Member Info for Jimmy23

Welcome back C 7 ,

Great to have your input.

J

Marachi,

I am invested in both chariot and Pdr and believe that both have enormous potential.

The reason that chariot reservoir thickness are greater than onshore equivalent is because the geological model is that such turbidite sands are deposited in relatively narrow grabens . It’s the same geological model for predator.

Clearly, chariot has an extensive 3D seismic set and an enormous amounts of samples and readings, which is what you would expect if a well was to cost $35 to $50 million .

Pdr well costs are $3 million or so.

No one can tell yet if the fan reservoirs in mou 3 are in communication with the thinner equivalent sands in mou 1.

Flow testing and pressure readings will inform that assessment.

What we do know from the geology of the rharb basin is that there is an 85% success rate on drilling seismic anomaly features, and the feature at mou fan is large and that may be a better predictor of sand lateral continuity.

Jimmy

Brv,

Flow testing to occur in July so initial logging results must be due then.

Note chariot took three months after initial logging results to upgrade the logged intervals.

Jimmy

Keith,

The announcement of project debt yesterday was by sound energy and not chariot.

Jimmy

Clarification, the mou 3 time depth is deeper for the mou fan at mou 1, the actual meter depths are that mou 3 fan is higher than mou 1 fan depth in meters.

The seismic time map of the mou fan, pre drill is disclosed on page 13 middle , bottom illustration at

https://wp-predatoroilandgas-2020.s3.eu-west-2.amazonaws.com/media/2023/01/Drilling-Update-MOU-2-01-February-2023-final-29012023.2317pm.pdf

Note the seismic twt (time) depth of the mou fan at mou 1 well location, as 1740 .

On the same pre drill map the prognosis for the seismic time depth for the mou fan at mou 3 well location is at 1870 , so it should deeper than at the mou fan horizon at mou 3.

But is not , it’s higher at mou 3 at a 1378 to 1437 compared to the mou fan at mou 1 as 1391 to 1510 as per the presentation at page 7 at.

https://wp-predatoroilandgas-2020.s3.eu-west-2.amazonaws.com/media/2021/09/19204501/PRD-Proactive-Presentation-Final-09.09.2021-1.pdf

So the depth conversion of time to depth of the two wells changes .

Obviously the mou fan now needs to be remapped as more of structure is up dip of proven gas at mou 1, and hence the risk of their being a gas water contact directly between the two wells is much reduced.

Good news and may explain why there was elevated gas readings in the 50.5 meters of reservoir encountered at mou 3, the upside gas volumes need to be considered , subject to log results of course.

Jimmy

23.8 million shares traded today , just a few more days to get rid of the overhang, if the guide of 3x placing volume , is true.

Jimmy

Obviously we have to wait on the audit of the mou 3 well logs to be certain, but we now know the following

1. The mou 1 well encountered 10 meters of audited net gas reservoirs in its shallow zone and the same intersection found at mou 3 had 10.5 meters with a high gas reading and which predator report as having a potential 58 km2 trap area, rough estimate about 250 bcf of gas to predator.

2. The mou fan had 12 meters in mou 1 and 50.5 meters in mou 3 with high gas readings and the interval was updip of the proven gas at mou 1. Predator state “ The MOU-3 well has validated our pre-drill upside forecast for sand development in respect of the main Moulouya Fan target. A gross interval of 43 metres will be evaluated by a rigless well test“ . The pre drill upside was 703 bcf.

So, subject to wireline log results, we are looking at potentially over 1 tcf of gas, so far.

Jimmy

I spent a good bit of time researching and posting my analysis of the rns, only for the post to disappear.

So a summary,

1. We have high pressure shallow gas in mou 3, most likely Pliocene, not logged, great news but it needs to be flow tested or has no value.

2. Ma sands in mou 3 slightly up dip from proven equivalent gas in mou 1, gas reading of 3% compared to 1.7 to 2.44 % in mou 1, looking good.

3. Mou fan encountered 50.5 meters net reservoir at mou 3 between 1378 to 1437 meters with elevated gas readings compared to 1391 to 1510 at mou 1 with 1.6% gas readings. Mou 3 is UPDIP so highly likely to flow high volumes of gas.

4. Gas bearing reservoirs in this area how low log resistivity, hence the need to get audited log results.

Obviously, got to wait for logs, but highly likely to be a great onshore gas discovery.

Jimmy

That’s true Fraser,

Also chariot will be selling cng to the industrial market and the current price there is $16 mcf, so I think $11 mcf seems a reasonable average to use for valuation purposes.

Jimmy

What’s the expected farm out worth.

We know that chariot will receive a lump sum plus a carry on capex and exploration, but do not know what the substantial licence interest they will retain will be at.

The valuation matrix ranges from a shell ebitda of 5 to Tullow ebitda of 10

I am using an $11 mcf gas price as a future average price, which is less than the forward price for 2024 in Spain.

There are two production profiles referenced by chariot, 105 mmcf per day initially and 150 mmcf per day if the low risk O sands are gas bearing as expected.

The ebitda calculations for a 10% licence interest are as follows.

1. 105000 x $11= $1,155,000 per day x 365 days = 421575000 per year less royalties of 3.5%=$406819,000 less opex 40,000,000 = $366,819,000 for 100 % licence interest so 10% is $36,682, 000 . Apply an ebitda multiple of 5 = $183,410,000 or $1.26 fx = £145, 563,000 or about the current market capitalisation for chariot which holds 75% pre farm out licence interest. To apply the tullow ebitda valuation double the value. For each multiple of 10% licence interest they retain multiply again, so a 40% post farm licence interest is worth £582,252 000 or double that for a tallow ebitda valuation.

2. I believe the probability of producing at 150 mmcf per day to be very high given the 85% success rate onshore for similar geology and seismic signature. So the valuation would be as follows 150,000 mcf x$11 mcf =$1650,000 per day x 365= $602,250,000 less royalties of 3.5% = $581,171,000 less opex $40 million = %$541, 171,000 x 10% = $54,117,000 divided by $1.26 = £42,950,000 x 5 years ebitda = £214,750,000 or double that for the tallow ebitda multiple of 10 , in respect of 10% of the licence interest of 75% pre farm out that they currently hold.

Each investor can choose their own estimate of the post farm out licence holdings and adjust accordingly.

Now the first ten years of production in morroco are tax free so a higher ebitda multiple valuation is justified.

One thing is very clear, the current valuation is simply way below reasonable market valuations.

Very strong buy.

Jimmy

Hi fernan

The reference to the onshore area is at

https://www.sdxenergygroup.com/operations/morocco/

The seismic signatures are for seismic amplitude anomalies which are common in both the onshore and offshore Miocene prospects.

Onshore the size of prospects is very small, whereas offshore they are substantially bigger as proven by a huge 3 d seismic survey.

I hope that helps

Jimmy

Hi GRH,

Patiently waiting like everybody,

Nice way to wait in the Côte d’Azur though.

No problem with you using my post as it’s for general information.

The seismic cross section is north of the mou 1 well and crosses from west to east so it gives agreat cross section of the rift Basin.

The cross section shows how multiple stacked reservoirs pinch out at the basin edges with an ant line in the centre.

Of particular levanter are reservoirs tgb3 and tgb4 which were blocked by the mud seal proven in mou 2 and which the seismic appears to show as pinching out to the west also.

Got to wait for drill results .

Given that shallow gas and shallow top seal have been encountered in mou3 well so far, predator should consider using its cng cashflow to a acquire a full 3D survey of the area

Jimmy

We know we have shallow gas to test, so no surprise if testing equipment brought on site.

The question is what else is to be found.

Page 21 gives a good illustration of the potential of the structure at.

https://wp-predatoroilandgas-2020.s3.eu-west-2.amazonaws.com/media/2019/02/New-Presentation.pdf

Jimmy

Gas supply required for decades.

China just signed long term lng contract to secure supply.

See.

https://uk.finance.yahoo.com/news/gas-stay-decades-fossil-fuel-010000495.html?soc_src=social-sh&soc_trk=ma

Jimmy

Ian,

I am not suggesting that chariot are selling 51% of its 75% licence holding . It’s my speculation that chariots 75% interest will split approx 40% to chariot and 35% to farminee.

The legals on such a deal are likely to be very complicated involving three exploration licence farm out agreements, and a non recourse finance loan to cover unexpected capex cost overruns and joint operating agreements acceptable to three parties for the licences and production licences. Hence a possible reason for a delay. Fortunately, chariot has an in house counsel with specific expertise in all these areas.

The value of chariot after a farmout will comprise of the implied value of the asset sold and by implication the pro rata value of the asset retained.

From the investor farminee they will want to get payback on their investment from production cashflow within 5 years of first production.

I suspect we are very close to finding out the deal,

However, we do know that it’s likely to be structured in such a way as chariot will not need equity funding to get to first production cashflow and that there is a funded pathway to increase reserves substantially and daily production to 150 mmcf per day if the low risk low cost drilling is successfull.

Jimmy

Ian,

Thank you for identifying the small error in my calculations, fat finger syndrome.

The issue which I was trying to address in a very clumsy way is the very low risk pathway to gross proven gas volumes of over 1.6 tcf .

Now technically chariot is correct to report that the chances of success of increasing proven gas volumes to over 1.6 tcf are between 49% to 61% , however the success rate onshore for similar geology with similar geophysical seismic signatures is 85%.

Now mr market is assigning this substantial increase in proven gas volumes with a nil chance of success , but big oil in California , I expect will recognise this low risk potential, and pay accordingly.

Let’s wait to see what’s announced , but if chariot keep from 40 to 50% of the licence this is incredible value in the share price now.

Chariot have set out the pathway to deliver this outcome without diluting shareholding equity.

Chariot stated, there was a competitive biding round for the oppportunity and the deal is in final stages, company brokers know the deal in my view and the re iterate guidance at 55 p, but that just the start.

Jimmy

Surfit,

Chariot previously suggested a spin out of the green and hydrogen business, so plenty of cashflow to finance a regular large annual dividend.

Jimmy

The latest announcement by chariot has outlined their plans to farmout, get a cash contribution and be carried through the development program.

We are starting with 637 bcf of proven gas and the development program will include drilling to complete the O sand reservoirs which have some proven reservoir and gas and will add if a further 735 bcf of very low risk reserves at 49% to 62% chance of success, if successful this will bring proven gas volumes to 1392 bcf.

The farm out deal will include the lixus and rissana licences and will most likely see the farmin or paying to drill anchois west which will add a further 280 bcf of low risk 52% chance of success.

These extra gas volumes are in reservoirs which have been drilled in anchois 1 and 2 and which contained gas, and the seismic signatures are also showing the presence of gas. Onshore in the same basin such seismic signatures in the same horizons have an 85% drilling success rate, so this is highly likely to succeed.

The extra gas volumes will allow daily gas volumes to increase to 150 mmcf per day, which is the pipeline to shore capacity and the project financing facility can be used to expand the onshore gas processing facility to over 150 mmcf per day.

We do not know what the chariot post farm out licence interest will be, but I am expecting it to be 40% to 50% .

Chariot advised the farm out was highly competitive and is now in the final stages of completion.

This strategy will leave chariot with no initial project debt, and a clear pathway to the development of over 1.6 tcf of gas and first gas in two years and likely to rapidly increase in daily production to 150 mmcf per day , without the need for further equity dilution and a valuation of less than 150 m stg £

Incredible value opportunity.

Jimmy

I think it’s time to look at some of the facts that have emerged from the recent rns.

1. We have a new over pressurised gas shallow gas bearing zone in mou 3 , that was not anticipated.

2. There was no such gas beating zone at mou 2 which is only 1,5 km away.

3. Predator have now identified the deep faults from the gas source to the shallow reservoirs.

4. There is a good top seal layer above the shallow gas reservoir in mou 3 which was sufficient to contain the high pressure gas now and also during the period of basin inversion.

5. The gas cloud in the seismic is therefore likely to have arisen as a consequence of gas escape from the deeper reservoirs during periods of basin inversion due to gas expansion out the spill points during inversion. Accordingly, expect multiple gas water contacts in the deeper reservoirs.

6. Gas in the tgb2 reservoir in mou 1 is also overpressurized.

My conclusion is that it’s highly likely that further gas bearing reservoirs will be encountered.

Obviously got to drill to prove it, but looking good.

Jimmy