Leasing Your Oil and Gas Minerals

By Skip Peel, Independent Landman

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 days 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 forces 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.

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