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Primer for Understanding Ownership in Oil and Gas Wells

March 15, 2019

History of Ownership

At some point in time every parcel of land and the associated minerals were owned by some entity, perhaps people or perhaps a government.  Ownership was in "fee simple," meaning that both the surface and the minerals below the surface were owned as a unit.  Through the years most surface ownership was separated from the below-ground or minerals ownership as the land was developed.  Mineral ownership virtually always carries with it a "right-of-way" or access to surface land as necessary to develop and market the minerals.  Other than having right-of-way for the drilling of wells, installation of tanks, pipelines, and other production equipment, and necessary roads, mineral ownership is seldom involved with surface ownership.  The two types normally exist independently, and this discussion will focus on mineral ownership.

 

Split Mineral Estate and Fragmented Ownership

Initially the surface owner usually owned the mineral rights, too.  Mineral ownership is a commodity that can be bought and sold, traded, leased, inherited, or transferred in any other legal manner.  It can be owned by people, partnerships, trusts, corporations, governments, etc.  Ownership is now very fragmented and it is unusual to find large tracts that are owned by a single entity.  This causes complexity in the drilling of oil and gas wells.

 

Mineral Ownership and Development of Wells

The person or other entity who owns the mineral rights is a mineral owner.  Mineral owners seldom drill wells.  Instead they lease the mineral rights to someone else, for which they usually receive a bonus payment along with a promise to drill a well within a certain period of time, and they retain a royalty interest in the land.  The mineral owner has now become a "Royalty Interest Owner."

 

Regulations and Well Spacing

States now regulate the drilling of wells.  One of the most critical factors is how close wells can be to other wells.  A key factor in this is how large of an area can be drained by a single well.  Producing characteristics vary from one formation to another since all subsurface rock is not the same.  Historically, based on both common surveying practices and production experience, common spacing is one well per 320 or 640 acres.  This constitutes a "drilling unit." Both larger and smaller spacing occur in some areas.  It is most convenient when a drilling unit is a square or rectangle which matches the survey, but some states have allowed gerrymandered units and even non-contiguous units in some instances.

 

Establishment of spacing and drilling units is vital.  Companies that want to drill wells must acquire all of the acreage within each drilling unit.  Acreage is normally leased from whomever owns it.  If some other company (person, etc.) already has a lease, they may either sell or assign their lease to the other company (the "operator") or participate in an informal partnership.  Ownership of the mineral rights and assignment of those rights via a lease must be known.  All documents relating to ownership are to be recorded in the county where the land is located.  Then painstaking research can identify the ownership and leasing status of each parcel.  Once all of the acreage is accounted for and all necessary permits are obtained, the operator can drill the well.

 

Example to Illustrate Spacing and Calculating Net Revenue Interests to Working Interests and Royalty Owners

Let's create a simple example.  Operator A wants to drill a well where a drilling unit is a square 640-acre section.  Person 1 owns the minerals for 3/4 of that section.  This could mean that Person 1 owns 100% of 3/4 of the section or owns 75% of the entire section.  Person 2 owns the remaining 1/4 interest.  Person 1 leases his land to Operator A and retains a 1/8 royalty interest (1/8 or 3/16 are typical).  Person 2 leases his land to Company B and also retains a 1/8 royalty interest.  A Royalty Interest Owner will receive that share of the proceeds if the well is productive but does not have to pay any of the costs of drilling or production.  Person 1 gets 3/4 of the 1/8 royalty and Person 2 gets the other 1/4 of the royalty because of their ownership shares.  They do not each get 1/8; together they get 1/8.  Their "revenue interest" is equal to the royalty percent multiplied by their ownership percent in the drilling unit.

 

Parties that get a share of the revenue and also pay a share of the costs are the "Working Interest Owners."  The working interest is equal to 100% minus the royalty interest.  In this simple example, 100% minus 12.5% royalty leaves 87.5% for the Working Interest Owners.  So here 100% of the working interest receives 87.5% of the revenue.  Operator A gets 75% of that amount and Company B gets 25%.  Their respective revenue interests are 65.625% and 21.875%.  But their cost interests are 75% and 25% because they, as Working Interest Owners, are paying 100% of the costs.

 

These calculations become significantly more complex if there are many Royalty Interest Owners or Working Interest Owners.  If someone has a 1/8 royalty in only 5 acres in a 640-acre well, their revenue interest is only 0.0009765, but it still has to be accounted for.

 

Another type of interest is an Overriding Royalty Interest (ORRI).  An ORRI is carved out of the working interest and does not affect Royalty Interest Owners.  A typical scenario is where a landman or small company obtains a lease but does not want to participate in the costs of drilling a well.  They assign the lease to another party but retain for themselves an ORRI which entitles them to a share of the revenue, usually for a limited period of time or until a specified sum of money has been received.

 

Another type of interest is a reversionary or back-in interest.  A typical situation here is when a company does not want to participate in the costs but also does not want to sell their lease.  The operator may agree to cover their costs but then the operator receives their share of the revenue until some specified amount, such as 200% or 300% of their costs, has been received, at which time the company "backs in" to their share and also pays their share of costs from that time forward.

 

Leases can also expire when their terms are not met and then new leases are taken by other parties.  Determining each person's or company's revenue interest as ownership changes through the years, usually becoming more and more fragmented, is challenging and requires precise record-keeping.

These materials have been prepared solely for educational purposes to contribute to the understanding of oil and gas appraisal. These materials reflect only general concepts in the industry based on Colorado and may not apply to all circumstances.  It is understood that each case is fact ‐ specific, and that the appropriate solution in any case will vary.   These materials may not be relevant or apply to any particular situation.  While every attempt was made to ensure that these materials are accurate, errors or omissions may be contained therein, for which any liability is disclaimed.