Member Info for Jimmy23

Further cost savings for green hydrogen described at
https://newatlas.com/energy/aemwe-kist-hydrogen-electrolysis-anion-exchange/
Jimmy

Just to clarify, the 10 meters per second wind speed is at 100 meter height offshore.
J

Thanks jimzi,
Because I intended to reduce the value of the offshore power by 50% to allow for ammonia production and transport, a wild guess because I don’t have the detail, it still comes down to £0.08 per share for just the first phase.

Hi Jimzi,
It’s great to have someone with some knowledge of green power npv values.
So if we develop your calculations a little further 45 mw offshore is npv valued at $90 million and chariot plan to initially do 300 mw = $600 million .
Chariot plan to increase this at a later stage to 10gw , but let’s leave the upside for the moment.
Say they keep a 15% interest that’s $90 million
Adonis stated on the conference call that initially the green power would be used to produce ammonia as a fertiliser , which is currently produced with now high cost natural gas. So let’s say that’s only worth 50% it still means that the initial green project is worth £0.082 per share.
Then there is the upside of 10gw of power potential which they announced.
Another unicorn
Jimmy

Hi Seattle optimist.
I have been struggling like many others to try understand why this share price is not at least 50p based on the excellent results drilling results to date.
My current view is that chariot increased its share capital by over 100% in 2021 at very much cheaper prices, along with an underwriting agreement which had an exceptionally long closing period, all of which overhung the market. This overhang will end and value will prevail.
With regard to the hydrogen project, the market does not understand the economics of this project although it has very high potential in the future, it was in effect an insurance policy in case anchois did not work. It’s costing very little at the moment , but once the economics and partnering are established, a de merger into a separate listed company is a logical step, but not now.
I have read up quite a bit on the economics of green hydrogen and it appears that the key ingredient is a high availability of green electricity, independent reports suggest Mauritania could have > 70% availability , this arises because of high offshore winds in the Atlantic blowing into the Sahara desert . These have been measured at 10 meters per second at 100 meters offshore, which generates very efficient power and very low cost. But lots more details to follow, ideal for a de merger,
Jimmy

The gas price formula for morroco is that gas is priced at the energy equivalent of heavy fuel oil which is based on Brent oil prices. Heavy fuel oil is currently used to generate electricity at kenitra.
Roughly calculated at 10% of Brent oil prices plus $0.50 per mcf.
Brent is currently $89 per bbl so the gas price is roughly calculated at $8.9+0.50= 9.40 usd per mcf, compared to the chariot forecast of $8.00 per mcf.
Based on my calculation of the new proven reserves of 750bcf of gas a $1 extra gas price generates $750 million in revenue for the field, less royalties of 3.5% pro rata to chariots 75% interest / 3 to get npv value and at an fx rate $1.35/£1 divided by 810 million shares in issue= £0.16 per share extra value based on an extra $1 gas price when $1.4 extra at the moment.
$300 million capex could be funded by the increase in gas prices .
Jimmy

Henry
If this was just another exploration project I would agree with you.
But we’re proven reserves there are just so many finance options.
This project is ideal for standard project finance with the support of venture debt if necessary.
No company would ever say they will never issue more shares, it’s just that equity is not necessary now. . As Ap is such a significant shareholder he will want to avoid shareholder dilution.
Jimmy

Thanks bouncycat,
It’s always good to get someone to double check these calculations.
Jimmy

Hi fernan
Good points.
My comments.
1. On the conference call Julian stated that onhym would pay their share of costs from the date of the issue of the production concession.
2. You are correct that banks typically require a 75:25 debt equity ratio, however they usually allow past costs as a contribution to the equity component, particularly importanas two suspended wells to be used as producers.
3. Julian hinted they might outsource the pipeline costs, reduce capex, increase opex and reduce debt equity level.
4. Given the very high levels of cashflow to be generated, some subordinated secured higher yield debt could work very well in these situations and possibly finance anchois north and west and deepen o sand at anchois 1.
The key to all this is the revised reserves and to finalise the offtake contracts. A lot to do but so very much do able with this new well results.
Jimmy

Fernan
The gas field model assumed that first production started in 2025 and hence production was tax free till end of 2034.
However , I modelled this that anchois north and west would be drilled in 2028 with an increase in production in 2029 so if these were separate fields they would be free of corporation tax till 2038 instead of the model cashflow of end of 2034.
Obviously a high level anslysis but it certainly confirms the huge potential here.
Jimmy

The lab results for gas and fluid analysis could be available within a further week or two.
Gas and water pressures will be known already.
Analysis of the 12 sidewall cores to determine permeability and reservoir sands classification could take a couple of months.
In the meantime the reservoir models will need to be updated and the well production completions need designed to make sure that individual reservoirs performance are optimised and reservoir pressures don’t interfere with each other , possible requirement for different production tubing for different reservoirs. All good reservoir engineering issues which will be standard work for the subsea team.
Jimmy

For reference I included anchois north at 600bcf and anchois west at 300bcf.
I should have included O sands below anchois 1 at an additional 200 bcf.
So more upside, will recalculate later.
Jimmy

SHC and fernan.
I have prepared a simple. Field economic. Model with two scenarios.
1, capex $350 million, opex $25 million and royalties 3.5 % on , revenue, no corporation tax first 10 years, gas price $8 mcf base on initial daily production of 70,000 mcf per day for 355 days production per year , abandonment costs $70m. Reserves of 750 bcf proven by anchois 1 and 2, assumes 100% debt finance at 6% interest. First production. 2025.
Based. On 810 m shares in issue the 10% npv is £0.54 per share.
The. 6% npv. Is £0.90 per share.

Scenario 2 .
Drill and complete. Anchois north and anchois west at drilling cost of $45 million , plus’s hook up and commission additional $45 million funded from production cashflow in 2028 , increasing daily production to 200,000 mcf per day. I have taken a conservative view and not claimed the new field 10 year corporation tax free period, so corporation tax at 31%.
10% npv per share £1.38
6% npv per share £2.33

The free cashflow undiscounted to 2056 from the anchois central, north and west , unrisked is calculated at $6.4 billion . So plenty of funds for big dividends.

The project valuation is particularly sensitive to the discount rate, and using a 10% rate when finance costs are likely to be less than 6% is a conservative view.

So you might ask, why be optimistic about anchois north and west.
The recent drill results have demonstrated that with 7 reservoirs they each seem to a different gas water contact. The logical conclusion of that is that firstly the field boundary fault are acting as a separate seal for each reservoir and with different gas water contact there is no pressure communication between each reservoir, otherwise there would be a common gas water contact. This means that even very thin shales between the reservoirs are acting as reservoir top seals.
It is reasonable to assume to such conditions apply to anchois north and west.
Spectral decomposition of the seismic shows both the reservoirs and the gas and water contacts in north and west which validate the geological model, confirming the presence of gas with a high confidence rate.chariot report that geological appraisal success rate in the onshore section of the same basin is 85%

The key next steps are,
1 lab results,
2. Revised 2c reserve estimate for results of anchois 2 new proven gas.
3. Gas sales agreement
4. Finalise development plan,
5. Project finance

This is a very strong project based on the information disclosed to date.
Very strong buy.
Jimmy

SHC, fernan
Working on the high level model based on assumptions previously discussed, not yet finished, will advise later.
Jimmy

Note . The deepening of the anchois 1 well is to produce from the O sands which are derisked by the recent anchois 2 well results.

Fernan, SHC,
Firstly, my estimate of current 2c reserves is 750bcf , with a further approx 200bcf to be added if they deepen the anchois 1 well to produce from the anchois 1 well.
I agree that the priority is to get production cashflow ASAP, start by producing at 70,000 mcf per day and use cashflow to quickly repay capex loans and then use cashflow to deepen anchois 1 well to the O sand directly below, drill anchois north which is substantially derisked and add a further 600 bcf of low risk reserves, drill anchois west with a rough estimate of 300 bcf, this easily is capable of generating 200, 000 mcf per day, or $1.6 m gross field revenue per day.
The cost of drilling such wells is probably around $15 m per well x 3 , easily findable from production cashflow or indeed some debt secured on the production cashflow.
The key feature here is to ensure the pipeline has the capacity for 200,000 mcf per day.
The npv of this is huge. Will need to do a quick spreadsheet on this but it’s likely to be in $billions.
Will revert later on calculations
Jimmy

Thanks to AFC for the investors chronicle post.
While it’s great to have Simon Thompson endorse chariot, I think he got his sums wrong,
The risked valuation for the A and B sands is 0.50 plus 0.04 p for the rest of the lixus licence, and that’s after assuming chariot sell half their 75% interest. The extra value of the C, M and O sands which are now proven by the recent well adds a further 29 p a share, total 83 pence .
That’s how I see it.
Other views welcome
Jimmy

Hi Henry,
The chariot annual report provides more detail on the development economic. 70,000 mcf per day at $8 per mcf, capex of $300 million.
At the presentation Julian advised that opec was low $20 million per year, so suggest you use $25 opex per year, there is also a 3.5% royalty on sales.
That’s before the extra reserves , proven by the well. Duncan CTO also stated that the incremental cost of producing from these extra proven reservoirs would involve a little extra capex only.
The key to the project financing is the letter of intent for a gas sales agreement for 40,000 mcf per day at $8 mcf with the Morocco state. It should be fairly straight forward to sell the gas to the kenitra power station that currently burns heavy fuel oil, way more expensive and dirtier than gas.
Even at 70,000 mcf per day the project achieves payback within 2 years, which is why two banks issued an loi to provide the project finance.
The actual funding could be reduced significantly if chariot outsources the pipeline , which Julian hinted at during the presentation, that would just leave the subsea completion and a further production well and onshore facilities. That would reduce capex by at at least $100 to $150 million , that will payback very rapidly, so I don’t see a difficulty financing this, obviously lots of work and legal but very doable. A 50% discount for such risk is very harsh to me.
The investor chronicle article is good third party endorsement.
Hopefully this will attract a lot of new investors at such incredible low prices.
Jimmy

Henry
What’s unusual about the share price is that the fin cap valuation note assumed a 50% farm out and only that was only in respect of the A and B sands only , there is at least double that based on the well results as we have more than 100 meters of net reservoir, and still the fin cap valuation of was 54p ,
We are now at 9p hard to believe, incredible value .
Jimmy

I expect a significant increase in net pay from the 100 meters reported also.
Page 11 of the presentation details the coring samples, note there are 12 cores taken, yet there are only seven reservoir sands reported, looks like extra reservoirs to report.
This is also validated by the note on page 11 that a new reservoir imaging tool has identified additional reservoirs below log resolution which have been tested and sampled for gas.
So definitely upside here . The lab results will confirm these new zones contain gas, this will then need to be crossed checked to the wireline logs and the vertical seismic profiles and quantified as reserves across the field.
A lot of good news to look forward to , starting with the gas analysis lab results which should be fairly quick.
The lab analysis of the sidewall cores will take a bit longer, but will form an important part of the field reservoir model.
Obviously a pity that not more gas found in the compartmentalised O sand , however there is probably approx 200bcf of gas in the adjoining down dip compartment. Expect news on this also.

Would be good to get another brokers report following the presentation

Jimmy