Calculation of Net Acre Feet and Value


I am new to this forum and have a question. Our mineral rights have recently become part of a pool of around 3,300+ acres. Our particular tract consists of 478+ surface acres of which we have 15 net surface acres. The lease states that there are 4,567 Net Acre Feet calculated on the 478 acres. Earlier in the lease it shows the formula as to how the calculation was made for each tract contained in the 3,300+ acres. It appears to be a weighted average. The formula states 80% X Tract Productive Net Acre Feet and then 20% X Tract surface acres in Unit Area.

It then shows this particular tract as Tract Participation 0.1070633 Surface acres 478 with Net Acre Feet of 4,567.

I was a commercial appraiser for over 25 years and have appraised other mineral rights so I am arguably somewhat used to applying formulas and making calculations, however I have not done this before. Thus, I'm hoping someone can help me understand the correct way to make this calculation. Thanking you in advance!

In the below calculation I took the liberty of rounding up instead rounding down where I should have in some cases. Just trying to figure out if I'm even interpreting the information correctly and working the right formula.

1) Our 15 Surface Acres / Surface acres Tract 478(r) = 3.138 rounded to 3.5%.

2) Total Net Acre Feet this Tract 4,567(r) x 3.5% = 160(r) Net Acre Feet.

3) 160 Net Acre Feet converted to Barrels of Oil = 1,241,338(r).

4) 1,242,000 Barrels x $50 (current market price) = $62,100,000.

5) $62,100,00 x 1/8 (net lease amount. 0.125 or 12.5%) = $7,762,500.

Although that number looks good, for some reason my gut tells me I'm probably missing something here :-) I have a few other questions, but I'll hold on those until I first have an understanding of this part of the equation.

Thank you very much for taking the time to assist my learning here.


You know Ron, if someone handed me a lease with all this jibberish in it, firstly, I would feel insulted. Then I would hand it back and ask them to 'spell out' in simple terms what it means. And, then, I might consider signing after I knew what I would be signing.

When a lease is written like this, I would automatically think that the lessee was trying to put something over/on me. Or, they were thinking that I was a mathematical wizard who could read their mind..

Personally, I would throw this mess back into their court.
Good luck,


From your mineral appraisal experience, imagine a highly permeable sandstone or limestone geologic oil trap deposit. The geometry of the deposit, including geographical limits and thickness isopach contours have been established by a sufficient number of vertical intercepts of the deposit so that the geometry of the deposit is not in doubt. Well logs showing formation pressure, water saturation, porosity, density, and other physical attributes can also be plotted by XYZ isopachs to show water tables impermeable lenses, and deposit physiological consistency. All of this analysis in common in flooding a known deposit.

To be fair to the property owners and investor partners, their respective plots are superimposed on the resulting isopach maps and acre-feet influences made for that owner/partner. An owner with 20 feet of deposit thickness over one acre will share in a larger portion of the revenue than a mineral owners with 2 feet of deposit thickness per acre located on the edge of the deposit.

Check you calculation 3). Unless you applied water saturation, pore pressure, density, permeability, the propensity of the gas molecules to stay in suspension at atmospheric pressure, and most importantly, proven percent recovery per volume of injected material,the conversion may not be accurate.

Prior to the advent of horizontal drilling and fracking in the US, the average recovery from oil wells drilled and completed conventionally was about 28% of the amount of oil in place arrived at by the metrics mentioned above.

Flooding with water, polymers, and CO2 double that total recovery at best.

The best appraisal parameters of large units remains the projection from decline curves based on the entire unit. With floods, the decline curves must be adjusted by the appropriate operating characteristics before being applied to acre foot distributions.

Hope that answers some questions.

Gary L Hutchinson

Minerals Managment

Thank you Gary! I would have expected there to be a section included that defined terms utilized and how calculations were made. That did not exist. Subsequently, a new lease now depicts 25% per barrel for our share and participation in 25% of the cost to treat. Your description and analyses makes sense to me and more of what I would have expected to find somewhere in the disclosures. In addition, yes, this phase involves water flooding. I greatly appreciate you taking your professional time to assist me.

Thanks again,


Thank you Pat. I have phoned and asked for clarifications on a number of these issues. There was no section contained in any of the documents that explained how these calculations were made...simply that they were produced by the oil and gas appraisers. Based on other information provided, some of these things seemed to be in complete conflict. I have now received an updated lease stating our percentage is 25% per barrel, while also incurring 25% of the treatment cost. I've asked for clarification on all of this. Thank you very much for responding to my question.


One correction on the last contract. It is 1/8 of cost (not 1/4) ) "of the cost of treating oil to render it marketable pipe line oil." I have asked them what all is included in that cost and what their estimate per barrel is (awaiting their response). In addition, I'm trying to locate industry averages for the same relative to reserves that are water flooded for production.