We can give you some highlights from the conference call and a take from a well known analyst from Raymond James.
1) The DST test compares favourably with the first one done at Elk1 at similar depth in the resource (albeit the resource is quite a bit deeper at Elk4 compared to Elk1).
2) The condensate to gas ratio was more than twice that of Elk1 (5Bbls/MMcf) at 11.2 Bbls/MMcf. Since We are deeper than at Elk1, this suggest increasing liquid content with depth, which is consistent with gas sitting on top of an oil leg. There is more pointing to this, as became known during the conference call:
Lab analysis of the specific gravity of the condensate, at room temperature rather than the heated temperature from the well bore, indicated 48 degree API, very close to crude oil. The fact that the specific gravity of the condensate is increasing with depth increases the probability of encountering an oil leg as the company deepens the well.
3) Since they are deeper, it establishes a lowest known gas level at 7,402 feet (5,236 feet at Elk1). According to Wayne Andrews:
We continue to believe that Elk (a brittle, fractured, deep-water limestone fault block) was thrust and lays upon Antelope (a larger, porous, shallow-marine structure). Given the similar pressure regime, intense tectonic activity, and overwhelming evidence of faulting, we believe that both blocks are in communication and in fact part of the same Elk/Antelope structural complex.
4) There are visible signs of both fracture and matrix porosity in Elk4, which further blows away (if that was still necessary) an early interpretation from Ross Energy, which argued that Elk1 was build on a major fault line and hence it’s extremely high gas pressures were a one-off fluke.
Not only is fracturing common, matrix porosity is often better. This is important, because that ‘major fault line’ argument was perhaps the one argument the shorts believed in, or wanted to believe in. It is still touted on some message boards.
most importantly, the visible matrix (vugs, chalky limestone) and fracture (visible micro-fractures) porosity along with shallow marine fossil evidence observed in cuttings from the well within the recently tested limestone reservoir
5) In the conference call new info came to light that makes it very likely that the gas pressure will increase substantially and further signs of matrix porosity:
First, the company described pumping heavy mud with Lost Circulation Material (LCM), to stop the flow of gas and liquids into the well bore. The LCM works to seal porous formation, but depending on the type of material may not be as effective on fractures. The fact that the LCM was effective is a potential indicator of real matrix porosity, a very positive sign for reserve potential. However, and more importantly, the heavy mud probably caused near well-bore formation damage which may have hampered the flow rate of the well in addition to the drilling fluids that were being recovered during the test. Both of these give us confidence that the well will be capable of flowing at substantially higher rates.
6) The report is increasingly confident of it’s valuation, it has a net asset value (NAV) of $64.56. Basically, the increased share count are offset by including a liquid resource potential of 69 MMBbls at $15.00/Bbl (risked at 50%).