The combination of database data entry requirements for horizontal wells containing unleased mineral owners presents a unique challenge for division order analysts when working Texas properties as opposed to properties in other oil and gas producing states. Other states almost always have easily available involuntary (forced) pooling available to operators; Texas does not. Don’t get me wrong, Texas does have forced pooling statutes, but they are expensive and cumbersome to use.
We will take a look at the three main areas that give division order analysts a challenge when a new-drill horizontal producing area contains unleased mineral owners.
They are (1) the basic types of horizontal wells that are drilled, (2) the special considerations for unleased mineral interest owners (UMI owners) when a horizontal well is drilled, and (3) the special care analysts must take with some of the popular revenue distribution software systems when entering data for this type of well.
Types of Horizontal Wells
There are three types of horizontal wells in Texas. The first is the one-tract horizontal well where the only tract involved is large enough that no pooling is needed. The first and last take points in the lateral are both inside the boundaries of the one tract. Rare, indeed, but it does happen. We’ll call this the one-tract horizontal.
The next kind of horizontal well is the one that involves more than one tract but is not pooled. The first take point is in one leased tract and the last take point is in another tract. The horizontal wellbore lateral can begin in one tract, cross over into another tract, and even a third or fourth tract in some cases, before reaching the last take point. This type of well is called an allocation horizontal well and is common in Texas.
The third kind of horizontal well is the pooled, or unitized, horizontal well. Several individual tracts are pooled together to form a unitized area for production. This is a unitized horizontal well.
Unleased Mineral Interest Owners
Unleased mineral interests (UMIs) in a one-tract horizontal well would be paid their proportionate, unleased interest (after 100% payout if they do not participate). There is no contract involved, so it doesn’t matter that they are not bound by it. Revenue distribution to a UMI in this type of horizontal well really is straightforward.
UMIs in an allocation horizontal well are a bit more complicated. Revenue distribution among all shareholders (owners) in an allocation well can be calculated based on any one of four scenarios in Texas.
First, the distance between the first take point and the last take point is measured by a licensed surveyor. Then the surveyor measures each length of the lateral contained in each of the tracts involved, sometimes also stating the length in feet and assigning the percentage of the total wellbore length contained in each tract in each a separate legend or a call-out box in the as-drilled well plat. The revenue decimals for the owners in each tract then are proportionately reduced by the percentage of length of producing wellbore in that tract, by the division order analyst.
The second acceptable method of allocating production between non-pooled tracts is much like the first, except it breaks apart the production lengths based on total length between point of entry into the producing zone (called the penetration point) and the end of the wellbore (called the terminus).
The third method sometimes used is based on establishing a proration area around the entire length of the wellbore from penetration point to terminus. This is done by the surveyor measuring out from the lateral 300 feet, or whatever Texas Railroad Commission rule is in effect for this well, on either side of the wellbore. This results in the wellbore lateral in the as-drilled plat having a line drawn around it denoting the proration area, filled in with shading, making it look like a giant cigar or a long box.
The surveyor then surveys the amount of surface land in the 600-foot swath with the wellbore in the center of it. The surveyor measures the length of lateral inside of each tract and calculates the amount of proration acres attributable to each tract. This information also is placed by the surveyor in the as-drilled well plat either in a legend or using call-out squares.
The fourth method appears to be much less common, involving counting the number of wellbore perforations inside each tract and dividing that number by the total number of perforations in the entire length of wellbore. The legal theory, as it has been explained to me, is that each perforation can be considered a separate “well”, so allocation would be on that basis.
A UMI in any one of the producing tracts in an allocation horizontal well would be paid revenues based on their tract mineral interest decimal in that tract multiplied by the allocation factor assigned to that tract by the surveyor. This calculation is done by the division order analyst as part of their task to create a revenue distribution division of interest for the well. Bear in mind that if more than one horizontal well is drilled across the same set of non-pooled tracts, the allocation factors for each tract almost always will be different for each well.
UMI Owners Inside a Texas Pooled Unit
A pooled unit created by a recorded Declaration of Pooled Unit or other voluntary pooling document creates the equivalent of one big lease in which every owner in any of the lands in it owns a share of production proportionately. A DPU binds all parties involved in the leases pooled by it, to allow their interest to be proportionately reduced based on their lease’s pooling clause.
Unleased owners are not bound by any contract they did not sign. They are not bound by a lease that would contain a pooling provision, so their interest cannot be proportionately reduced. They can be bound by the DPU and their interest proportionately reduced only if they ratify the DPU. They don’t have to sign a lease, but becoming party to the DPU will allow their interest to be proportionately reduced.
If any part of the wellbore comes within 300 feet (or number of feet as ruled by the TRC for that well) of the boundary of their tract, they must be paid 100% of their tract decimal interest (after 100% payout) based on one of the four methods explained earlier. However, their 100% tract interest must be reduced by the allocation factor assigned to that tract in the well.
