Member Info for Jimmy23

Dgdg.

I can only reference the published information to try to ascertain what’s going on.

Predator estimate the cng market in morroco at 50 mmcf per day. Initially predator are looking at 10 mmcf per day and further volumes dependant of further drilling success. As stated previously they estimate the price at $14 mcf, which as you state is in excess of $12 mcf that sound energy are selling, but that’s via the pipeline as compared to other customers not connected to the pipeline who are the focus of the cng.

I expect chariot to produce at 150 mmcf per day after they drill the deeper O sands as part of the anchois development wells, and the incremental cost of producing that extra 50 mmcf per day will be tiny, but still very profitable if exported at lower prices in Europe if they have to.

Jimmy

The 21% chance of success referes to the Jurassic target in mou 4 .

The mou 3 well comprises the tgb2 reservoirs which were audited as proven contingent resources and the tgb 4 sand reservoirs which had an audited chance of success of 34% before the new top seal encountered in mou 2 derisked the tgb4 reservoirs.

Jimmy

Dgdg1,

Chariot will in the first instance sell its gas for moroccon power generation and hence reduce moroccon dependancy on dirty coal for power and reduce co 2 emissions by circa 55% by doing so. Before Ukraine war, the price was $8 mcf and this will be on a take or pay basis. This will amount to 60 mmcf per day. The remaking gas will mostly be sold in the local market, probably as cng with its jv with vivo , recently announced. Predator are also targeting that market and they have guided a rice of $14 mcf.

The balance to be sold to Europe.

Hope that helps

Jimmy

Hi Keith,

I think we get to the same conclusion.

Pg certainly seems confident of lateral continuity of reservoirs over the 30km sq of the mou fan, even though we have only encountered 10 meters of it in the mou 1 well so far.

He may well be correct but I have not seen the data yet to support this. Perhaps if the reservoir pressure gradients can be correlated between mou 1 And mou 3 then this will prove or disprove reservoir communication across 30km sq, if proven then happy days, if not then more wells needed.

Anchois 2 well had seven different gas water contacts over 150 meters of reservoirs and we are starting with just 10 meters and no gas water contact identified so far.

Good flow test data needed.

Jimmy

I had asked a question regarding the format of the flow testing, as to whether the flow testing would be individual sand reservoirs or concurrent testing of all reservoirs or sequential total testing by testing the lowest reservoirs first and adding shallower zones sequentially.

The answer by Pg was not particularly clear , but it seams to me they will flow test the deepest zone first and then add zones sequentially to reach their target for cng production.

The duration of testing was not fully answered either other than to say he was satisfied that the reservoirs were fully connected over 30km sq of the field.

Pg referenced the seven heads gas field in his answer.

So you might ask does this all matter.

If the focus is on getting to cashflow asap and using the cashflow to finance lots of follow on production wells it’s probably ok.

The flow testing in a cumulative sequential way has been common practice onshore USA for years, but is very crude method and makes calculation of reservoirs performances and characteristics difficult. It may not help to identify intra reservoir faulting and compartmentalisation problems until sustained production of a few months occurs . At seven heads there were thin sands below seismic resolution in a basin that had suffered inversion and the field was more compartmentalised than expected, requiring more wells to drain the field effectively , a major problem offshore but not such a problem onshore as well costs are so much lower. This risk may well be the reason for multiple production wells being planned by prd .

I had hoped that the flow testing of the tgb2 reservoir sands in mou 1 would have been long enough at such high pressures to prove gas down below the 1920 seismic twt depth , which would have effectively proved the gas in mou 3 in my opinion, but this does not look like it’s going to happen.

In addition, if flow testing is sequential the gas from tgb2 reservoir is expected to be very high pressure so it may well hold back lower pressure gas from other zones.

So you might think this is all very nice and academic so what, cash is king.

In my opinion , the quality of the flow testing impacts on the quality of the reserves and that in turn impacts the ability of the project to attract debt finance and the asset value if it’s to be sold or farmed out.

If the strategy is to get to production and use the cash to drill multiple production wells, and stay in production and not asset sale , it’s probably ok, otherwise other options will have a reduced value.

Jimmy

Hi Keith,

Thanks for observations regarding mou 4 and the Jurassic carbonate potential reservoirs.

Clearly the fact that mou 4 carbonate prospect is 1500 meters higher than TFR x 1 increases the probability that the subsequent basin inversions would result in a leached reservoir . At 126 km sq prospect size this could be truly enormous.

Do you have any indication of the porosity and permeability encountered at tfrx1 well 15 km to south east

Paul referenced this prospect in the proactive presentation as having a 21% chance of success, however the c fact that it can be drilled as part of a mou fan producer makes it a very attractive low cost drilling opportunity.

Jimmy

Nigel,

Please read the presentation again.

1. There are a number of reservoirs sands being targeted by the forthcoming mou 3 well

a) tgb2 well which has encountered proved logged and audited gas at the mou 1 well, this reservoir does not have a GCoS as its proven according to the SLR competent persons report.

B) the tgb3/4 reservoirs were originally classified as a 34% GCOS before the drilling of mou 2 which derisked it further by proving a substantial top and lateral mud seal. Still got to be drilled to be proven.

C) tgb 6 is a high risk reservoir as there does not appear to closer to the east.

D) the k reservoir and a reservoir below the tgb 2 reservoirs are not assigned volumes or risk , so speculative upside.

2. The main pipeline in morroco is currently being used to import gas from Spain , the current power generation demand is for 100 mmcf per day. Prd have estimated there is demand for 50 mmcf per day to provide gas to industry in the form of cng, which will displace fuel oil. Yes there is plenty of pv potential in morroco but not so good for a wide range of industries that need consistent power 24 , 7 .

Jimmy

Hi ford,

Thanks for letting me know.

Can you summarise how the wells will be tested .

Jimmy

Hi NV

I believe the predator price for Morocco compressed gas is based on it being a lower cost substitute for industries that are currently importing and burning heavy fuel oil.

Jimmy

Barnyard

I understand that the directors loans can only be repaid if there is a flow rate from mou 1 and or mou 3.

Jimmy

Pdr, have issued an updated presentation to day regarding their plans to flow test the mou 1 well and drill mou 3 well. They plan to sell the gas to morroco industry at $14 mcf by way of compressed natural gas.

Chariot is planning to supply that market also with its joint venture with vivo . Pdr believe the market for such gas is 50 million cfg per day, of which the mou 1 well is expected to supply a max of 10 million cfg per day. Some nice profits for chariot then .

Jimmy

I cannot make the meeting tonight, does anyone know if it can be accessed remotely.

In addition, I would appreciate if someone could ask the following questions.

1. Will each of the reservoirs to be flow tested, be flow tested individually or combined.

2. For how long will flow testing of each reservoir be carried out.

3. What is the expected area of investigation for the flow testing for each reservoir.

4. Is the flow testing of the mou fan reservoir at mou 1 which has high pressure , interfere with the flow testing of the shallow gas reservoirs and the unconventional gas reservoirs due to its high gas pressure holding back gas flow from lower pressured gas reservoirs.

Thanks

Jimmy

GRH,

In the most recent chariot presentation they report that they expect the field production to be 105 mmcf per day from three wells.

The anchois 1 well encountered 50 net meters of reservoir, the anchois 2 reservoir encountered 150 meters of net reservoir and it looks like the number 3 well will encounter 50 meters of reservoir also, so perhaps you could use those numbers as analogues.

Regards

Jimmy

Hi GRH,

As far as I know there has been no flow testing at anchois, instead they sampled the target zone reservoirs extensively, by taking extensive core samples which I believe are then used to get a laboratory calculation of permeability, pressures were extensively measured and multiple samples taken of reservoir gases and fluids if any.

From these detailed measurements along with the usual logs , the experts can calculate a fairly accurate flow rate .anchois logs show a high gas water ratio, so these calculations are likely to be accepted by the project finance banks.

The reservoirs so far at mou are substantially thinner so far and the measurement of gas water ratio in thin reservoirs is difficult.

I do not know if mou 1 well had all these detailed measurements and hence there is a need for a flow test.

Hope that helps.

Jimmy

GRH,

It will be interesting to see the flow rate from mou 1 for the reasons you describe. However, in my opinion it will also be important to see if such flow rates are sustainable from thin sands, as a general rule the thicker a sand is the more likely it’s laterally continuous , so a consistent long flow rate will be important to validate lateral continuity of sands, particularly as thin reservoir sands are usually below seismic resolution.

Jimmy

Did not see the mou 3 well described as high risk

Michael,
Perhaps it’s late at night but I did see the mou 3 well described as high risk in the rns dated17 matprch 23, can advise where it’s stated.
Thanks
Jimmy

Nigel,
The mou 3 well is targeting two major reservoir targets
Reservoir sands tgb 4 , which are classified as prospective resources with a 34% chance of success , before the new mud seal derisked the prospect.
Reservoir tgb2 , has been audited as a contingent resource , hence no Cos .
Finally, even after the well is drilled and establishes a proven logged reservoir, the gas only becomes a reserve when the production licence is issued and finance and capex contracts in place for its development, per the new reservoir engineering classifications.
Jimmy

Nigel,
Can you kindly explain how drilling into audited contingent resources is high risk at mou 3,
Thank you
Jimmy

Anchois npv in excess of $1bn net to chariot.
Partnering discussion advancing for anchois development as part of basin opening strategy.
Jimmy