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Permalink Reply by Two Dogs, Pirate on February 10, 2009 at 15:21

Depends on the formation that they are drilling to.

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Permalink Reply by herefordsnshale on February 10, 2009 at 16:03

To drill into the shale

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Permalink Reply by herefordsnshale on February 10, 2009 at 16:17

I'm wondering about this because there is about 90 acres in my section that is not leased, the leases on the remaining acreage start expiring in October. The land is in a hot area of DeSoto Parish with drilling all around.

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Permalink Reply by Dion Warr, CPL on February 10, 2009 at 19:26

KB:

This brings up a good point. Lets assume for a moment in the above example that all leases in the unit described are at 1/4 RI. CHK's net revenue interest (NRI) would be 75% (0.75). If the minimum cutoff is 75% leasehold, CHK's Unit NRI would be 0.5625 (0.75)(0.75).

Chesapeake's overall revenue stream before payout (BPO) would be CHK's NRI plus carried interest (from the unleased parties, UMI). After payout (APO), CHK would only receive the NRI, and the UMI owners get the rest (less their share of ongoing costs, as same come up):

CHK (BPO): NRI + UMI = 0.5625 + 0.25 = 0.8125
CHK (APO): NRI = 0.5625

Let's change the example, though. Herefordsnshale states that leases start expiring 10/09. This means that some of these leases were taken in 2006, when the average RI was approximately 1/5. If the leases holding half of the unit were taken at 1/5, the values now change:

CHK's NRI: (0.50)(0.80) + (0.25)(0.75) = 0.40 + 0.1875 = 0.5875

CHK (BPO): NRI + UMI = 0.5875 + 0.25 = 0.8375
CHK (APO): NRI = 0.5875

This is a difference in CHK's revenue stream of 2.5% of the production over the life of the well. At a EUR of 52 BCF per section (unit), and assuming a constant $7 for calculation basis, the difference in revenue stream is 0.025 x 52,000,000 x $7. = $9.1MM (!) That covers the cost of a well.

This illustrates two things. First, WI/NRI analysis (and the effect of lease burdens) is essential to O&G in determining their operations, and where they drill (or drill next). Secondly, whatever the 'cutoff' is, the O&G company and its determination of well economics is particularly sensitive to this NRI.

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Permalink Reply by herefordsnshale on February 11, 2009 at 13:51

Thanks KB and Dion for the input. Actually a lot of the royalties were 3/16 (mine and two more owners that I know of). 440 acres of the section is owned by Hancock Forest (formerly Timberstar, formerly IP, they were leased first, I don't know what their royalties were or when their lease expires, the rest of us were approached in September of 2006 so Hancock's lease probably expires in August or early September. Using Dion's formula the 3/16 royalties makes drilling seem even more attractive for them but it looks like they're going to let the lease expire. They still have time to drill but they're going to have to get their butt in gear to make it happen.

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