I'm seeing a lot of talk in this discussion centering on bonus rates. I'm sure that by now someone has mentioned this in response to the original question, but I'm going to say it anyway. Current Lafayette prospects mostly are classified as gas wells by the TRC--some condensate, but that's just oil that gets produced from a well officially classified by the Texas Railroad Commission as a gas well. A gas well means pooling is most often required because there aren't too many 640-acre single tracts in Lafayette. Feel free to jump in and correct me on anything I'm saying here. Bottom line is, unless you own a single tract of 100+ net acres and can pretty much write your own lease because of it, you're taking a risk by refusing to lease if all of your neighboring tracts are leasing. The reason is because in Texas, a pooled unit can be formed that includes the legal description of your land, but your land will not be bound by the pooling. Here's the upside: if an owner is unleased and a well is drilled with even one perforation in the wellbore within 200 feet of your tract line, the owner gets 100% of the production revenues from the allocated production from that section of the wellbore based on the number of perfs on or within 200% of the owner's unleased tract. The owner just doesn't get paid until the well pays out 100% for the operator. Here's the downside: if a well is drilled that doesn't have even one perforation in the wellbore that is within 200 feet of the owner's tract, the owner doesn't share in any of the royalties from that well. Ever. For the life of the well. And based on experience? A lot of operators will torture the direction of a wellbore to avoid an unleased tract being part of the drillsite. Do you feel lucky? What's worse, once the pooled unit surrounding a non-drillsite unleased tract begins to produce, every lease buster in Texas will be banging down the owner's door to take a lease. But guess what? They'll tell the owner that they will give them a fraction of the $200/ac bonus the owner could have gotten before, in exchange for a 20% royalty rate. "After all," they'll say, "there's already a producing well. You'll start getting royalty checks right away!"
What about today's oil and gas industry strained by depressed oil and gas prices? Companies aren't spending $200/acre PLUS brokerage costs (all of the costs they expend just to pay that $200, usually another $200+) just to let a lease sit out its primary term and expire. They already have deals in the works to line up partners to participate in the drilling of the initial round of proposed wells. The money is not in the bonus payment nowadays. The money is in the royalty rate. Let me prove that last statement. Say you own 10 net acres. You would get $2,000 bonus at $200/ac rate if you accept an 18.75% royalty rate. If you negotiate paid-up rentals for another $20/ac/year for the 2 remaining years of a 3-year primary term, that's another $400 paid with the bonus, if the paid-up rental isn't already included in the $200 at the 18.75%. Total of $2,400 at the outside. But remember, for that $2,400 you would get a 3/16 (18.75%) "basic" royalty rate. Instead, if you can negotiate with the longer term in mind, you could tell them you will take $100 per acre for a 25% royalty rate. It's being done--go to the Lafayette courthouse and look at all of the Memorandum of Lease agreements filed there over the past year or so, to hide the higher royalty rate, etc. Say that a 640-acre pooled well comes in that will produce the average of about $6 Million over its average lifetime of about 10 years.
If you took the 18.75% royalty at $200/ac, you would get over 10 years a total of roughly $17,578.13 plus the $2,400 bonus, or $19,978.13 if you add a clause to the lease that says your royalty is cost free of everything but taxes, if they will even let you have that clause at the basic rate. But if you took the 25% royalty at $100/ac, you would get the cost-free clause as part of the deal and over 10 years a total of roughly $23,437.50 plus the $1,000 bonus, or $24,437.50. And what if the well produced above average (half of the wells do, which is why they call it an average)? Well, you do the math (total production revenues times royalty rate times 10/640). But the $2,400 never changes and the $1,000 never changes. Now add a second--and a third--well in that same pooled unit (to maximize allowables for the Lessees), and now the $1,000 or even $2,400 looks like pocket change.
The oil companies aren't the only ones taking a risk in oil and gas exploration and production, Fayette County and everywhere else in the continental U.S. Landowners are, too. But knowledge is the key to reducing risk, and maximizing profit, for both Lessor and Lessee.
Oh, and by the way. I'm going to venture to say that as much as half of all of the leases being taken in Lafayette County right now are being taken by brokerage firms with oil-company-sounding names. As soon as those leases are recorded they are assigned to the oil company who hired the brokerage firm to get the leases. There are many reasons it's done that way so much of the time.
So now, everyone please jump in and comment on everything I've said that you think isn't accurate. I need to know.