Rob2, Tim Dowd is a wealth of knowledge and spot on regarding your leasing concerns. You are free and clear to lease, as you have no active lease.
For your second question, it’s a bit more complicated, and I’m gonna over explain it, just to see if it’s helpful.
First-off, I have only signed one lease in Roger Mills County. I spent many many countless hours learning everything I could to negotiate my own lease; spent months negotiating, then put it on pause and spent a few more months negotiating again. Even when I signed, I didn’t understand the possible value of a leased mineral acre in a 2-mile horizontal well in Roger Mills County. I have more clarity now, although it is completely speculative, I feel more educated and comfortable.
From looking at wells in recent months completed and producing nearby I’ve created my own little equation with the help of information shared on this forum.
1. Cumulative Production Breakdown
The lifetime total production for an average 2-mile lateral in this core area generally hits these benchmarks:
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Crude Oil / Condensate: 350,000 to 500,000 barrels (BBLs)
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Natural Gas: 2.5 to 3.5 billion cubic feet (BCF)
2. Initial Production (IP) and Peak Rates
Modern completion and frac techniques by dominant operators in the area (such as Mewbourne Oil and Upland Exploration) deliver very high initial volumes:
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Peak Daily Rate: Newly drilled 2-mile wells routinely show peak initial production rates averaging 1,200 BOE per day.
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Real-World Example: As a benchmark, Upland Exploration’s Easy Come Easy Go 1-36well (a nearby Cherokee offset well) recovered approximately 138,000 BBLs of oil and 0.74 BCF of gas in its very first year of online production alone.
3. Production Decline Profile
Like most unconventional horizontal plays, Cherokee wells experience a steep hyperbolic decline. A typical well will produce 35% to 40% of its total lifetime oil and about 25% of its total lifetime gas during the first 12 months of sales.
Remember this is all speculative, with many factors affecting outcome, but I think it’s a reasonable way to project possible production from a well.
So…
Take 350,000 bbl’s of oil. Multiply that by a respectable price sold per barrel. We’ll go pre Iran War, and say $75/bbl.
We get $26,250,000
Divide that by 1280 acres, because that is how many acres are spaced in a 2-mile horizontal well. Which is what most of the wells are now.
We get $20,507.81, this is the “value” of one acre before the lessee takes their cut
If you have 1/4 royalty, multiply that number by 0.25.
We get $5,126.96
That is your value of one mineral acre for the oil production only. If that scenario, your six acres is worth $30,761. If price of a barrel is more, you get more. This is over 30+ years of production. Do that same math with natural gas.
2.5 million BCF at $3/bcf is $7,500,000
We get $1,464.84
TOTAL MINERAL ACRE VALUE = $6,591.80*
*If you have no deductions, and disregard taxes
-remember this is all low average. It could be substantially lower or higher, but this is a kind of a mean number for reference.
-now add potential future infill wells, the possibility for overlapping wells at different depths and you can at least paint a picture to understand the significance of 1 mineral acre
Now you have to ask yourself if it’s worth paying an attorney a couple thousand or less to make you feel secure that you are getting all that money and not having post-production and other expenses taken out. A lot of times, it’s not worth it compared to waiting for pooling. The risk is more if you miss the pooling and then get leased at the lowest royalty.
Hope the Math helps, and if anyone thinks that is not a good equation, please let me know. I wouldn’t want to steer anyone in the wrong direction.
