Member Info for Jimmy23

Wiggly,

Much and all I would love your calculations to be true , you have erred in the calculations..

The 10% sale to energean for a finance carry of $850 million is worth $85 million for 10% and chariot will hold 20% after final farm down so its $170 million of financing foe the development of anchois provided by energy an.

In addition chariot receives $25 million in cash and a carry of 20% (assuming they dilute to 20%) of anchois 3 well costs of $85 million worth $17 million.

Anchois 3 well is highly likely to increase proven gas to approx 1000 bcf gross, which I assign an 85% chance of success, similar to onshore success rate for same geology and seismic attributes.

That leaves chariot fully funded for the development which will produce 200 mmcf per day gross and generate ebitda of approx £80 million per year tax free for next ten years, based on $8 mcf gas price.

So we are valued at a little over 1 year ebitda, and financed through to first gas.

Jimmy

Hi Keith,

Many thanks for your observations and comments.

With regard to mou 4 carbonates, the mou 4 results rns reported 2 meters of high porosity carbonates, but the pre well prognosis was for 243 meters, any views as to what happened .?

Jimmy

The typical basin floor fan prospects in the Namibian orange basin is finding around 2 billion bbls of oil.

The shell discovery is reported at around 9 billion bbls.

Jimmy

Galp have just announced a major oil discovery offshore Namibia,the licence area of which is contiguous to a licence in which chariot have rights to a a10% licence interest after a well is drilled on the block.

See.

https://www.offshore-energy.biz/semi-sub-rig-finds-significant-oil-discovery-offshore-namibia/

There is a giant prospect north of the recently drilled galp block which probably extends into chariots acreage.

A nice surprise.

Jimmy

Great to see ap buy shares in the market along with other exec directors recently.

Looking forward to the start of the onshore low risk drilling program shortly.

Same concept as drilling the successful anchois 2 well offshore, the prospect is up dip from a proven reservoir of 10 meters, with logged gas, in a prospect with 3D seismic showing amplitude seismic features of gas, which have previously demonstrated >80% discovery success rate.

No wonder they invested.

Jimmy

I have re read the previous rns on Trinidad and it does seem capable of getting into production quickly from previously drilled wells.

The snow cap 1 well previously flowed at an initial rate of approx 400 bopd which was not sustained due to a high wax content which killed production.

High wax content oil can be treated with chemicals and by pumping hot oil back through the production tubing to clear the wax, a common procedure.

Prd estimate that snow cap 1 well could produce at about 100 to 200 bopd, and that they will look to re complete snow cap 2 on the same basis .

Assuming 200 bopd from two wells and a net back of $20 per bbl would generate $1.2 million p.a. Net to predator, but could be double that rate.

In any event, that net revenue would cover most of prd basic operating costs and free up its current cash holdings to then drill the Jurassic carbonates in Morocco later this year.

Pity that prd did not state the depth that the mou 4 well was drilled or what the overall thickness of the carbonates were below the level at which gas was encountered.

Prd did state that they were investigating the possibility of gas condensate or oil in the mou 4 well.

So did they encounter 2 meters of gas in the carbonates and gas condensate below this?

It’s been 6 months since the well was drilled so an update on mou 4 is warranted at this stage.

Jimmy

Hi snott,

Just to clarify, the next anchois well will drill and flow test down to the proven O sands which previously found a thick reservoir of 47 meters and some gas, which has a very high chance of success to increase gross proven gas volumes to approx 1 tcf.

The sub nappe will not be drilled offshore in this next well, although I suspect it may be drilled in the first onshore well by chariot, where a previous well found 300 meters of reservoir but could not be logged due to drilling problems.

Jimmy

Kb,

The gas at anchois is proven because it has an independent expert report confirming it’s proven.

It is currently classified as a contingent resource and when the finance to develop is provided and the production concession licence is issued it becomes a proven reserve.

Jimmy

We know that flow testing of four reservoirs has to be completed by the licence renewal date of 4th February 2024.

So I am expecting an Rns to confirm crew mobilised for testing and the T and T competent persons report to issue, next week is my guess.

Jimmy

I agree with icb

This is good news for chariot as it will focus the regulators on progressing the largest commercial gas discovery

The eni results probably downgrades the offshore oil potential which has not worked offshore Morocco

Probably makes the licus and Rissana licences more valuable. Particularly the deep potential from where all the gas originated from

Happy new year and let’s hope this time next year we are 3 or 4 x the current share price

Jimmy

Spain is one of europes largest importers of lng , part of which is exported to Morocco so it’s the relevant benchmark to consider for Morocco.

J

The relevant price for gas in Morocco is determined by the price in Spain.

See.

https://www.mibgas.es/en/market-results

Look at the forward price for 2025 , divide by 3.412 and X by fx 1.11 to price in usd per mcf.

Still ok.

Jimmy

Great to see two directors purchase shares in the market to day.looking forward to the first rns announcing the start of the four well drilling program onshore Morocco in early2024

Happy Christmas to you all

Jimmy

Clausewitz,

At the back of the corporate presentation is a schematic of the zones to be tested and the equivalent flow rates from small reservoirs tested in the same geology onshore.

The gas is there as it’s been audited , sampled and pressures taken. However, there are four different gas water contacts and I expect different pressure regimes, the flow testing will provide the definitive information for the production completions, with each of the three wells modelled at being able to produce 100 to 200 mmcf per day, so achieving a field production of 200 mmcf per day is very achievable with considerable extra capacity.

With regard to onshore, I believe it to be very low risk with reservoirs already identified by drilled wells at least 10 meters, with four wells at 1.1 mmcf per meter per day yielding gross production of 44 mmcf per day, at minimum 8 mmcf for power Gen its a strong cashflow generator, quickly.

The current share price values the onshore about correctly and puts nil value for offshore.

Bonkers.

Jimmy

Hi sailplane

Great summary.

I would just add.

Sound energy drilled and logged lnb 2 and lmb 1 which both found approx 10 meters of high quality reservoir and reported such sand were identified through out the 3 d seismic area.

Based on average flow rate of 1.1 mmcf per day per meter for the onshore rharb basin that results in a combined flow rate of 44 mmcf per day for four wells, at $10 per mcf and per SDX an opex of $0.9 per mcf. Obviously need to connect to the pipeline to get to market, but that’s very fundable.

Average success rate for onshore the basin is 80 to 85%

So the current share price reflects a success case for onshore and there is a possibility of a deeper 300 meters of reservoir found in the area also.

Jimmy

Foot and mouth.

I have reviewed the rns announcing the mou 3 well results which stated.

“ rigless well test over a gross interval of 43 metres within this section between 1379 to 1422 metres TVD MD is planned to be carried out.”

The rns of the 30th nov then states rigless testing in mou 3 in the tgb 2 (mou fan) will be performed from 1406 to 1412 meters.

Why not test all of it as previously advised after the mou 3 well, the extra cost is likely to be small compared to mobilising a rigless testing equipment and performing a test at another time.

I think a corporate presentation on the website explaining the planned activities would help shareholders understand the change in plans.

Jimmy

Blue glow,

Good comments.

I think matters have changed in Morocco and gas purchasers need independent cpr of proven gas or flow tests. Since prd has not taken gas samples and pressures and sidewall cores, the neutec log analysis reports probable gas for mou 3 and mou 4. Hence the need for a flow test.

With regard to RoB comments about keeping powder dry for a takeover, I reallly don’t see the evidence for that. If anything the more data that is obtained that validates the potential gas volumes the better a defence can be made or indeed the better that another bidder would compete, cove is mentioned as precedent, but those bids were made after independent reserves were published. I would have thought proove up as much of the 150 meters of indicated gas as possible to get the data to demonstrate the scale of the opportunity for shareholders.

I agree that getting to cashflow asap is the priority to avoid further equity dilution, but flow testing all of the mou 3 fan reservoir would surely put prd in a strong negotiating position, unless of course prd have already found the gas water contact and will not announce it.

Jimmy

43 meters of reservoir in the mou 3 fan reservoir and prd is testing 6 meters, why not repeat test the lot , would not cost a lot more and cheaper than drilling a redrill of mou 3 for the shallow gas which was not logged or indeed a follow up Jurassic well.

A high flow rate would demonstrate real value and provide options.

I am not convinced by the takeover talk, as untested reservoirs would get a low value, better to test and increase the defendable value of prd.

Jimmy

Ibiza,

They raised £10 million in July for testing, so why not do a thorough test as soon as possible

J

BDC,

I had a look at the old SDX energy presentations for the Loukas licence and they comment that a 10 meter reservoir was seen as widespread through out the 3D seismic area and two wells lnb 1 and lmb 2 both encountered logged hydrocarbons at 10 meters of reservoir. Chariot are to drill four wells so I am expecting combined flow rate of at least 40 mmcf per day and upside of 300 meters of reservoir in a deeper horizon which was found in lnb1.

Jimmy