Frequently Asked Questions

In most states, unless the mineral estate was previously reserved in a tract’s chain-of-title, the surface estate will include the mineral estate.

Mineral rights can be sold with or separate from surface property rights. However, minerals are included in the surface estate unless otherwise reserved by a prior owner.

Executive rights owners have the right to negotiate and execute oil & gas leases. In addition to executive rights, the other rights associated with mineral ownership are (1) the right to receive lease bonus payments, (2) the right to receive delay rentals, if provided for in the oil & gas lease, and (3) the right to receive payment of royalty.

NPRIs are created when a mineral owner conveys all or part of the royalty interest under a given tract, but does not convey any right to execute oil & gas leases.

NPRI owners are entitled to their proportionate share of oil & gas revenue from the tract without having to share in the operational costs of the well(s), however, their royalty interest is subject to the lease royalty rate negotiated by the executive rights holder in the oil & gas lease.

The main difference between executive rights and NPRI owners is executive rights holders execute oil & gas leases and receive lease bonus and delay rentals. NPRI owners receive only their proportionate share of oil & gas royalty payments.

Working interest refers to an individual’s or entity’s ownership percentage in the oil & gas operations within a well, regulatory lease or contract area. Working interest owners must account for the costs associated with the leasing, drilling, completing and production resulting from oil & gas operations.

An overriding royalty interest is a cost-free royalty interest retained by a lessee when an oil & gas lease is assigned to a third-party. Such an interest expires once the underlying oil & gas lease from which it is derived expires.

An overriding royalty interest is a cost-free royalty interest retained by a lessee when an oil & gas lease is assigned to a third-party. Such an interest expires once the underlying oil & gas lease from which it is derived expires.

It is common to have numerous companies leasing minerals under a single tract. In order for a well to be drilled, entities usually (1) assign their oil & gas leases to the entity who will operate the lease, or (2) enter into a joint operating agreement which aggregates the oil & gas leases for a defined contract area and appoints one party to act as operator.

A regulatory lease is simply the acreage designated by an operator for oil & gas operations that has at least one undivided owner of the underlying mineral estate.

An oil & gas lease clause mandating the termination of the oil & gas lease upon primary term expiration as to acreage located outside a production unit, as defined in the oil & gas lease.

Older oil & gas leases often do not contain a Pugh clause.

The Continuous Development Clause (CDC) allows an operator to extend the oil & gas lease primary term so long as it maintains scheduled continuous drilling and completion operations. If an operator fails to adequately dedicate all acreage to production units within the time provided for in the clause, then the oil & gas lease terminates as to acreage not assigned to a production unit.

Older oil & gas leases often do not contain a Continuous Development Clause.

Oil & gas lease ratifications are usually executed for one of two reasons:

The decimal figures on royalty payment statements are the net-revenue-interest(s) for the respective regulatory leases in which the operator/purchaser is issuing payment. Simply put, this is your proportionate net share of production revenues stated as a decimal, which takes into account both your fractional mineral/royalty interest in the tract, as well as the lease royalty rate negotiated in the governing oil & gas lease.

For horizontal wells, both pooled units and allocation wells allow an operator to drill across regulatory lease lines. The primary difference between pooled units and allocation wells is the methodology in which royalty owners are paid on horizontal well production.

In a pooled unit, a royalty owner’s net-revenue-interest is proportionately reduced by the ratio of the number of surface acres the owner’s contributing lease contains in proportion to the total number of surface acres represented by the unit.

In an allocation well, a royalty owner’s net-revenue-interest is often proportionately reduced by multiplying the net-revenue-interest by a fraction, in which the numerator is the footage of perforated wellbore within the owner’s contributing tract, divided by the total perforated footage of the wellbore. However, operators often provide Production Allocation/Sharing Agreements to mineral/royalty owners which can modify the allocation methodology.

When an oil & gas lease is pooled into a larger regulatory lease or unit, the mineral/royalty owner’s right to production revenue is proportionately reduced by the number of surface acres of its tract within the larger regulatory lease or unit.

The net-revenue-interest is simply your fractional mineral/royalty interest in the regulatory lease, multiplied by the royalty rate negotiated in the governing oil & gas lease. When appropriate, a tract participation factor may also be applied.

Divestment of a mineral/royalty interest results in a single tax event. Receipt of monthly oil & gas royalty revenue payments are taxed on a continuing, annual basis. It is imperative to consult with your tax professional to accurately determine an individual’s tax burdens/consequences.

Trusts are created by the execution of a “Trust Agreement.” The Trust Agreement will determine whether or not the Trustee(s) may sell mineral interests owned by the trust. Since every trust has its own, unique Trust Agreement, some trusts may be able to sell mineral interests while others may not.