successful early wells, bonus offers may increase also.
Now the question of risk becomes important to mineral owners considering an offer or offers to lease. Not all leasing efforts continue to the point of exploration or production. It is not uncommon for leasing to cease for many reasons mostly beyond the understanding of mineral owners. If early exploration wells experience insurmountable mechanical problems or production is insufficient to meet internal corporate rate of return models those are obvious reasons to stop offering new leases. However there can be other reasons that no one can see coming or anticipate. In those cases only those who leased early will benefit from the lease bonuses. However in the opposite scenario development success will provide financial advantages for those who lease at a later date. As it is common for production from successful exploration and production efforts to last for many years, indeed quite often decades, the bonus payment soon loses significance compared to the royalty in a lease. The difference in payments between a one fifth royalty and a nine fortieths or one quarter royalty to a mineral lessor projected over the course of multiple unit wells and a couple of decades can be quite large. Most leasing professionals would likely agree that the bonus is the least important term and would follow in importance not only the royalty fraction but a list of beneficial and protective lease terms dealing with surface use, royalty cost deductions, pooling limitations, depth limitations and shut in payments, to name but a few.
NEED TO KNOW TERMINOLOGY AND VALUE METRICS
In order to make informed decisions concerning leasing and selling minerals it is helpful to understand what you own and how you own it. It may seem strange but a large percentage of mineral owners do not know what they own. The legal concept of severing the mineral estate from the surface estate did not come into practice until the early twentieth century when the exploration and production of oil spread across the nation. Some areas of the country did not experience exploration and production until the mid to late twentieth century and some areas long thought to be non-commercial are proving otherwise in the twenty-first century. The ownership of both estates is said to be ownership in fee. Once the potential value of minerals became clear the sale and trading of mineral and royalty rights became relatively common in areas of successful production or sheer speculation. Thereafter mineral rights were often severed and no longer owned in fee.
It is common for ownership of minerals to be shared by multiple owners. When an individual owns a fraction of the whole they are said to own an undivided interest. For example, four owners with equal interests in a 40 acre tract are said to own an undivided interest in one quarter of each acre. Another common way to express this is that each owner owns 10 net mineral acres. It is common practice for lease forms to contain the gross acreage of a master tract, (e.g. 40 acres) instead of the net mineral acre total for each undivided ownership interest (10 acres). For that reason if the four owners were to all lease their interest in the 40 gross acre tract they would execute lease forms giving a legal description of the tract as 40 acres even though their individual interest was one quarter or 10 net mineral acres. The simplest way to calculate what the company offering the lease thinks you own is to find out the dollar amount of the bonus per acre and then to divide the bonus payment by the per acre amount. If the bonus per acre was $200 and your bonus check was for $400 then the land company would have calculated that you own two net mineral acres of the 40 gross acre tract. An owner of an undivided interest may act independently of the other owners to lease and receive a bonus or to sell their mineral right or a royalty interest.
In states that allow severance of the mineral estate from the surface estate in perpetuity it is quite common for gross tracts to have many owners due to the handing down of family ownership over generations. In many cases those heirs are unaware that they own the mineral interest owing to the fact that it may never have been leased and that no taxes are levied on non-producing minerals (how minerals are taxed varies by state). Their first recognition of that ownership interest is often when they are contacted by a landman offering a lease. Undivided ownership may also come about by the sale of a portion of the mineral right as opposed to ownership handed down within a family. Between sales of mineral interests and the passing of ownership by will or forced heirship laws a 40 acre tract of land could have many owners each having a small fraction of the whole and it is not unusual for the surface owner to have no ownership in the mineral estate.
Louisiana mineral law is different from most other states in that the severance of the two estates in perpetuity is not allowed. The sale of Louisiana minerals results in the creation of a mineral servitude (the right to explore for and produce minerals) that is governed by a ten year prescription period. The ten year period begins the day a mineral servitude is created. At the end of the ten years the mineral right would return to the current surface owner if there is no good faith effort to produce (drill a well meeting state standards). If a productive well is completed the prescription period is suspended and begins anew from day one on the date that the production ceases. If a well meeting the standards is drilled and is not productive that act resets the ten year period which begins again from day one that the well is plugged and abandoned. A mineral servitude may be created with an effective period of less than ten years but cannot be greater than ten. This is a simplified definition and mineral servitudes can be quite complex and subject to a number of exceptions and conditions. Servitude owners should seek counsel from professionals with extensive experience in servitude statutes and legal precedents.
Researching mineral title is complicated and requires experience. In states where the two estates may be severed in perpetuity running title is especially time consuming and costly. For this reason a client company dictates the level of due diligence that a land company will employ in order to offer a lease. It is common practice in the industry to perform a limited amount of due diligence during the leasing process. This is because it is a considerable expense that is wasted if a well drilled under those leases is dry or sub-economic and not produced. If the well is economic then the client will conduct a full blown title review in preparation for paying out royalties. That review will result in a Division Order that specifies who will be paid and calculates the net mineral interest for each royalty recipient. Division Order reviews may include new surveys of each tract in a unit and those surveys may not correspond exactly with older or original surveys. For example a tract surveyed in the early twentieth century may be found to be of a different size with the more modern technology/methods used in a new survey. Once a Division Order is completed each royalty interest will receive a document stating their specific decimal interest and requesting personal information for tax purposes. When mineral owners approve their decimal interest and provide that personal information they are said to be "in pay" and will begin to receive monthly checks and statements. Mineral lessors should keep originals or copies of all documents pertinent to their lease, division order and royalty payments in a permanent file along with the contact information for their operator and/or lessee.
There is an additional term and concept that should be mentioned although it will not come up in lease negotiations nor in the payment of royalty. Those in the business of buying, selling and brokering minerals often use the term, royalty acre. In addition to mineral ownership having a net mineral interest, leased minerals will have a royalty acre total based on the royalty fraction contained in the lease agreement. Early leases commonly carried a one eighth royalty. Royalty fractions now are quite varied generally ranging from one eighth to one quarter with leases in unconventional plays normally commanding one fifth to one quarter. All else being equal, a lease with a higher royalty has greater value to a buyer. A royalty acre is one net mineral acre at a one eighth royalty fraction. Therefore our 40 acre tract leased at one eighth is 40 royalty acres. 64 royalty acres if leased at one fifth. And 80 royalty acres if leased at one quarter. To calculate royalty acres divide the royalty fraction in the lease by 0.125 (one eighth). The calculation for a one fifth royalty would be: 0.20 divided by 0.125 = 1.6. Each net mineral acre under that lease would equal 1.6 royalty acres. The concept of mineral value based upon royalty acre should be an important consideration when negotiating a lease and deciding which lease terms are most important.
OPTIONS IN STRUCTURING THE SALE OF MINERAL RIGHTS
Minerals are classified generally as producing and non-producing. Non-producing minerals may be leased or un-leased. Depending on the particular combination of categories there are associated variables that are considered in a value calculation. There are also varying business models employed by brokers and buyers of minerals to identify willing sellers.
The universe of buyers for non-producing, un-leased minerals is relatively small. This is largely due to geologic risk, high capital requirements and uncertainties regarding the time to realize a return on investment. The buyers who have acquisition strategies targeting this class of mineral interest are often large, well capitalized companies that specialize in acquiring large acreage positions. For that reason their strategy may not include modest to small acreage tracts and they rarely send mass mailings to mineral owners of record. Some independent energy companies have business models where they develop a geologic prospect, acquire a core lease block and promote the prospect to operating companies.
The universe of buyers for leased, non-producing minerals is larger and more diverse. When leases or memorandums of lease begin to be recorded in the public record they become a readily available and somewhat vetted source of contact information. Although a lease provides greater detail as to terms than a memorandum both contain the key information that can be used to build a mailing list. All that is required is the name of the lessor, their mailing address and the legal description of the lands leased. As mentioned earlier a land company will perform the research required to identify the individual mineral owners through conveyance instruments in the public record. Although not a full title review that work is sufficient to give a degree of confidence that the lessor on the lease indeed holds some undefined ownership interest in the mineral tract. There are other less accurate sources from which to source contact information such as Interested Party lists which are part of drilling unit applications and local tax records.
Once a company has the information required to make a mass mailing the question becomes how they choose to structure the offer. Some use overly vague and purposely misleading language and send hundreds of thousands of letters with little seeming thought to the location and prospective nature of the mineral interest. The bulk of mail offers are short on detail, especially an actual dollar amount per acre, and represent a fishing expedition for interested sellers. A return response usually results in a negotiation that is intended to determine the lowest price acceptable to the seller. It is not unusual that when a company making such an offer actually does some research on the specific location of the minerals they will decide to decline to make a specific dollar offer because the facts turn out to be less than acceptable based on the acquisition model. There is nothing illegal or inherently unethical about making unsolicited offers to buy or broker minerals by mail.
Websites are the new means to find interested mineral sellers. Perform an Internet search and you will get an idea of just how many are currently active. Obviously this avoids the need to do any research for contact purposes but it does create a huge challenge for the manpower and overhead to process large numbers of contacts not to mention the research that would be required to actually make a fair market offer through some reasonable level of due diligence on minerals scattered across the United States. In my opinion both approaches are based on generating a large number of potential deals and making enough, off the few that actually result in a sale, that will cover overhead and generate a net profit. For those reasons I have my doubts that Internet offers generally represent what most would consider to be a fair market offer.
So how does an interested seller go about vetting mineral acquisition companies and generating multiple offers for comparison? Those that have a trusted banker or attorney may be able to get referrals to local individuals or companies that broker or buy minerals. In my opinion the odds of receiving a fair market offer are improved by dealing with those who are most likely to be familiar with the mineral history and any current relevant activity in the proximity of the mineral interest. With a firm offer in hand it is possible to judge if one or more website mineral companies are willing to make a competitive offer or to counter an offer received by mail. Sellers would do well to disregard claims by any broker or buyer that they always make the best offer.
Those individuals or companies that acquire mineral interests are often characterized as either wholesale or retail buyers. Wholesale buyers generate their own prospects based on their acquisition strategy. They negotiate the price and provide a purchase and sales agreement. Although there is no middle man (broker) involved in a wholesale transaction there is no guarantee that the offer is the best available. Retail buyers utilize brokers and expect to pay for the services they provide. Brokers will use an option contract to define the specific terms of a sale. The option has an effective period during which the seller can take no actions to burden or convey the mineral interest and is binding on the seller for a buyer who will fulfill the terms of the option within the effective period. Option contracts serve to work out all the terms of a sale in advance and provide a reasonable period for a broker to perform title review, assemble a buyer preview to provide facts that bolster the option price, contact multiple buyers, get a commitment and make closing arrangements. Sellers, in this case called optionors, are not bound to accept any sale that does not conform to the terms of the option. If the broker fails to find a buyer at the agreed upon price then the option will expire and the mineral owner is free to consider other offers. It is not uncommon for a buyer to make a counter offer through the broker that the seller may choose to accept but is not compelled to do so. Many buyers prefer to focus acquisitions on minerals offered for sale through an option contract because there is a greater level of certainty that if their due diligence results in a decision to buy they will be able to close the purchase without further negotiations or unrecovered costs. Retail buyers avoid those mineral owners who are merely interested in knowing what someone thinks their minerals are worth, with no intention of selling, and those with no binding commitment to a sale at specific terms and maximize their time where they have an expectation of closing a sale.
PROS AND CONS OF SELLING A MINERAL RIGHT VS SELLING A ROYALTY INTEREST
A mineral right or royalty interest may be sold in its entirety or as a fraction of the whole. One of the four owners of an undivided interest in our 40 acre example, owning 10 net mineral acres, would have the right to sell a half interest in their mineral right. This would result in their retaining a one eighth ownership interest in each of the gross 40 acres and the buyer owning a one eighth interest in each acre. If the seller's mineral right was burdened by an existing mineral lease the buyer's mineral interest would be subject to the terms of that lease. If the 10 acres was un-leased or an existing lease expired then both seller and buyer would be free to lease, or not, their separate ownership interest going forward. A mineral right owner has the right to lease their interest, receive royalty, bonus and other payments. A royalty interest owner has only the right to receive their proportional share of the royalty. As defined by the Louisiana Mineral Code, there are two classes of royalty: a royalty created from a mineral right and a royalty created under an Oil, Gas & Mineral lease. A royalty created from a mineral right, whether by the owner of the lands or by the owner of a mineral servitude created from the lands, is effective for a defined period of time no greater than ten years. If there is no production during the effective period the mineral right royalty expires. If production is established during the effective period of the conveyance the royalty right remains in force and begins again from day one when production ceases. Example: If a royalty interest carved from a mineral right is effective for a period of five years and production commences in year three, the royalty right remains with the buyer for the duration of production. Not for the remaining two years. Once production ceases, the five year effective period begins anew.
A royalty created under an Oil, Gas & Mineral Lease is effective for the term of the lease. Whenever the lease expires, whether through failure to drill a well or through the drilling on a non-producing well, the royalty created under that lease expires also. If a producing well or wells are drilled then the lease remains in force, as does the royalty created from it, until such time as production ceases. Unlike a mineral servitude created by the sale of a mineral right, the prescriptive period for a royalty created under a lease is not reset by a good faith effort to produce that fails (i.e., a dry hole). When a lease expires through cessation of production, the royalty right conveyed expires also.
I strongly advise mineral owners who wish to sell a royalty interest to engage the services of an experienced energy attorney. There are various ways that a royalty may be defined in a conveyance instrument that determine how it is interpreted in law. For the practical purposes of a willing seller the most important variance is how the proceeds of a sale are taxed. The sale of a royalty created from a mineral right, owned for a period greater than one year under current IRS rules, is taxed as long term capital gains. Depending on the seller's tax bracket that would be either 15% or 20%. The proceeds of a sale of a royalty created under an Oil, Gas & Mineral Lease would be taxed as "ordinary income" and depending on the amount would be taxable up to the top effective rate, currently 39.6%. Louisiana mineral owners would also pay the appropriate percentage of state tax in addition to their federal tax requirement. Offers to acquire a royalty interest in producing minerals are commonly based upon a multiple of a monthly average payment. As an example a buyer of royalty may take the average of the most recent three monthly payments and then multiply that amount by a number of months of production, commonly 60 to 120, to calculate their dollar offer.
Experienced mineral buyers understand and seek to manage risk in a number of ways. Interested sellers in emerging plays should account for one of those ways. It is very common for buyers to develop an acquisition strategy where there is little or no actual production that sets target acreage totals by location. Simply put, they don't want too many eggs in one basket. They scatter their purchases across a defined area and decline to acquire more than their target range in any one drilling unit. For that reason a buyer may prefer a 20 acre tract to a 200 acre tract. Those with a different acquisition strategy may prefer the 200 acre tract. In either scenario once they have acquired their acreage target they quite often decline to buy any additional minerals or royalty. Buyers often have a budget and a strategy to buy acreage in locations and in multiple drilling units scattered across their area of interest. Experienced buyers know that not all rock will turn out to be equal and that unexpected geologic factors such as faults can negatively impact prospective minerals. Acquiring mineral on the periphery of an emerging play carries additional risk as even the most extensive unconventional plays do not extend forever. Productivity can decline rapidly or cease over a relatively short distance.
Where lands have been proven with completed wells and mineral ownership has undergone the scrutiny of a high due diligence division order review the risk of acquiring mineral interests is much reduced. It follows that the value of those minerals would be increased. Not all risk is eliminated however as the market price for hydrocarbons has a history of wide fluctuations. At this point the assessment of future value tends to be based on how many wells will be drilled in a unit and in what time frame. The concept of the present value of a dollar is important to both buyer and seller. Minerals in a unit where an operator is actively permitting or drilling additional wells can be of greater value than similar minerals where there is no evidence of additional near term development. However minerals where multiple wells have been drilled and produced for any significant period of time are declining in value as the unit reserves are depleted.
Determining the value of minerals is a subjective exercise and boils down to what a seller is willing to accept from a buyer. Mineral owners should seek professional help and get multiple offers including one or more that originates with a buyer or broker who knows the history and current activity where the mineral interest is located. Before soliciting offers a mineral owner should give thought to just what they are willing to sell. It is easier to make a decision to sell and not second guess that decision or the sales price if a mineral owner has exercised a modicum of due diligence in the process.
Skip Peel, Independent Landman provides land services to land and mineral owners. Services include leasing research and tracking, lease negotiation strategy, tracking spreadsheets for unit and well data by play, mineral history, title research and curative and brokerage for the sale of minerals. Service area is Louisiana and east and south-central Texas. Contact by email at firstname.lastname@example.org.
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