Member Info for KeithOz

Thank you Thunderstang for providing a new link to this report, I had not read it for about a year, and could not find it last week when I wanted to refer to it. It is rather long, and contains a lot of info about offshore licences which are not relevant to present-day PRD, and after 9 years is a little out of date. The Guercif permits at that time were called the Merada permits. Imho, these are some of the more interesting bits, which I will need to post as more than one section due to length.

Previous geochem surveys, pp10-11.

Two micro-seepage surveys were carried out by Geo-Microbial Technologies in 2006 and 2007. A total of 32 traverses were carried out over a 2500km2 area and 731 soil samples were analysed in 2006 and 2007. These identify several hydrocarbon types in the Guercif basin: thermogenic dry gas and some condensate around the GRF-1 well; oil and gas/condensate around the MSD-1 well, over the Jezira anticline and in southwest; and oil in all other anomalies. Particularly interesting is the abundant seepage in a large area around the TAF-1X well which appears to be oil rather than gas. The anomalies cover a larger area and have higher oil concentrations than the anomalies elsewhere. These surveys confirm there is an active hydrocarbon source system in the basin.

TransAtlantic’s regional analysis yielded a number of large untested surface anticlines (up to 25 km in length) with associated surface geochemical anomalies. Its work confirmed the presence of source and reservoir rocks, seals and traps. TransAtlantic attempted to analyze the timing of oil maturation versus migration and trapping. In addition, it believed that two of the four wells drilled appeared to have missed pay opportunities,

correction - vugs have less effect on permeability. An edit function would be very useful

That posted itself, so I'll continue. Porosity can be reduced by compaction and diagenesis, which is later alteration by fluid flow - this can fill up the pores with mud or crystals.

Permeability is a little different, in that it relates to the connectedness of the pore space, and thus the ability of oil or gas to flow through the rock. It is measured in millidarcies, or mD. or if you are really lucky, Darcies - which are of course 1000 mD. Permeability is dependant upon a lot of different factors, including the pore size, connectedness and orientation. Another factor is the extent to which a sediment has been altered over time. This alteration can be good or bad for permeability. In particular, permeability can be increased by fracturing during tectonic events (lots of that in the Guercif basin). Rather surprisingly, some of the oil reservoirs in the North Sea have had their permeabilities improved by deposition of fine clay, which has prevented later crystal growth into the pore spaces.

Vugs have been referred to. These are spaces larger than the normal pores, which are due mostly to dissolution of crystals, fossils, etc, leaving a hole. The presence of vugs increases porosity, but has less effect on porosity unless there is also extensive fracturing which has the effect of joining up the vugs.

I'm afraid I have found little info on the porosity, permeability and charge of the Gurecif Basin other than that I posted yesterday from the ONHYM website, but that does look very promising. We would need to see thin sections of reservoir rocks to really know what is going on, plus of course some extended flow testing.

A Texan called Jerry Lucia appears to be quoted by everyone else, below are two links that readers might find interesting, they have lots of photos of rock types, and easy to read charts. This one covers rock types and porosities:

https://www.beg.utexas.edu/lmod/_IOL-CM07/cm07-step02a.htm

and this deals with permeability about half way down:
https://www.beg.utexas.edu/lmod/_IOL-CM07/cm07-step02b.htm

Enjoy your weekend.

I've been meaning to get back to Mr Darcy, but have had to wade through pages of stuff related to Mr Troll first.
We need to look at two important concepts that underlie the amount of oil you can squeeze from a lump of rock, assuming that it already has oil in place (that is the 3rd important concept, charge).
Porosity is the amount of space within the rock that can be occupied by oil or gas, measured in %age space. Typically oil bearing strata will have around 10% porosity, up to 30% if you are very lucky. Generally, the larger the grain size, the greater the porosity.

I have been a JAY holder for years & years , originally buying in at around 20p, so you can tell that timing is not my strong point :-) This week I had some spare cash from a recent sale, and took the decision to double my JAY holding. Why? I am hoping that my timing is a bit better this time, since I am expecting a number of things to actually start happening and result in a very different company profile by the middle of next year. Below is what I think these are and why - I would welcome comments from knowledgeable posters, but not from trolls!

Q$ 2021. Completion of Dundas funding. In order for construction to start next spring, this has to happen very soon in order to allow purchasing of long lead time items, which may be in short supply and/or slow to transport to Greenland. Also, JAY have some nice low-interest funding offers on the table. As global interest rates start to rise again, they may get withdrawn, so JAY needs to act pdq. SPAngel has a 37p NPV10 for Dundas, but this is based on an ilmenite price that is l lot lower than the current price. The actual NPV10 may be around 50p. It is quite normal for a project at this stage to be valued by the market at a fraction of the NPV to take account of project risks. Once construction starts, this risk discount should evaporate very quickly, since from both a geological and engineering perspective this is a pretty straightforward project.

Q1 2022. Continued exploration in Finland, very likely with discoveries. Although not of great immediate commercial value to JAY because of the earn-in structures, these will provide some good psychological support that JAY is on the right track with the exploration work.

Q2 2022.
Dundas construction starts.
Disko-Nuussuaq. As a geologist, this is why I bought into JAY, not Dundas. The potential here is huge. In May this year I wrote to the company berating them for not getting in the drilling team now that the Greenland Covid restrictions were relaxed, and they already had identified drill targets pre-Covid. I was told to wait for some news - we have now had that with Kobold. Kobold are very keen to crack on with this project, since they can use it as a showcase. The RNS talked about them doing further exploratory work in 2022, and drilling in 2023. There are already some well defined and very large conductor targets, which were going to be drilled in 2020, until a certain virus came along. It will not take very much work by Kobold to verify these and get to work drilling - which I expect to see next season, not 2023. These potential orebodies are very similar geologically to those being evaluated by Kavango Resources in the Kalahari Suture Zone in Botswana. If you are interested in some of the technical stuff and valuations of these, have a look through my posts on the KAV board here.

Q3 2022.
Dundas construction finished, ready for 2023 operation start.
Disko first assays, delineation of further targets for ne

Are you trying to make soup? Beef stock or chicken stock? There's certainly no shortage of FOG stock, I just bought a six figure chunk without any problems. So why do you post this?

Part 3 – Reservoirs

We've heard all about the Tertiary (Miocene) sandstones (TGB & Hoot sands etc) which have reasonable porosity and are mostly in the form of turbidite fans. That's where GRF-1 and MSD-1 were drilled (but a bit off-target), where MOU-1 has gone and MOUs 2-7 are all planned. Some nice near-surface gas plays which constitute readily commercial plays, especially since seismic indicates that they are considerably larger in both thickness and areal extent than those found in the Rharb to the west. Lonny and drilling manager Moyra Scott have enormous experience working on exactly these targets in the Rharb.

What was mentioned for the first time in this week's presentation was MOU-NE, which is a geologically older potential reservoir., being Jurassic limestone. Further east there are Triassic sandstone targets, which no on has even talked about yet. Being older, these potential reservoirs could underlay our near-term targets, giving a complete second set, although there is a good possibility that these may be oil, rather than gas. Here's what the ONHYM folks say about these:

“Numerous reservoirs are known in the Jurassic succession. They are : (1) reef carbonate in the Missour Basin with porosity up to 10 %, (2) the Tarfaya Laayoune carbonate, (3) sandy dolomite and carbonate of the Callovo-Oxfordian in the Essaouira Basin, where the porosity range from 5 to 20 %, (4) the Middle Jurassic arkosic sand of the Haricha, with porosity of up to 30 % , (5) the Middle Jurassic sands in the Tadla Basin (porosity up to 10 %), (6) the Lower Jurassic carbonate in the Guercif Basin, the reef carbonates in the High Plateaux, the oolitic limestone in the Tselfat and the coarse sandstone in the Sidi Fili trend. Porosity values of the Lower Jurassic reservoirs range from 10 to 30 %. “
So – numerous reservoirs, including the Guercif Basin – porosity up to 30%. PRD has already identified MOU-NE as being 105 km² in area, with 224 metres of Jurassic oolitic limestone with potential reservoirs. How many of these could underlie the shallow targets that we have been concentrating on so far?

Part 2 - Source rocks

A trawl through the ONHYM website (which can be very slow to load) gives us some interesting quotes on the large number of potential source rocks. In order of age, with oldest first (and of course at the bottom of the sequence):

Palaeozoic organic facies are widespread over the whole Moroccan territory and constitute the continuation of those encountered in Algeria and North Africa in general. The Silurian source rocks with TOC value of up to 12 % are the most important.

Jurassic & Triassic. The synrift sequence, infilling Triassic graben and half graben along the Atlantic coastal basins, may yield excellent lacustrine (type I kerogen) source rock. Recent geochemical survey shows that the Rif, the Middle and the High Atlas basins contain rich Lower Jurassic (Liassic) source rock. The organic facies is predominantly amorphous type II kerogen with TOC values up to 10 % and within the oil window in most places. This facies is producing oil in the Prerif Ridges and is the source for many seeps distributed throughout the Prerif and the Middle Atlas areas. The petroliferous character of this Jurassic organic facies may have a widespread distribution.
Cretaceous marine organic facies (Aptian-Albian and Cenomano-Turonian) are, by far, the richest in organic matter with TOC up to 20 %. These facies are widespread over most of Moroccan sedimentary basins. Under adequate burial, the Cretaceous marine organic facies may constitute an excellent effective source rock.
Oligocene and Miocene marls and shales have TOC values of up to 7 % in the Atlantic basins and up to 2 % in the Mediterranean offshore area. This source rock produces biogenic gas but can yield oil where sufficiently buried. This is seen particularly in the Rharb Basin where we have either biogenic gas or oil production, depending on the depth of burial of this source rock.

So the chances are we have multiple layers of carbon-rich source rock in an exceptional 'kitchen' setting.

Not specifically about carbonate reservoirs, but bear with me, we will get there towards the end, in Part 3 :-)

Part 1 – Backround.
Readers interested in the details may recall that we have two important areas of geological interest – possible source rocks, and possible reservoir rocks. PRD themselves have talked mostly about Miocene reservoirs, since these are close to surface, therefore easily evaluated and relatively cheap to commercialise. GRH and others have talked about potential sources of hydrocarbons, and the theoretical 'kitchen'.
We know in simple terms that the deeper organic material is found, it will be under greater pressure and temperature, and more readily form economic hydrocarbons. The Guercif licence area consists of grabens – parallel faults where the block between has slipped downwards, as happens in a rift valley. Very thick layers of sediment have then been laid down over these grabens, giving us the ideal situation of high carbon content rocks under great pressure and temperature. This produces oil/gas, which then migrates upwards to hopefully become trapped in reservoir rocks.

Great, I'm really pleased you're on this board - from your username I assume you are both a geologist and highly proficient and expert in your field. Presumably you are on this board to share your expertise with less experienced investors, so could you please help us mere mortals out by running through the five appendix slides of the 9th September presentation, which are the MOU-1 logs, and give us your considered view on each slide, and why you have come to the conclusion expressed in your comment today? That would be so helpful, thanks very much in advance.

Good positive summary of progress to date and next steps:

"Much remains to be proved. But the upside doesn’t come much better. If you’re looking for big game hunting, this is it."

https://www.proactiveinvestors.co.uk/companies/news/961679/kavango-resources-still-optimistic-in-its-hunt-to-discover-the-next-norilsk-961679.html

Oh god, no edit - the NPV nos. are $millions of course!

Given the upbeat tone of the RNS, with a reference to 100mm cfgpd post MOU-4 & 5, I have revisited the 18th March RNS, aka Michael Caine. I am using the info from there as a basis for NPV calculations of 4 different scenarios - 10 (as in 18/3), 25, 50 & 100 mm cfgpd. Costs are increased in proportion to income, and are equal over years 1 & 2. Sales are net of royalties that kick in at 3.65 BCF, and decline with reducing reservoir pressure as follows - yrs 1 & 2 no production, 2-5: 100%, 6 & 7: 75% 8&9: 50%, 10: 25%. You will appreciate this is quick & dirty, and I am cooking dinner at the same time.

10mm cfgpd: NPV $79, IRR 105%
25: NPV $202, IRR 121%
50: NPV $405, IRR 121%
100: NPV $811, IRR 121%

My rule of thumb for discovery stage projects is to use 25% of NPV to account for risk of things not going to plan - which of course they often happens, particularly at the moment. So if we divide the $US figures above by 4, then by 1.37 to get them into GBP, and assume 300M shares in issue, we get the following values per share:
10 - 3.6p, 25 - 12.3p, 50 - 24.6p, 100 - 49.3p.
Of course once these are up and running in two years time, you remove the risk discount, so multiply these share prices by 4, which of course gives you £2 for the top case. You can begin to see from where GRH gets his numbers, since this calculation does not take into account of anything other than MOU-1,4 & 5.

Please note - this is illustrative only, as I have said previously, I am neither an O & G specialist, an accountant, nor an investment advisor.

And what a day to make the announcement - with Henry Hub gas prices going above $6 for the first time I can remember, and Brent going above $80 for the first time since Sept 2018 - and that was only for a couple of weeks.

F & M - Yes, I want to run some NPVs for different assumptions (10, 25, 50 & 100mm cfgpd). Please bear with me, I will do it after getting the kids' dinner & before going to bed (I have a 9-hour time difference to you guys)

Things I like:
1. The large areas of the Morocco gas prospects are all mentioned
2. RNS mentioned in passing up to 100mm cfgpd after MOU-4 & -5 get up and running - 10x the SLR projection, or $US 200M per annum revenue net to PRD.
3. MOU-NE looks like a stonker (that's good, btw).
4. The T & T government must be really hacked off by FRAM's behaviour towards a project that they perceive to be in the national interest - the chance of PRD picking up the I-T IPSC must be pretty good.
5. I can't comment on developments in Ireland - out of our hands and in the slippery hands of incompetent pollies.

Just a quick follow up if there are any HE1 staff reading this board.... your younger geologists will be very familiar with remote sensing digital technology, but old-timer ERT may be something of a shock (pun intended) to them. I suggest you issue them with yoga mats, which they should fold double and use to sit on when taking readings. Without this, there is a significant risk that high voltage square wave, low frequency, alternating current will try to earth through them by the shortest route. If you are squatting on the ground in shorts, but with thick insulating rubber-soled boots on, you can work out where the shortest route goes.

My technical summary: "We've not yet found RNS-worthy mineralisation, but have enough indicators that there are plenty of goodies for us to keep looking"

An interesting listen, Sarah Lowther is quite aggressive in her questioning, especially compared to Proactive Katie. To me the most interesting info is that exploration for shallow basins is underway. This is using an old electrical technique called ERT, or electrical resistivity tomography. It's actually so old that this is the first geophysics that I ever did - although it was then called simply electrical resistivity.
In simple terms, what you do is stick four large metal spikes in the ground in line, and stick electric currents between them (we used to use square wave, which could give you a nasty jolt if you touched the wires!). You then measure the difference in current resistance between the two inner connected electrodes, and the outer two. The further apart the electrodes, the deeper the current penetrates - up to 100m should be possible.
The advantage of using this rather dated approach is that it works very well in differentiating porous sand and impervious clays, thus distinguishing our potential reservoirs from our potential seals. The only issue I can see is it is rather slow - electrodes have to be moved frequently, wires reconnected, measurements logged manually, then hopefully someone has a computer programme that can image the results. It was painful doing each calculation then plotting manually on graph paper. Another advantage is that it works best on wet strata, which is what we had at Rukwa.
The last few minutes of the chat was DM explaining why you get washouts with a small bore drill, and why he expects this will not be a problem next year when using a larger drill. Worth a listen if you're interested in the finer points of boring holes in the ground.
DM seems very positive that gas was found, and frustrated that due to hole conditions they were unable to flow to surface and declare a discovery.

otd - 22.5% ownership/accountability of FOG has been taken into account throughout. 98% vs 100% ownership of Falcon Australia is irrelevant, the other numbers are rounded, and the assumption are so wide ranging.
I would prefer to see a net gas price figure (eg net profit per mmCF, rather than a net profit per boe). I have no idea of the net profit margin received by the operator, nor of the likely gas price forecast for the next 30 years. If anyone has independent and professionally-generated numbers, let me know and I will drop them into the calculation and report back. Whatever, this is just a wet finger held up to the wind, which is still better than nothing.

tnb - Thanks very much for this. When I first bought FOG many years ago, I attempted an NPV calculation, and came to the conclusion the shares were a steal. After several years of delay and frustration, this conclusion should be re-visited, unfortunately I have mislaid my original calculations.
Please help me out - I can not see how you have derived your end number. I am happy with the value of US$ 61.6Bn, this is the value of the recoverable resource attributable to FOG. You then seemed to have just divided the number by 10, unfortunately this is not how a discount rate is applied to cash flow in order to obtain an NPV.
For the big picture, if I take the
* $61.6Bn total FOG attributable recoverable resource value
* assume production starts in Year 4, and continues for 30 years at a fixed annual income amount of $2053 M (61.6/30)
* total infrastructure costs of Year 1 $500M, Year 2 $1Bn, Year 3 $1Bn, of which 22.5% attributable to FOG
* drop into NPV/IRR spreadsheet with a 10% discount rate
* gives NPV10 $15.6Bn
* IRR 143% (!!!).
* 985M shares in issue = $15.80 per share = £11.56 at GBP:USD 1.37.

In reality, projects at this stage are typically valued by the market at a fraction of their NPV, to take into account all the things that can and frequently do go wrong. Future political risk is an obvious overlay here to the normal geological and engineering risks. I have assumed 25% of value, which is pretty standard for a project still at discovery, so maybe £3 per share is a realistic valuation in a few months time, once we have a a more solid idea of gas flows and thus economic viability.

So why the sub-10p valuation? Of course this is based upon the 6.6 TCF total / 1.46TCF attributable to FOG. Let's use the same assumptions, but with lower infrastructure cost - total $1Bn, $225M to FOG, Year 1 $25M, Years 2 & 3 $100M. Value of gas/year drops to $182.5M. NPV10 is then $1.52 Bn, IRR is a very respectable 57%. Share price is US$ 1.54 / £ 1.12p, then apply your market risk discount fraction - if 25% as above, that gives 28p / share.

However, it is important to point out that there are some very big assumptions here, not least the gas price and whether there will still be a demand for gas in 2054! I am a geologist (but not O & G) and not an accountant, so other commenters please provide your more knowledgeable input!

Whatever (reasonable) assumptions you make, at the current 6.6TCF the shares are still very undervalued. Once (or should I say if) the surrounding companies' wells show commercial rates, and we are able to validate the Amungee flow to Origen's rather than POQ's standards, then the market will start to realise that 465TCF or more starts to look plausible.

My conclusion: Don't sell.