I own mineral rights on a small (.4856 acres) in Kingfisher, OK. Section 22-16N-07W. The lessee is Core Resources and the lease is dated 11/2017 with a 3/16th royalty.
We have not received a payment, but all of a sudden have gotten numerous offers to sell between $6,500 - $10,000 per acre. I am attempting to run a DCF model based on production to model the economic worth, however:
I have looked at all the big drillers in the STACK, but cannot find any information regarding if someone is looking to drill and when my land would be pooled.
How do I find out if a company is looking to put up a well and pool my land?
I do not think my lessee is a direct operator. If not, how would I get my royalty?
“I own mineral rights on a small (.4856 acres) in Kingfisher, OK. Section 22-16N-07W. The lessee is Core Resources and the lease is dated 11/2017 with a 3/16th royalty.”
You should have gotten paid the bonus amount for your lease.
If you are leased, then you will not be pooled within the time frame of the lease.
Good news is that Paloma Partners has just filed a Location Exception 201806353 at the OCC for a horizontal well in section 22. They have filed another one 201806352 that also says location exception and looks identical? They just had a pooling with offers of $3000 3/16, $2750 1/5 and $0 1/4. One year in which to spud the well from August 27, 2018. Anyway, you will probably have a well soon which is why you are getting offers to buy. If you are thinking about selling, you need to think past one well (and also capital gains tax if you do). Section 21 just to the west of you has increased density of nine more wells. (That is also why you are getting offers to buy). They hope you don’t realize the future potential.
I appreciate the info. Yes, my mom got the lease bonus payment.
I actually spent quite a bit of time on the phone with Paloma today. A lot of good information. I just need some operating expenses, transport and LOE expenses to accurately forecast net income.
Yes, they said 2 wells initially, with the drill site built out.
I calculated my ownership off the following:
640 acre pool
.4865 net acres owned
3/16= 18.75% royalty
=.000142656 decimal interest
Therefore I will gross .000142656 of all revenue, both gas and oil.
I get 0.00014252929- pretty close
The formula is net acres/spaced acres x royalty x % perforations in your section. If the wells are only in one section, then that last component is “1”. If multi-section, then you have to put in the percent that is in your section.
Also have to take out OK tax and your Fed tax from the royalty check. You will get some of the OK back if you are out of state an maybe some if you are in state.
Your royalty check will start out “high” as it will include about the first six months of production and sales. The next one will be more realistic. Horizontal wells start out with higher production and then will drop sharply and then level out at fairly low rates, possibly for decades. Since you know that you have two wells to start with, consider that you will have more in the future and factor that in.
If you sell, you will have to pay capital gains tax of 15-20% on the profit. If you have good records of the value when obtained, then it will be less than if you have no records. The IRS will consider the whole sale taxable unless you can prove otherwise. There are tax benefits to passing minerals to the next generation in a will and getting the “step up” value
While oil valuation is new to me, finance is not. I know all about step-up basis. I have been an equities and real estate investor since a teenager (33 now). I work as a private equity financial analyst and was a financial adviser in a previous life (boring after the Army and firefighting).
Does anyone have any good resources for all the wells in a certain section or area? I am trying to gather comp data.
I am doing comps on oil wells in the area. Basically pulling whatever data I can find and creating a common time zero for all wells. As soon as I get enough data points, and based on similar geological characteristics, I can forecast life span, production and depletion rates. Of course I assume a wells lifespan is based on numerous factors including fixed costs, variable costs, price of oil, damage and unforeseen risk (governmental, natural disaster, ect). From my understanding, this area has a lower break-even cost then other drilling locations in the nation. Will my projection be accurate? No, no projection ever is. Will it provide a good DCF to judge the possible investment…probably.
I really need to figure out the expenses that could be passed along to me, such as transportation and marketing. The lease I have is not clear.
There are several subscription services that are useful in finding the production from other wells near you. However, they are very expensive. The OK tax site gives the last 12 months production from wells for free and you can request farther back for a fee.
The wording of your lease is actually quite clear as to whether you will be charged post production fees or not-it just doesn’t tell you the amounts. They can start off rather low and usually increase with time as gas pressure drops and it costs more to compress the gas to keep the line pressure up. Each company has its own contracts with pipeline and gas facilities companies for what the transportation, compression, marketing, etc. will be and that data is not public.
Sending you a private message.
The site gets better, the more I use it. The search magnifying glass is very helpful. Also, it is organized by county within the states. Just play around and you will find all sorts of useful things.
The value of the mineral via production will be dependent upon the actual production. I just did an appraisal of minerals just over the line in the next county north (a charity owns the interest and I do the appraisal annually). Drilling in 2014, it produced only 4 years and was shut in. The oil decline curve collapsed upon itself rapidly and I had predicted a year ago it would go to zero in 18 months. It did it in about 14. The gas production was low but stable but the expenses of hauling water pretty much ate up the “profit” and you will be subjected to post-production expenses. In the end the charity made about $2,000 per net mineral acre over the four years.
OTOH, it could be a very good well, a “barn burner” if you will. And make several times the offers. But you have to weigh the risk of doing so. And you can crunch DCFs till you are green around the gills, and even run Monte Carlo simulation but nothing is going to predict the actual production.
In any event, it is a very small interest. You have little to risk, and no it won’t make you rich in the best of times. If me I’d not worry about it. If someone is dumb enough to offer over $20K…then I might elect to take the cash as certainly it would have to be a huge well to get your money back in less than 5 or 10 years. Otherwise sit back and see what happens…
I think it is pretty much impossible to accurately estimate production in advance. I estimated a new well last year to pay about $2K/month, a professional landman said I was wrong by half, he said it should pay at least $4K/month, when the well came in it paid $200/month, that was the bad news, the good news is that the oil company plans to drill 6 more on the same spot so there is still hope!
Yeah brokers “landman” for oil, always paint the rosiest pictures. When your income is based on sales, you have to get people to buy/sell.
I agree 100%. Every single financial model is wrong as soon as it gets underwritten. However, it is still good practice to understand modeling. Hell, every professional investment is dictated by one, especially PE and VC (which is what drilling a well is!).
I have heard of horror stories of royalty owners not getting checks. It seems like the reasons varied from outright fraud where companies simply did not pay, to post-production expenses eating into any profit.
“They hope you don’t realize the future potential.”.
Come on … $10,000 doesn’t seem out of line for 7W acreage that is that far north and in an urban setting.
An alternative is they are making a fair offer based on risk, timing and returns and are realistic about the future potential. Just because some public company says everything si great and all the acreage works doesn’t mean it true…
While you are fortunate that Paloma filed a location exception, the timing until the mythical mulitwell density project is highly uncertain with a P.E. backed group like Paloma. That’s generally not the typical P.E. model, even as the PE model is changing. So if time value of money is meaningless, then you definitely can wait for Paloma to flip their acreage, go public and come back and drill, or be happy to gain a step up in basis and fear Capital Gains tax - which may or may not be 15%-20% depending on you ordinary income.
Which by the way you will have to pay ordinary income tax on your royalties.
Furthermore the costs of acquiring a small parcel is much higher than a larger parcel as the cost to run title isn’t much different for one acre or one hundred acres. The reality is you likely got blanket offer letters based on the regulatory filings and when they hear how many acres you have, most of those that sent letters will not be able to transact at a reasonable price per acre due to transaction costs. There simply isn’t enough acres to spread title and legal fees across.
I can go on and on, but that was a disappointing statement.
So True Jeffrey, when someone has to go out & run the title doesn’t matter how many or how few the acres are, cost is the same so what does matter is how many acres the cost gets spread over. And then if there are legal costs (like we had), for the court and a lawyer if you have only a couple of acres the legal fees could be as much as you get on a deal (selling).
The reason the number of acres matters, is because someone isn’t going to spend the money to run title if they think there’s a very small amount of acreage. Alternatively, they can make a very low bid assuming the risk of title and that on occasion they will be wrong.