Member Info for KeithOz

There are 24 weeks to the end of Q1 2022. By that time, we are told that PRD will have drilled Mouloulaya 4 & 5, and flow tested all 3 MOU wells. 8 of those weeks will be taken up by drilling and moving the rig. 3 minimum will be used for testing. That leaves a maximum of 13 weeks, or 3 months, to get everything sorted - finalising a JV for funding, contracting the rig & crew, and moving them from one side of Morocco to the other, contracting the testing team, ordering all the necessary supplies (I know some are already on order).
That's quite a busy timeline - although Christmas and New Year are not a deal in Morocco for the locals, they are for everything and everyone coming from outside the country. PRD don't want to overshoot the end of Q1 - not only do delays look bad, but Ramadan starts right at the beginning of Q2, and believe me, everything will grind really slowly for the whole of April.
If this is to all fall into place, an announcement on funding is needed imminently. The last few trading days has seen an increase in volume and share price - Is this because someone knows something good is about to be announced, or just people being hopeful? I suspect now is the time to either place your bets, or take your money off the table - there, that should keep the rampers and derampers happy :-)

btw, I'm in, big time.

erm... wrong board, 111b.

Hi AP, Yes I was very curious about the 40BCF in shallow targets - that would make 29% of the total of 138BCF. Where on earth did that come from? Elsewhere, shallow targets are only stated to be 4% of the total, which would give 5.5BCF, and it appears this figure covers the whole Rukwa basin.
H&P 'conservatively' allocated 1BCF to the Tai LBF, giving a risked 1p per share valuation. Again, it is unclear how many holes are scheduled to be drilled in order to obtain this 1BCF, and how these many small reservoirs are to be commercialized. Is the plan to have a small mobile concentrator go from hole to hole? Since these reservoirs will be at low pressure, how much gas will actually come to surface? How much will exploration + production cost be per BCF? It seems to me there are a lot of question marks around this strategy. If you are going to move away from a previously carefully planned and costed strategy, it seems reasonable to explain a little more detail to the folks who will be funding it, which is you & me.

If this sounds a bit negative, it is because I don't have the information to assess this properly as an investment proposal. I do rate highly the strategy for the big, deep prospects, which is why I am heavily invested here. I just don't want to see our limited resource sidetracked just so we can announce a discovery, when that discovery may have low potential for commerciality. - Keith

This was the question I submitted:
David: It is reasonable to assume that shallow traps in the LBF will have a relatively small, and probably uneconomic amount of Helium, since the reservoir beds are thin, pinch out laterally, and being shallow have a low overburden pressure and thus less gas. Would it not make more sense to use our limited financial resource to concentrate on the deeper, thicker and more extensive reservoirs already identified as at Tai? Of course, this time with a more capable drill. We shareholders originally signed up for 3 or 4 well programme testing different trap styles, but as per the CPR those traps were all likely to contain commercial quantities of Helium.

Me too, Sef, but bearing in mind who those characters were, I thought it would be politically incorrect to mention!

Over the last week there had been speculation (including by me!) of identified oil prospects on the Guercif licence, in particular reference has been made to a prospect identified by Maxim in 2014, which they had named 'Top Dogger', with a best estimate by SLR of 60 million BOE recoverable.
I have now had time to dig out some maps and correlate them. The Maxim licence was previously known as Hassi-Burkane, which is now identified by ONHYM as no. 187 on their map:
http://www.onhym.com/images/Cartes/Domaine_minier%2005_06_2015.jpg
The Guercif licence is shown on the same map as XV. It will help greatly if you use the magnifying cursor!

Unfortunately, the Top Dogger prospect is not PRD's - it is just a few km away from the NE corner of our licence. While ONHYM terminated the licence to Maxim in 2016, I can not find any reference to it being re-licenced to anyone else.
However, what this does indicate is that there is potential for substantial plays in the deeper Jurassic (Top Dogger is Middle Jurassic) & Triassic (analogous to the TAGI sands in Algeria), particularly. Very little seismic has been done to the north of Merada town in the middle of the Guercif licence area, and that was 35 years ago.

PRD needs to relinquish 25% of the current licence by the end of 2022. I hope they are weighing up the commercial potential for both oil and gas given the shambolic energy crunch we are just entering into.

May be a funny name, but very interesting commentary on why things are going wrong and what is likely to happen. There is a link to the full report, which is even better, but you have to be a (free) subscriber to read it, sorry, I am not allowed to copy it to here.

Much more developed? Did you expect igloos and reindeer, and people dressed in furs carrying spears? This is the capital city of a European Union nation, but you can still drive from one side to the other in just over 5 minutes.

For those of you not members of Research Tree, you may need to register to see this Cenkos comment on today's RNS.

https://*********************/companies/uk/oil-gas-e-ps/falcon-oil-gas-ltd-/research/cenkos-securities/cenkos-falcon-oil-gas-ltd-kyalla-update/39_5f5058ba-1ea0-41df-8cfa-ffc50e14234d/07c9ee73-6864-4c85-a7c9-6af3213cf554

Since this is a nearly 300-page document, you can save time by going to pp 100 - 103 for previous drilling info.

Meant to say in the last line that there have got to be better things to do with the vast amount of CO2 produced by all the Moroccan fertiliser plants, rather than just vent it into the atmosphere.

omg, 'should be demand outstripping supply' of course.

I believe it was well understood that there was oil all over Morocco, including our own licence, but there were several reasons why it was not being more aggressively pursued:
* Lack of infrastructure, hence the stranded assets to the south of the Guercif licence
*Mostly in deeper prospects than gas, so more expensive to drill
*Very complex geology, due to the multiple tectonic events causing extensive folding, faulting and overthrusting, giving rise to (a belief that) there would be lots of small prospects, as SDX has discovered with gas in the Rharb
*The presence of shallow, readily exploited and easily marketed gas.
Those factors have guided PRD's strategy, with the overlay of the 'energy transition' aka 'we're the good guys' angle.

With oil prices topping $80/Bbl, and demand very likely to outstrip demand for some time, I suspect the strategy may indeed be revisited. Reviewing some of the data previously 'hidden in plain sight' it does appear that the oil prospects at our end of Morocco appear to be very substantially larger than those in the west. One poster here has possibly detailed knowledge of remote sensing data, which he is unable to reveal for either reasons of confidentiality or common business politeness. The fiscal regime in Morocco is probably better than anywhere else - see slide 7 in the Maxim presentation.

Given all these positives, what would you do in PG's shoes? It makes sense to continue with the gas commercialisation strategy for now, with financing from a strictly project related JV - effectively an offtake agreement with funding. By the end of next year there is both cash flow and credibility - both together is very unusual in an O & G junior - then start using the money for wider exploration - both geographically and for resource type. If it is necessary to stick with the 'energy transition' story, then selling off the hydrocarbon assets, in whole or in part, would fund ventures such as the gasification platform, and something similar to the solar & wind project that is being appraised for Mauretania just to the south. There's lots of sun, wind and empty space along the Atlantic Coast, every time I have been to Essaouira it was almost impossible to stand upright in the wind, day or night, and you get sunburnt within 15 minutes. Alternatively, you could use the expertise from T & T to 'green' all this newly-found Moroccan oil.
Am I getting too carried away?

I've finally managed to access the Chapman September 11 2014 report, there is a better map on p32, but it still looks to me as if it might just be off the edge of our licence area. The ONHYM maps are no help here, the scale is too big. I've spent an hour or two failing to reconcile these areas, if any one has the data to hand I'd be very grateful!

The Maxim proposed licences covered a larger area than Guercif, but I am assuming the prospect they name Top Dogger is within the current Guercif licence. I cannot find the intersection of seismic lines 85 BZ-37 and 85 BZ-11 on a large scale map -can anyone confirm the location and name by which this prospect is known today? There is a good chance that this is oil rather than gas. Despite being close together, the microseepage data suggested gas for GRF-1 and oil for MSD-1

https://www.proactiveinvestors.com.au/companies/news/962040/tamboran-resources-on-a-mission-to-create-tomorrows-energy-solutions-in-fy22-962040.html

Snip, thanks for your response.
From the other board, PerfectChoice made this comment re. Dundas construction timing:

"In terms of funding yes I would like to see that in place by the end of this year ready for commitment to required orders for equipment/resources. But in terms of orders that may only be required for what is possible for 2022 summer season construction. I expect call off of secured funds for 2023 construction will not be necessary until this time next year. So there may be less urgency required especially for the more complex machinery as they will not be required on site until 2023. The first year construction needs to focus on the underlying facilities just to have constructors on site in this cold climate environment. The Dundas SIA document states a construction workforce of up to 270 and 175 for operation, bearing in mind a shift system will mean that is not the concurrent workforce at any time just the total. So before they can get to constructing the gravity separation process with the wet/dry plant and transportation to central facilities and loading onto the 11 ships per year they are planning for, they need to construct the underlying facilities including the airfield if that is still the primary route for access especially for workers.

There has been some speculation on earlier production, however in my view that can only be on the basis of the 2019 40K basic filtering Ilmenite pilot plan shipment, for which further refinement is required for supply to smelters. While JAY have their pilot plant in Quebec, it can only really be considered for further customer sampling (as has been happening) or for one-off smelter runs, not for continuous commercial supply. So that further refinement stage has to be available elsewhere for any early shipment out of Dundas is feasible.

The critical factor for any continuous volume supply is to meet the Ilmenite grade specification the end customer smelter operator requires. So until Dundas is up and running with both wet and dry plants in place, end customers cannot be supplied in the large scale commercial volume required to the specifications they required for their smelters.

That means it will be late 2023 at the earliest for volume shipments of the Standard or Premium Ilmenite in volume supply to end customers "

In pt 2, it said incorrectly TARI sands, it should of course be TAGI. My crazy (non-UK English) spellchecker tries to change 'pore' to 'porn'. Sigh.

Volumetric Calculations, p.37

(fyi – gas saturation is the %age of pore volume taken up by gas, gas expansion factor is the amount by which the gas has been compressed by the weight of the overlying rock, so GEF of 300 means 300m3 at surface will fit into 1m3 at reservoir depth)

There are three petroleum systems in the Guercif basin with reservoirs in sub salt Triassic clastics, Lower Jurassic reef complexes, Middle Jurassic sandstones, and Tertiary clastics (ERICO, 1986). Pathfinder has prioritised the Tertiary biogenic gas plays. These Tertiary Neogene gas plays are commercial in the very similar Rharb basin to the west where good seismic has resulted in a remarkably high discovery rate.

The gas initially in place (GIIP) is calculated by Pathfinder as 506 BCF based on an area of closure of 52 km2 mapped near exploration well MSD-1 (Figure 8). The closure is supported by clear seismic amplitude anomalies seen on 2003 vintage data (Figure 9). Typical Tortonian sandstone beds at outcrop range are up to 40m in thickness. Forty feet of net pay is assumed based on multiple separate amplitude anomalies adjacent to the GRF-1 well. Average Porosity is assumed to be 19% based on a range from 13 - 25% seen in the GRF-1 well. Average Gas Saturation is assumed to be 70%. Traces of gas are recorded on the GRF-1 mud logs. A gas expansion factor of 170 was used. Depth to top reservoir is about 1,800m. A 66% recovery factor was used. Volumetrically the Neogene sediments in the Guercif basin are adequate to source large volumes of biogenic gas.

The GIIF is considerably higher than the P10 figures of 41.7 BCF gross quoted by Circle Oil for structures discovered by it in the Rharb Basin. The Rharb gas discoveries are individually small but the high drilling success rate (10 of the last 11 wells) resulted in a number of small producing fields making the prospect economic. Furthermore, gravity, magnetic and seismic data indicates that the Guercif Basin it is more likely to contain larger structures than those seen in the Rharb Basin.

Stratigraphic traps can be identified by amplitude anomalies in Tertiary turbidite sand lenses in the Guercif Basin permit area.
A sub-salt Triassic prospect with an area of closure of 38 km2 has also been identified (Figure 10). A net pay of 100 feet is assumed based on the Triassic reservoir thickness in the TT-1 well in the adjacent Missour Basin. The average porosity is 6% based on a range from 1% to 13%. The average gas saturation assumed is 70% and the gas expansion factor is 300 based on an average depth to reservoir of 3,500m.

Source rocks, p.13

The Silurian “Hot Shale”, the Devonian or the Carboniferous are likely to be present over at least part of the Guercif basin. All these units are proven source rocks in the Middle or High Atlas and adjacent areas, and are likely to be mature for oil and gas. Additional source rocks are also likely in the lower Jurassic and should be mature for oil in the deeper parts of the basin which are buried down to at least 7kms in some areas.

Reservoirs p.14

Reservoirs in the Guercif basin include Triassic clastics, Lower Jurassic reef complexes, Middle Jurassic sandstones, and lower Tortonian clastics (ERICO, 1986). These reservoirs each have corresponding seals provided by Triassic evaporites, Middle Jurassic mudstones, and Tortonian mudstones (ERICO, 1986).
Reservoirs are postulated in the Triassic (the famous TARI sands of Algeria), lower Jurassic limestones (mainly fracture porosity), middle and upper Jurassic sands (eroded on some highs) and Miocene sands. Only the Miocene sand quality can be considered proven. The Miocene sands are sealed by the gypsiferous Mio-Pliocene marls. Triassic sand and Palaeozoic reservoirs are potentially sealed by Triassic salt where present.