People have long known that the Niobrara is thick, rich in organics and thermally mature. Oil has flowed from the Niobrara since the dawn of the industry: Florence Field, near Canon City, Colorado, was discovered in 1876 near an oil seep. Florence produces from fractured Pierre shale, and part of the Niobrara formation. Oil pioneers also found the Niobrara productive at Salt Creek, Teapot Dome, Tow Creek and Rangely fields.
These fields were anomalous “Sweet Spots” due to the local geology and geologic structures that allowed the oil to flow freely with vintage vertical drilling technologies. In most fields the Niobrara section of the well was usually completed since it was above the more productive target reservoirs such as the Dakota “J” Sand in the Denver Basin.
Horizontal Drilling Arrives and the Niobrara Heats Up
The traditional view of the Niobrara as a tight reservoir all changed with the drilling of JAKE #2-01H by EOG Resources Inc. in the October 2009. This strike set off the Niobrara Oil Play. This well’s Initial Production figures were astounding, 1,558 barrels of oil equivalent per day and an average of 555 barrels oil per day over its first 90 days. The reason for this phenomenal production? JAKE #2-01H was horizontally drilled into the Niobrara and then fractured (fracked) using new technology to make the Niobrara the next hot oil play.
So is this discovery abnormal or is this the kind of production the oil companies expect when drilling a Niobrara well with new horizontal drilling and fracking technology? EOG Resources has since completed Elmer 8-31H at 730 barrels of oil per day and Red Poll 10-16H – 1,100 barrels of oil per day in the Silo field.
If the land rush that this discovery set off is any indication, these wells may well be typical of the production that can be expected from many other Niobrara wells.
How much money would I get if I sign a lease?
The answer to that question is of course dependent on your lease, however you can get a general idea of what your royalties would be by making some calculations with some industry and Niobrara play standard figures.
- Royalty% = 1/6 (this is what Chesapeake Energy is currently offering if you sign directly with them, industry standard is only 1/8, however the State of Colorado received 1/5 for their Lowry Bombing Range property)
- Ownership% = 100%
- Acres = 10
- Field Spacing of 360 acres
- Unit Size = 360 acres
- Number of Wells in Unit = 1
- Oil Price = $100
- Production = 500 bopd
Daily Value = (Production * Oil Price) * ((Acres/Unit Size) * Ownership%) * Royalty%
(500 * 100) * ((10/360) * 1) * (1/6) = $231/day
That’s not bad for a measly 10 acres is it? The production figures used are of course Initial Production so you can expect production to decline over time, but it’s still very impressive to see the magnitude one of these wells could be worth to a mineral owner …and lets not forget, there can (and probably will) be multiple wells drilled into a drilling unit of 640 or even 1280 acres! So the math can only get better!
Lets not forget about taxes!
So you have finally gotten a royalty check… but there are deductions. The tax man wants his share, and there are quite a few of them lined up with their hands out. So who are they?
It is highly recommended that you go to visit our friends at the Mineral Rights Forum Web for a very nice detailed breakdown or Royalty Statements and Taxes, but a quick summary can be found below. (following bullet text credit to Mineral Rights Forum)
- Severance Tax – Most (but not all) oil and gas producing states levy a severance tax on all oil or gas production. This tax is based on either the volume or value of the production. Royalty and mineral owners pay their pro rata share of these mineral rights taxes. You’ll notice these severance taxes deducted on your monthly royalty revenue statements
- County Ad Valorem Tax - Ad Valorem (Latin for according to value) taxes are levied at the County level and are generally viewed as a property tax on mineral rights, similar to the tax you pay on your residence. In most states, this tax becomes payable only when minerals are producing (as opposed to non producing), and are billed and collected once per year.
- Federal Income Tax – Under the IRS code, royalty revenues are considered ordinary income and are taxed as such.
You can reduce your tax exposure using the following methods:
- Depletion Allowance – The depletion allowance is one way to accomplish this. Since minerals are a finite source and will eventually play out, the IRS code generally allows royalty owners to deduct up to 15% of the income from their mineral interests.
- 1031 Exchange – 1031 exchanges are a great way to defer paying capital gains taxes on the sale of mineral rights. This type of exchange is based upon section 1031 of the IRS code which allows capital gain taxes to be deferred on the sale of properties like mineral rights which are then exchanged for other properties considered to be “like-kind.”