Lease

Why the quarter royalty is not always the best lease option

lease bonus and royalty for mineral owner

By guest contributor, Brian M. Atchley, RPL, Prospect Manager at Prairie Oil & Gas, LLC  


As far back as I can remember I’ve always heard that as a mineral owner you always want to take the highest royalty possible, which is usually the quarter royalty. In many cases, this may be true, but I believe that in today’s oil and gas market trading royalty for more up-front cash can prove to be a better choice. To make a truly informed decision about what royalty to take on an oil and gas lease there are a number of factors that need to be evaluated. This is particularly important in today’s market as the price of oil has proven to be highly volatile in the recent past. Looking first at today’s market conditions I feel it is important to look at the lease bonus amount being offered at the varying royalty options. The lease bonus is typically a per acre amount being offered as consideration to the mineral owner for executing the lease and can vary between the royalties being offered. For example, a mineral owner might receive a lease offer of $3,000 per net mineral acre at a 1/5th royalty or $1,250 per net mineral acre at a quarter (1/4th) royalty. This difference in lease bonus amount comes from each point of royalty being valued at $350. Based on the traditional line of thinking that many people have been taught by parents and grandparents about their minerals, the 1/4th royalty is a clear choice. This is where a little more due diligence helps to see which royalty is really the best offer. In order to see the picture more clearly it is necessary to utilize a model to see how each offer plays out over time. For this model we will first assume that the mineral owner owns 5 net mineral acres and that their interest will be unitized with the other undivided mineral owners in his tract of land to comprise 50% of the total 640-acre unit, and that this particular unit has an initial production rate of 1000 barrels of oil per day (bbl/d).

Secondly, it is important to understand the decline rate of a typical horizontal oil well. Most horizontal oil wells start off with high production rates which is “followed by a first-year decline curve that is incredibly steep” (Schaefer, 2014). This decline curve is shown in Schaefers’ graph below.

Lease bonus and royalty choices for the mineral owner

In conjunction the decline rate of a well it is necessary to estimate the average future price of oil in order to make an informed decision on which royalty option is the most economical for the royalty owner. In this model, only the first 5 years of data will be utilized to determine the best royalty option. The average price of oil in 2017 was $49.70 per barrel (Short-Term Energy Outlook, 2017). Future average oil prices for 2018 ($56.18/bbl), 2019 ($53.74/bbl), 2020 ($52.27/bbl), and 2021 ($51.40/bbl) were derived from CME Group’s Crude Oil Futures Quotes (crude oil futures quotes, 2017), and provide enough information to construct and compare revenue models for the 1/5th and 1/4th royalty options. Through the use of these models, the results will then be compared to the initial lease bonus to determine which royalty option is more economical given the current market trend of oil prices.

The first calculation that is necessary to determine the Total Royalty Revenue (TRR) is the decimal interest in the well, which will be denoted as “D.”

 

D = (Net Acres/Unit Size) X Royalty X Unit Allocation

           

1/4th Royalty                                                    1/5th Royal

D = (5/640) X .25 X .50                        D = (5/640) X .20 X .50

D = .00097656                                        D = .00078125

 

The next step is to determine annual production for each of the first 5 years of production. In this model, we have assumed that the initial production, denoted as “IP” for this well is 1000bbls/day and that the decline rate will follow Schafer’s decline model. The production data for each year, 365 days, denoted by “Prn.

Prn = (IP X 365) X Decline Rate

            Pr1 = (1000 X 365) X .69

            Pr1 = 251,850bbls

            Pr2 = (1000 X 365) X .39

            Pr2 = 142,350bbls

             Pr3 = (1000 X 365) X .26

            Pr3 = 94,900bbls

            Pr4 = (1000 X 365) X .27

            Pr4 = 98,550bbls

            Pr5 = (1000 X 365) X .33

            Pr5 = 120,450bbls

With values assigned to D and Prn, it is now possible to incorporate the average oil price, denoted by “P,” for 2017 ($49.70/bbl) and the estimated average price of oil for the following four years, 2018 ($56.18/bbl), 2019 ($53.74/bbl), 2020 ($52.27/bbl), and 2021 ($51.40/bbl) to build the Total Royalty Revenue model.

TRR = D[(Pr1 X P1) + (Pr2 X P2) + (Pr3 X P3) + (Pr4 X P4) + (Pr5 X P5)]

 Utilizing this model for the D value for both the 1/4th and 1/5th royalty option will provide the Total Royalty Revenue for each option, which can then be compared to see the difference after the first 5 years of production. Once this value is calculated it can then be compared to the difference in lease bonus between the 1/4th and 1/5th royalty options to see which option is the better choice in today’s market.

1/4th Royalty                                                                 1/5th Royalty

TRR1/4 = .00097656($36,956,432.50)               TRR1/5 = .00078125($36,956,432.50)

TRR1/4 = $36,090.27                                                TRR1/5 = $28,872.21

 

TRR1/4 – TRR1/5 = $7,218.06

 

While our model shows the difference in Total Royalty Revenue (TRR) for the first 5 years of this well as being $7,218.06, we can now compare this to the difference in lease bonus. While the lease bonus for the 5 net mineral acres at the 1/5th royalty was $3,000 per net mineral acre and $1,250 for the 1/4th royalty option we can see a difference in the initial lease bonus of $8,750.00. When comparing this difference to the difference in TRR after the first 5 years there is a negative difference of $1,531.95. This means that at the 1/4th royalty it would take more than 5 years for this option to be as or more profitable for the mineral owner than the 1/5th royalty option.

While there is no guarantee that any additional wells will be drilled on the leased lands, that is information that would need to be considered when choosing a royalty option by the mineral owner. Any increased density well completed on the leased lands would likely move the timeline of profitability for the quarter royalty up to some point less than 5 years versus that of the 1/5th royalty. This model also uses the present value of money and any future value of money could possibly increase the profitability timeline due to inflation. Additionally, this model would likely change dramatically if the price of oil were to increase back to values of the 2012 era where the price of oil was in the $90/bbl range. With prices in the $90/bbl range the 1/4th royalty would likely become more profitable than the 1/5th royalty option very early on the production cycle. Given the volatility of oil prices, current market trends and forecasts into the foreseeable future, this model shows why it may be more economical for a mineral owner to take a lower royalty in exchange for a higher up-front lease bonus.

 

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