Updated: Mar 7, 2019
Many division order analysts are squeamish about working Oklahoma as a geographic area. This is because Oklahoma is unique in its royalty distribution statutes. What too many analysts believe is a complex mathematical formula must be used to distribute pooled unit gas royalties and comply with Oklahoma statutes.
In 1992, Oklahoma passed Senate Bill 168 into law. The new law had two parts: PRSA and NGMSA.
The Natural Gas Market Sharing Act (NGMSA) mandated all pooled unit operators to make their gas market available to any partner in the well that wants to market its share of gas volumes under the operator’s contract with their gas purchaser. While that sounds fairly simple on its face, it was a leap forward for royalty owners who had struggled for years to get paid all gas royalties due to them, if they got paid at all.
In Oklahoma, as in other oil and gas producing states, each working interest partner in the well (the company or person who owns part of the leases in the unit and participates in the costs) is allowed to market its share of gas volumes under its own private contract with a purchaser. Usually a non-operator partner in the well has no problem negotiating a contract with a purchaser for their share of the gas, but for partners with a very small working interest decimal—3% or less, for instance—sometimes purchasers wouldn’t give a contract. The administrative costs on the contract would eat most, if not all, of the profits they would realize from it. So those tiny partners didn’t market their share of gas. Their royalty owners didn’t get paid. As a rule, every month that partner’s gas was treated as still being “in the ground”—not yet produced. The partners who sold gas that month were overproduced by their share of the non-selling partner’s gas. The non-selling partner would be under produced by their <3% share of gas they were unable to sell. Over time, the gas imbalance would reach a point that it would be impossible for the non-selling partner to ever “make up” the under-balance by starting to sell their gas in exaggerated quantities (which is allowed). Put simply, the royalty owners got the shaft.
NGMSA solved that problem. The small partners could always sell their tiny share of gas under the operator’s contract. That small partner’s royalty owners would always be paid.
Which brings us to the other half of SB-168, the Production Revenue Standards Act. This part of the act says that if gas volumes are sold “split stream,” meaning gas is taken to more than just the operator’s contract, each partner selling their gas independently must pay over to the operator each month an amount of their gross revenues known as “total unit royalties” or TUR, for short. The decimal that each partner pays is based on their Proportionate Production Interest, or PPI for short.
The PPI calculation formula is written in a way that takes differences in lease royalty rates and exclusive overriding royalty burdens into account, but still delivers to the royalty owner exactly their correct share of royalty under their lease.
To learn more about PPI calculations, buy a copy of our “Oil & Gas Pooled Lease Calculations Workbook” for sale in the paperback bookstore. It contains NGMSA and PRSA information and calculations that every Oklahoma mineral rights owner should learn. Personal knowledge is always the best tool for verifying the correctness of any royalty remittance check.