Oil Patch Press
Common DOI Management Issues: Interest Types
Assigning an interest type to an owner in a division of interest sounds simple, doesn’t it? Too often today, it’s no longer simple.
The basic interest types that anyone can own in a property are royalty, overriding royalty, and working interest. Simple so far. The complication sets in with the valid variations of those types (sub-types) that should be used in the DOI for accuracy.
In the royalty group, there are four sub-types: the lease royalty, floating non-participating royalty interest, fixed non-participating royalty interest, and non-executive mineral interest royalty.
Lease royalty is the royalty reserved in the signed lease, and quantified by it. It is part of the mineral rights covered by the lease. That royalty rate exists only for the life of that lease. When the lease expires, that specific royalty rate expires with it. The next lease signed could have a higher royalty rate. Examples of common lease royalty codes are “R” and “RI”.
The floating non-participating royalty (NPRI) is also derived from the mineral rights covered by the lease. An NPRI does not include the right to negotiate or sign a lease, or to receive a part of the signing bonus or delay rentals. Depending on the language in the document creating it, the non-participating royalty can be a proportionate part of the specific royalty rate stated in the lease (known as a “floating NPRI”) or can be a fixed NPRI discussed below. An example of the calculation for a 1/16th floating NPRI would be 1/16 x 1/5 lease royalty, or 0.0125. The owners of the lease royalty would receive their proportionate share of 15/16 x 1/5, or 0.1875. The two combined total 0.2000, or 1/5.
A fixed NPRI is created by the language in the document creating it, just like the floating NPRI discussed above. The signed lease activates the fixed NPRI, but unlike the floating NPRI, the fixed NPRI does not depend on the royalty rate in the lease for its calculation. The fixed NPRI is just that, a fixed rate of royalty owned in the specific tract of land. Using the same 1/16th NPRI ownership fraction as the example above, a fixed NPRI would be 1/16th or 0.0625. Regardless of the royalty rate contained in the signed lease covering the mineral interest from which the fixed NPRI was derived, the fixed NPRI will always be entitled to 0.0625 of production of the well. The calculation for the lease royalty subject to this fixed NPRI would be 1/5 minus 1/16, or 0.2000 – 0.0625 or 0.1375.
Both the floating NPRI and fixed NPRI can be proportionately reduced by the unit size (if any), if the NPRI owner ratifies the lease or the designation of unit. It also can be reduced by the length of horizontal wellbore lateral traversing the NPRI tract divided by the total lateral length, if the well is horizontal, and its owner has not ratified the lease or designation of unit.
It is important to designate the interest as NPRI and not just a royalty (R or RI) in Texas properties because NPRIs are calculated differently than the pooled lease royalty, unless the NPRI owner has ratified the lease or the designation of unit. Unratified NPRI owners outside the drill site tract(s) generally are not entitled to receive payments for the life of the well.
The fourth type of royalty is known as the NEMI, or non-executive mineral interest royalty. It is a full-ownership mineral interest that owns all rights, except the right to negotiate and sign a lease. It is included under the lease covering the land and shares in the lease royalty rate, but also the bonus and rentals payments for the lease. Like the NPRIs discussed above, it also is not bound by the pooling clause in the lease. A NEMI must ratify either the lease or the designation of unit to be paid if its tract lies outside the drill sight or the tract is not traversed by the horizontal wellbore lateral.
The second interest type is the overriding royalty, which actually is not a royalty at all. It is a tiny piece of the working interest, but it never pays its share of pre-production costs (exploring, drilling, completing, or producing). The working interest out of which it was carved will always pay those bills on its behalf.
The most common sub-groups of overriding royalty are leasehold ORRI, wellbore ORRI, volumetric ORRI (known as a VORI and exists only until a certain volume of production is saved and sold, then it automatically terminates), and net ORRI—a special type of net profits interest.
Overriding royalties are assigned out of leasehold working interest, most commonly created in an Assignment of Oil and Gas Leases either as an outright conveyance of ORRI or as a reservation in a conveyance of working interest. Common interest type codes used in the DOI are O, OR, and ORR.
Last is the working interest (WI) type. It can be leasehold WI, unleased mineral interest participating in the well costs (PMI), or unleased mineral interest not participating in well costs (UL). Common interest type codes are W, WI, PMI, and UL or UNL respectively. Properties in Texas will use interest type codes for unleased working interest for reasons to be discussed in future blogs, because most other states use some form of forced pooling which creates court-ordered leases covering the otherwise unleased mineral interest.
Using a correct interest type code in the DOI is important for many reasons beyond accuracy. For instance, a royalty interest is taxed differently than a WI or ORRI. Also, typically a database will internally code a royalty-type interest to also be manually coded free from post-production costs deductions if the lease or other contract requires it. A WI or ORRI type, however, usually are internally coded ineligible in the database to be manually coded free from post-production costs deductions (“cost-free”). When post-production costs are not deducted from a royalty interest, that proportionate share of those costs are borne by the working interest contractually responsible for that royalty.
Next week’s blog will be “Common DOI Management Issues: Similar Owner Names.”