Something to think about in 6 weeks.

I hope she doesn't mind but Ya gave a really good post on the FAR thread under the thread title "What are we worth" and I thought it might also be relevant to us when some results come through in 6 weeks so it might be an idea to put it in your favourites for reference.

It kinda highlights what CVN might be up for.
Eyes might not be happy though.
So here's Ya's post.


There's a bit of confusion on this topic.

Contingent resource is not P90/ P50/ P10 OIIP, its quoted as 1C/2C/3C.

After which, to bank a reserve, (ie 1P/2P/3P) they need actual DST/production data or BOPD's. Until then the discovered HC's will b classed as Contingent.

The P50 etc only applies b4 one discovers HC's in the well (ie desktop analysis/3D seis studies etc).

Once the discovery is made, the Contingent resource can be booked by an Operator, based on fluid sampling/ gas-oil ratio, oil-water contact clarity/ pressure/ reservoir properties/ SWC properties/poro/perm etc.

Cairn have indicated that the preliminary estimates of the Contingent resource range from P90-150mmbbls, P50:330, P10: 670 for SNE-1. This bodes well from what they've found (bar the thick gascap).

Which means from the data available so far, the JV should b able to bank a Contingent resource in the range mentioned above for the Albian Clastics.

Once the 2C resource is released they can apply a 10$/bbl metric.

For undrilled prospects with lower confidence most analysts use a $5/bbl metric for the OIIP estimated.

Another point is that an Oilfield cannot be Commercial without valid data from DST & reservoir pressure data from nearby wells.

All they are suggesting is that the resource in place is there & logs/sidewall core analysis indicates that it should meet their business criteria for Commercial development (ie field size in mmbbls).

One needs multiple wells & an extended well test data to get to actual commercial or development phase.

Example: At WPL's Chinguetti, a higher reserve was initially calculated (ie 2P: 123 mmbls 100% basis). After a few months from first oil in Feb'06 the flowrates didn't sustain 70k bopd, dropped to 23k bopd and this made the Operator to release a resource downgrade of 50% (ie 2P-53 mmbbls & 2C: 24 mmbbls).

So in the absence of any DST/production testing data conducted by the JV at both wells drilled in Senegal, best case scenario is for a Contingent Resource, which can b commercialised at a later date (40-60 months minimum to first oil, till then its all stays in the ground). Albian at SNE looks fairly straight forward. Will find out about the Aptian in the coming days.