Member Info for Jimmy23

Hi fernan,

In the last presentation and comments, it was mentioned that the pipeline to shore had been increased in size to handle 200 mmcf per day, hence the increase in capex.

The presentation states there are two production options being looked at , 100 and 200 mmcf per day and as you correctly point out the presentation states that individual well production modelling has been calculated at 100 to 200 mmcf per day so three wells at least 300 mmcf per day.

I expect the pipeline to be at least 200 mmcf per day and processing plant increased from 105 mmcf per day initially to 200 mmcf per day as new customers are secured.

Jimmy

B4now,

At the back of the last corporate presentation is an illustration of the reservoirs encountered by anchois 2 and a comparison of sections of those reservoirs to their equivalents onshore.

The anchois development is now looking at producing 200 mmcf per day from 3 production wells.

The average production rate onshore from thin sands is 1.1 mmcf per day per meter. Anchois 1 has 50 meters, anchois 2 has 150 meters and anchois 3, which is updip from anchois 1 will have at least 150 meters plus the low risk O sands of 47 meters, so getting to 200 mmcf per day production will be relatively straight forward.

From a cashflow perspective gas to power with a guaranteed price was previously guided at $8 mcf, below current prices, so this will be a substantial cashflow generator , and the capex is funded.

Jimmy

The area of the relevant prospects and where the gas water contacts are relevant to determine the potential gas volumes.

Mou fan is reported at 30 km2

Mou A sand 58 km2

Jurassic 124 km2, which has so far reported 2 meters of gas, hopefully at the gas water contacts.

We need to see flow rates and estimates of gas water contacts and reservoir communication or not between wells, that’s what the long awaited flow tests will help address, and hence value.

Jimmy

If prd is the only mover in Morocco, then why don’t they flow test all 150 meters of sands that were identified for gas flow testing .

I understand that the perforation gun is only 6 meters, so re use it multiple times , create te value and connect the gas the the major pipeline which is only a few km away.

I am concerned that the market will attribute no value to a reservoir that is not flow tested, particularly if the reservoirs in question were not sidewall cores, and sampled and pressure tested.

Lonny will have flow tested many times previously in Morocco so prd needs to get it done as promised.

J

The rns of 30 nov say the T and T competent persons report will be issued in December 23.

The same rns stated that the Morocco licence first stage was extended to 4th February 24 and

“The key objective of the testing programme was to ensure that all required rigless test data were available within the extension of the Initial Period of the Guercif Petroleum Agreement and corresponding Exploration Permits enabled by Petroleum Agreement Amendment No.3.”

Hope he does what he says.

Jimmy

Hi ianfer,

Yes based on chariots 20% share of the 200 mmcf per day production and an $8 mcf gas price used for power generation in Morocco, current price is approx $11 mcf in Morocco

Jimmy

While many investors expected more of an upfront cash payment from Energean, including me, they have secured a clear and funded pathway to increase reserves to 1tcf and development funded by Energean

This will yield chariot ebitda of £80 million per year for 10 years tax free and a further £56 million post tax for four years. If the reserves increase to 1.4 tcf, very low risk, the £56 million post tax ebitda will continue for a further 5 years.

That exceptionally low risk opportunity can be purchased for just over one years ebitda.

If chariot were to pay a £30 million annual dividend, this would yield a30% dividend yield for investors who purchase shares at 10 p.

I consider the risk very low indeed, but each investor will have other views, worth considering.

I am holding.

Jimmy

Hi daibark.

Morocco is a heavy user of coal for power generation, so transitioning to gas will reduce co 2 emmisions by 45% compared to coal.

In addition, Morocco needs a fuel for base load power generation when the sun does not shine or there is no wind, which gas is best able to provide.

Jiimmy

Hi rh,

Vugs are holes in carbonate rocks which dramatically increase porosity and permeability of the reservoir rock to flow gas at a high rate.

Because the carbonate rock found in mou 4 are elevated higher than carbonate rocks found in nearby wells, it’s believed that exposure to air when sea levels dropped exposed carbonate reefs which dissolve partly in the air and rain and generate the bugs.

Predator reported they are surveying outcrops to establish how widespread such conditions are.

J

In addition, production at 200 mmcf per day would repay the debt in about 3 years.

J

I think at an appropriate stage the farm in debt could be refinanced by a project finance debt at a lower interest rate.

J

BDC,

The 7% royalty only applies if the gas price exceeds an unspecified price.

In the presentations questions they said the royalty level was confidential.

Otherwise , your analysis is good.

Jimmy

the competent persons reports notes that the mou fan reservoir is a turbidite reservoir and that predator interpretation is that these are fan sands, whereas the competent person report is of the view that due to the sp**** seismic coverage these reservoirs could in fact be separate reservoirs in a channel sand deposition.

if the reservoir pressures in each of the sands in mou 1 and mou 3 confirm they are in pressure communication then it’s likely that predator are correct.

maybe grh has some insight on this matter.

jimmy

Onshore $3 million includes testing. It’s one principal reservoir of circa 10 meters that’s expected, but I think there could a good chance of a very thick reservoir of 300 meters as proven by the nearby lnb1 well, a nice surprise.

J

Hi jt,

There is a 150 meters of audited gas in anchois 2, which will be penetrated by anchois 3 plus a thick o sand below it.

The proven gas will at least flow at the average rate per meter of 1.1 mmcf per day, the key reason for the flow test is to measure both the flow rates and the pressures so that different zones with different gas water contacts can be completed seperately for production. The deeper O sand has been proven with gas and a very thick reservoir in anchois 2 and has a seismic amplitude anomaly which worked when drilling anchois 2 and similar seismic with similar geology onshore has an 85% success rate. In my view it’s a near certainty, so we will be looking at gross reserves of 1tcf which in turn will substantially de risk another 1tcf of gas in anchois north and west with plié prospect.

Jimmy

Shagged,

I have not put any value on T and T and wait to see production rates.

With regard to a further raise, I agree with you that pg views drilling as the value creators, however, without flow testing the current or future wells prd will not be believed. If he gets the 25 to 30 mmcf per day from the forthcoming flow test, then that will unlock some of the cng capex to be funded by cng buyer which can then be repurposed for Morocco drilling.

Personally, I think that with 150 meters of reservoir likely to be gas, just test all those sands asap, and sell to the nearby pipeline for power Gen.

150 mmcf per day onshore generates a lot of cash.

Jimmy

Investors via spread betting have been caught with margin calls and forced to close positions, hence the crazy market price.

J

Kingbilly,

The forward price of gas in Spain dropped circa 20% in the last two weeks so I don’t know if it’s permanent or temporary, it’s still circa $11 mcf in Morocco, less than the $15 previously.

Jimmy

Obviously, I am a little disappointed in the deal, but the rise in rig costs and lower gas prices squeezed this deal hard. Listening to the presentation, I got the impression that an issue arose as to how each of the reservoirs would perform on flow test, not that they would not flow , but the reservoir pressure of one zone could impede the reservoir performance of another zone in the same well bore, requiring separate completions and tubing , as a consequence project finance option was not available at this time. There was no hope of an equity funding to drill again so farm out was the only option.

The good news is that there is a route to free production cashflow without recourse to shareholders and the additional funding leaves chariot well cashed up.

In terms of reserves, we start with 637 bcf at 75% = 477.75 bcf and probably expected to give away 50% at least in a farm down to circa 238 bcf, instead we are getting 20% of a highly likely 1000 bcf = 200bcf, and if the O sands proove up as indicated by the seismic amplitude anomaly then it’s also highly likely that the O sand directly below anchois 1 also is gas bearing which will bring reserves to a gross 1.4 tcf or 280 bcf net to chariot, for no cash outlay by chariot.

The development plan includes a redrilled of anchois 1 so drilling slightly deeper to include the o sand below is very low cost.

The presentation states that the modelling of individual well productions demonstrated 100 to 200 mmcf per day per well, as I have suggested previously, so increasing daily production to 200 mmcf per day from three production wells is obvious but it hugely impacts positive cashflow.

The Gas in O sand and its thick reservoir have been proven in anchois 2 so this is a very low risk.

Chariot has a route to cashflow without any significant equity dilution risk.

I still think that the first onshore well will surprise to the upside, but let’s see what q1 brings.

Jimmy

I am also invested in chariot, and to days announcement shows the importance of getting a flow test.

Yes, the capex has increased substantially, but also the increase in daily production to 200 mmcf per day.

So while there maybe be some carried capex to be repaid from cashflow, the payback period is very fast at such high production rates.

Jimmy