Member Info for mbarnholdt

I am going to try and watch it, so I will post anything that is of note beyond what was in the september viewgraph pack.

I didn't see a whole lot of new information in the updated corporate presentation. Did anyone pick up anything of note in the question and answer session? Thanks, M.

Not sure if they had enough dynamic data to do a material balance calculation. My guess would be they used volumetric methods to start out. I think they did mention that they did not observe a transient flow effect that would indicate bounding of the reservoir, and some of that might be reflected in P50 or P10 calculations.

I am hoping that since Cascadura came in overpressured, that they have done the proper planning, any rig modifications, and have on hand appropriate pressure control equipment in the event this well is similar. Would guess that since the plan is to move on to Cascadura Deep lead after Chinook, and from same surface location, that they have done their homework on the drilling side.

I sure hope so; the delay in Chinook spud has been bothering me for awhile. Wondering whether it was lock down related, remote location, rig modifications, etc. When it slips and slips, it tends to gnaw at me. I sold some shares awhile back, covered all my initial costs. Still have a nice stake of "profit" shares. Gas contract + well successes + production commencement is a sequence I'd like to see. Still don't see a lot of downside over the long term, unless some of these items are delayed and people start losing patience.

Anyone know if Mr. Baay has any upcoming webcasts? I have watched a few of them and they are most helpful in getting up to date on ongoing activities. Thanks, Mike

Finally cracked the 1$ mark here in the US, currently at 1.02

My mistake, GLJ does apply a location and quality differential-I missed the footnote late in the report. Hard to tell how much it is, the price for 2020 looks sort of low (reference), but it looks like it comes up in later years to something a bit more reasonable for a market that is short of gas. I think one of the trains at Atlantic LNG was running short of gas for awhile also, unless things have changed recently. A good situation I think for a gas producer with solid reserves. I heard Shell is looking for a way to pipe in some gas from Venezuela, but I think that is a super long shot at best. Would appreciate comments of those more knowledgeable than I. Thanks

Afterthought: some european gas contracts and a few south american ones I have seen in the past were indexed/priced against No. 2 heating oil mostly, which was considered a substitute fuel. BOE probably makes a bit more sense there. I think PB uses it mostly to give frame of reference, which is sometimes useful. As a yank, it still helps me, especially in dealing with the metric measurements in europe which I know, but my brain doesn't convert as easily to scale for comparison.

Some of the gas shale players in the US used to highlight gas equivalence, to highlight their focus on gas early on as well. Good point on the taxes-this looks to me like a tax royalty contract, so the calculation to get to net (of royalty and taxes) barrels is fairly straightforward. In a production sharing contract, its quite a bit more complex, and was based on economic entitlement. I thought I noted also that GLJ used HHub as the marker for the economics calculation (I think)-I would have thought they would have used that + some sort of price differential for the local market, which I think should be better than the US in terms of pricing. If that's the case, as soon as we get the gas contract inked, they should be able to use the long term contracted price, which should yield better economics on the reserve calculation (for economic limit tests, etc.). Let me know if I misread on that point.

I have seen ratios of 5.8 to 6.0 used in the industry over the years-it was based on energy equivalence rather than price.

Did Mr. Baay, in his comments mention spud status/date for Chinook?

A good point, one that I didn't pick up until I read part of the technical paper that I think was put together by TXPs(?) Chief Geologist. Think Turbidites-think the big thick sands of the Gulf of Mexico. I like their exploration focus, in that a lot of the leads they have are wells that were logged/not tested back in the 60's or so, so you are working an area known to be charged (PB quote), with technology that has come quite far in the last 50 years. I noted that in the statement they came out with that they did not note any boundary effects in the reservoir(s). I would guess that when the reserve report comes out that the numbers will be based on volumetrics, and there will probably a large difference between proved and 2P, and probably a good chunk still in unproved due to offset/lowest known limitations. They will probably have a better feel for what's in place when we get some dynamic data (flowing production/psi) and they can do some material balance calculations. When I first heard Mr. Baay talk about it, and due to the similarity in well tests, that the two sands tested were connected vertically, but now I'm not so sure. Anyone have a good feel for this? It would be interesting to me to hear what they reckon are porosity and permeability of the areas that they logged, and how they have it mapped. I am probably wildly optimistic, but I'd like to see a 2P number of a tcf plus. I love to see GLJ's work papers to the extent they will share sometime in July.

That was my thought as well.

No really big reveal as some of us had hoped; he did give me some comfort around meeting the drilling & seismic obligations, license risks, and management of in response to a question I had.

Most appreciated, thank you.

Mike

Did I see mention of a web seminar for Thursday or did I misread? Anyone have the time and/or the link? I'm also an ex-Shell guy and shareholder. Thanks, Mike