After updating the 4Q13 well results (still in progress) and I probably won't finish today, some observations, from corporate presentations, press releases, news reports, Bakken well data:
- when I first started blogging about the Bakken, I said that a Bakken well probably "paid for itself at the wellhead" after 100,000 bbls; then with more expensive wells, I moved that figure to 150,000 bbls; I now think that Bakken wells "pay for themselves at 75,000 bbls" -- partly due to the longest stretch of high oil prices in history; narrowing spread between WTI and Brent; cost of wells coming down
- there are "no" dry wells in the Bakken
- "payback" is hell -- more on this cryptic comment a year from; until then, don't ask, don't tell
- Enerplus Resources is the biggest surprise; some huge wells
- several oil fields to watch: Banks, Truax, Antelope, Mandaree; some of these are the "same old names," but Mandaree is interesting (an Enerplus Resources field)
- Statoil continues to have huge IPs; moderate wells in the long run
- BR has huge IPs; great wells in the long run
- CLR remains an enigma: moderate IPs; moderate wells; but lots of "seed corn" planted
- KOG has highest cost wells, but consistently great wells
- natural fracking is the operator's best friend, but if you don't have natural fracking, max out sand -- 10 million lbs is a nice start
- number of stages may be less important than total amount of sand
- the increase in the number of perforations (I can't imagine that adds much marginal cost)
- the experienced roughnecks are correct: they've never seen anything like the Bakken