Continuing the discussion from Permian Basin, Loving County Texas: I have small working interest in all of Sec 28, Blk 29, PSL Loving Co. that I want to sell—any help on valuation would be appreciated.
Yes and yes to both questions.
We considered selling our WI at one time, and just for a ballpark figure our CPA had us give him the total amount received over the last 6 months, and the total amount spent on JIB’s over the last six months.
He then had the net for the past six months.
He then took the average net and multiplied it by 36 months or (3 years) and gave us a place to start.
I found in our case the operator was willing to pay more than an outside party who was not involved. If you can find out other WI parties they might be a good place to start with looking for a buyer.
Also our attorney had to review the JOA to make sure there was not some sort of language or clause mentioned in the JOA that says the operator has some sort of first right when purchasing the WI.
I hope this can give you a bit of a start.
I’d say Alexis is more less on the right track IMO. Existing production goes for some multiple of monthly cash flow. As the existing well is flattening out a bit, I’d value it at 60 months net cash flow.
I’m assuming you are talking about selling all of your interest in Sec 28. In that case, there is a lot more value in the wells that haven’t been drilled than in the well that have been drilled. And as Alexis points out, the person most likely to pay you for undrilled locations is the operator. They control the drill bit. So give APC a shout.
COG bought RSPs undrilled acreage for something crazy like $65k/acre 10-15 miles north of there. I’d guess you could get $20-25k/acre here.
So…60xNCF + 20ksomething per acre. That’s my guess. Hope that helps.
It helps a lot—thanks!
@NMoilniy, where does the 20K-25K figure come from? Is that basically 1/3 of the operator’s lease sale price (if assuming a 25% royalty)?
Many news releases report operator-to-operator lease sale prices. I’ve had difficulty trying to understand how to use those $/NMA figures to come up with a value from the mineral owner’s perspective.
Long story short, it’s a SWAG at what a win-win price might be to lease in this area at 1/4 royalty. Very little math involved. The rock in the RSP acreage looks better, and I thought I heard a good portion of it was 1/8 royalty. Sept BLM lease sale confirms that NM/TX border rock at 1/8 can go for a whole lot. This doesn’t look quite as good and I assumed 1/4 royalty, plus big chunks sell for more than small chunks on a per acre basis normally. So I mentally scaled down quite a bit. Maybe too conservative. But if you are looking to sell your small WI position, and somebody will give you 20-25k per acre for the undeveloped portion, IMO, you at least aren’t getting robbed. If Roy sold for just the value of his current well, he’d be getting robbed.
I think its a bit hard to translate lease bonus pricing to mineral pricing, assuming your minerals are leased and you are looking to sell. The lease bonus an operator will pay is non-linearly related to the well performance, as they are carrying all the costs. When you are paying $10m to drill a well, a 1MBO well may be worth $14m in NPV10. A 700kbo well, $7m in NPV10. A 500kbo well, $2m in NPV10. Operators will pay bonuses for the great stuff that are much higher than for the good stuff. For a leased mineral owner, the value of the minerals/royalty is linear with well performance (assuming everything else is equal). A 500kbo well is worth 1/2 of a 1MBO well. So there is no easy way to correlate bonus to mineral pricing across the board. Ratio of the two will change depending upon well performance.
That’s a very clear explanation of something I had never understood. Thanks for that—exactly what I was looking for.
Yea the per acre prices you read in the news when an operator sells their operations to another operator is not a good way to gain insight into the value of their minerals. While they translate those prices as per acre prices, they are factoring all leases taken by the first operator, all wells drilled by the first operator, and all infrastructure and equipment as well, so a lot more is lumped into that number than just the value of the mineral rights.
I wish it was easier for mineral owners to understand fair market value of their minerals, but its not.
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Thank you, @Cam and @NMoilboy. This recent Forbes article references $75,000/acre and later in the article $77.6 million for 9,100 acres (which equals approx. $8,500/acre). Can anyone with industry knowledge provide insight into what these figures reflect? I don’t think it’s so simple as equating it with the $/NMA that we mineral owners often use for leases and mineral sales.
Here’s my opinion, I’m sure I’m wrong on a few details:
The $75k an acre number represents Concho buying RSP on the M&A side and the early Sept NM BLM lease sale. When Concho bought RSP they bought X barrels of production a day plus Y undeveloped acres for $9.5B. The implied price per acre is the total cost minus the value of the existing production divided by the undeveloped acres. I don’t know the exact math somebody used, but you probably value the production at around $40,000 per net barrel a day. So, lets pretend that RSP made 65,000 bopd and had 92,000 acres.
$9.5B minus 65,000 bopd x $40k/bo = $6.9B divided by 92,000 acres = $75k/acre
Effectively, Concho took over RSPs undeveloped (but likely to be HBP) leases for $75k/acre. That seems like a lot. But here is the important part, this is all in Loving county up by the TX/NM line. In the best of the best of the Delaware. I don’t know what the average royalty is on those leases, I thought I had heard it was relatively low prior. But that’s what acres cost where you might drill >30 targets over the life of development, if you are an optimist .
For the BLM lease sale in September, Matador and others paid up to $90k/acre for 1/8 royalty leases along the NM/TX border. In the best of the best of the Delaware. Similar to the RSP deal but lower royalty. For an operator, the great stuff is worth a ton on the leasing side. Especially great stuff with a royalty less than 1/4.
The $8500/acre number represents what Rosehill paid for acreage down by Coyanosa in Southern Delaware. On the edges of established production. It’s probably going to be ok, but its not going to be great. Less targets to drill, less good well performance. On the leasing side “not great” means things are pretty cheap. Rosehill has a portfolio that includes some Lea/Loving county stuff, but the acquisition touted in that article is not that. Its not in the “core” of the Delaware. It’s in Pecos where mineral owners are signing leases for well under $10k/acre.
There is a lot of economic diversity in the Delaware. The best leasing areas are also the best mineral areas. But you can’t equate one value to the other. It’s a different thing.
For example…If you sign a 25% lease, your land is worth less to the operator per acre and worth more to you per NMA (than if it were 3/16 or 1/8 etc). The two things are actually moving in opposite directions as a function of royalty.
IMO, first of all, people should think about mineral acres in terms of royalty acres. It will limit the number of apples/oranges comparisons. If your neighbor, who just signed a 25% royalty lease, just sold their minerals for $30k/NMA and you think you should get the same for your old 1/8 lease, you are going to be irrationally disappointed. You are going to get offered $15k/NMA. But both get $15k/nra.
And then I think on absolute numbers you can really only compare leasing prices to leasing prices, and mineral prices to mineral prices. Though, again, higher leasing equals higher minerals etc.
So yeah, this was real long-winded (apologies, Monday caffeine) but you are right, it’s not so simple to compare mineral and leasing prices. They correlate but they don’t equate.
Thank you, NMoilboy, for the detailed reply — very informative. I saw the BLM New Mexico September lease sale, too. I was amazed by the numbers. I counted 14 leases with bids over $50,000/NMA, including 3 over $80,000/NMA. Since the BLO uses a 12.5% royalty, should we halve the bonus to “translate” it to our standard 25% royalty? Or are there are other terms/peculiarities in a BLO lease that complicate making an apples to apples comparison of bonus values?
There are not, as far as I know, any peculiarities about a BLO lease other than the fact that it is good for 10 years. Thus is worth even more, though you’d kind of hope that all > $60k/acre leases are getting developed in their primary term.
Without getting into a spreadsheet with # of wells and their forecasts and doing the math, it’s hard to make a simple comparison of a lease at X royalty with a lease at Y royalty from the operator side, which is who is determining the bonus amount. Sorry, above I should said that’s it only simple to compare leasing prices if the royalty is the same.
From the mineral owner side its pretty simple, it’s like you say, twice the royalty is worth twice the revenue (post-bonus). That’s why its so much easier talking leased mineral prices in royalty acres. It makes everything linear.
But for what bonus the operator should pay, its a different story. A 12.5% lease gets them 7/6 of the revenue of a 25% lease, minus all of the same operating and drilling costs. In some places that might mean a 25% lease is worth half of a 12.5% lease, but that’s not the case everywhere.
For an operator, a 12.5% lease on an acre has the value of a 25% lease on that acre plus the value of a royalty acre. (since the difference is 1/8 royalty on an acre). Maybe that is wrong, but that is how I think of it. If I have a feel for a lease bonus at a certain royalty rate, and the price for a royalty acre, I can sort of translate to the bonus at a different royalty rate without doing anything crazy.
Does that make any sense? Sometimes it barely makes sense to me.
Oh yes, I forgot BLO leases have 10-year terms. So I would think to “translate” to what most of us come across, not only should you halve the bonus due to the BLO royalty of 12.5%, but then you should take one-third of that, since the term is 3.33 times longer than the typical 3 years?
As far as royalty acres, I hear that’s what the folks “on the other side of the table” use internally all the time. Especially buyers of minerals with an existing lease but no production.