I see a lot of posts on this so thought it might be helpful to give a general guideline of how mineral buyers evaluate a play like this. The Leon/Robertson core has enough production history now to generate a satisfactory type curve (disclaimer: I am not a PE.) Using a composite curve of Aethon & Comstock’s wells under following parameters: Well set: 21 wells, 8800’ perforated lateral being average of well set DCA model: Modified Arps with exponential terminal decline at month 40 (B factor of .96 before terminal rate) 450 months, P10 EUR: 44 BCF P50 EUR: 38 BCF P90 EUR: 36.4 BCF. Pretty tight range ran on 500 bayesian trials. To get a engineers stamp on that it would have to be the P90 case but buyers can rarely transact that way so we are rolling with the P50 EUR. As for the DCF model, have to make some wide assumptions here. I am basing this on:
- $2.50 p/mcf. I realize HH is over $3 right now but most people are going to deal with a range of wellhead realizations. Also the unfortunate realization that the “cost-free” royalty clause in your lease is probably worthless and will you will still get hammered with post-production costs unless you have a very good attorney who has kept up with the clusterf**k case law here.
- 7.5% Sev tax, 2.5% ad val
- Assuming a ¼ lease and a 1,000 acre unit (many of these units are much larger and I know most people did not get a quarter but have to use something) I did this evaluation on a 1 acre basis so NRI = 1/1000*.25 = .025% NRI
- No fed income tax calculated.
- PV25 discount rate, this is usually higher than a PDP deal but the strategy here seems to be buying ahead of the bit to capture the full royalty stream of the first well. High pressure, high volume gas wells will hold most of this land for the next two generations so it could be a decade until we see much infill and down spacing outside of a few tests here and there. Could get interesting if the Haynesville works alongside lower Bossier though. The results surprised me a little, especially since I have heard the number 10K p/a thrown around quite a bit. While not a bad deal for a buyer considering the upside of future locations and multiple benches, 10K per acre is around a 4 year pay out with a negative PV value and total ROI of about 2:1. One thing to consider is if the offer is net mineral or net royalty acres. NMA = 1:1 NRA = 2:1 @ ¼ royalty rate. You can google the calculation if you have a different RR in your lease. But the point is, 10K per royalty acre is only 5K per net mineral acre. Of course, these folks don’t play to lose. They are levered to gas prices at the low end of range and have multi-bagger upside down the road with infill locations. The gamble is tied to Comstock etc. ability to make this play economic. Paying up for a one-off HBP well is a risk. As it has always been in this business high risk necessitates high reward. I don’t have a dog in the fight. Just hoping to lay it out for folks so that they can have a little bit better idea of how the game is played and can maybe play it to their advantage. tc.pdf (19.1 KB)