Member Info for Fernan10

The count is:

1. Long Term Incentive Scheme (LTIP):
Share awards outstanding at Dec 31, 2021: 28.242.865 (source: note 21 to 2021 FS)

2. Non-Executive Directors' Restricted Share Unit Scheme ("RSU")
Share awards outstanding at Dec 31, 2021: 8.755.156 (source: note 21 to 2021 FS)

3. Post-acquisition share-based payment charge
Contingent payments representing a maximum of 3,964,192 new ordinary shares are payable to key members of the AEMP team (source: note 21 to 2021 FS)

4. Grant of Deferred Share Awards in 2022 (Aug 12, 2022 press release): 16.263.940 shares

5. Non-Executiv directors´s matching Awards in 2022 (Aug 12, 2022 press release): 680.145

Total share awards outstanding: 57.906.298

We should expect a 10% dilution from current and future share awards in a 3-4 years´time.

Regards

The annual free share awards (subject to vesting conditions) is equivalent to roughly 1.7% of the share count. After 6 years, if it keeps at the same level, it will be around 10% of the future share count. In order to take account of it, I think it´s reasonable for us private investor to adjust our long term target prices accordingly (e.g., a 10% reduction in a 6 year investment horizon).
Regards

According to the CPR, the amount of prospective resources to be drilled through the Gazania well (including the potential side track) will be 491 mm bls (100% gross, best estimate).

Net to ECO (50% equity interest in the project): 246 mm bls

Breakdown of the prospective resources:
Namaqualand prospect: 191 mm bls
Gazania prospect: 208 mm bls
Perlargonium prospect (potential side track): 92 mm bls
Total prospective resources (100% gross, best estimate): 491 mm bls

Source: last CPR report, page 118

https://www.reuters.com/article/ukraine-crisis-spain-energy/new-gas-pipeline-linking-spain-to-france-could-be-operating-in-8-9-months-idUSS8N2YF0KD
This pipeline will prove to be very usefull for us in the long term. I hope we will be able to take advantage of it, in order to sell our future gas production in diverse european countries, aside from Spain.
Regards

https://www.reuters.com/article/ukraine-crisis-spain-energy/new-gas-pipeline-linking-spain-to-france-could-be-operating-in-8-9-months-idUSS8N2YF0KD
This pipeline will prove to be very usefull for us in the long term. I hope we will be able to take advantage of it, in order to sell our future gas production in diverse european countries, aside from Spain.
Regards

Anyone potentially interested in farming into the 3 wells exploration campaign will do basically the following math:

Gas in place for the 3 exploration prospects (TE4, SBK1 and M5): c. 1.200 bcf (best estimate, 100% gross) (see press release)
Gas in place (net to SOU): 900 bcf (75%)
Recoverable gas (assumption): 1/3 of gas in place: 300 bcf (net to SOU)
Recoverable gas (net to farm in partner, assuming that the partner gets the standard 50% economic interest of SOU´s original 75% in the projec): 150 bcf
Net present value of recoverable gas: US$ 2/mcf (assumption).

Potential net present value of the exploration campaign for the farm in partner, in case of success: US$ 300 mm

Investment by the farm in partner to drill the 3 wells (at a cost of US$ 8 mm/well): US$ 24 mm

So, the potential farm in partner should have to decide if the geologic risks justify investing US$ 24 mm to drill 3 exploration wells, in order to potentially discover natural gas up to a net present value of US$ 300 mm net to it.

Regards

It seems that the current status of the tax claims is the following:

SEME subsidiary: There is liability of US$ 2.75 million that has been confirmed both by the Local Tax Comitee (LTC) and a court. The company is currently appealing the judge decision.

SARL AU: the company has a contingency of US$ 22.5 million, with the following breakdown:
- Value Added tax and witholding taxes: US$ 22.2 million
- penalties: US$ 0.3 million
The company has appealed these claims to the Local tax commitee (LTC), which has up to 12 months to make a decision.
See note 8 to 2021 Annual financial statements

Regards

Maybe.
MS made a clear diferentiation of the effect of each claim on company´s operations and cash flows. There should be a reason for that.
Time will tell.

I was not talking about the reason for the tax claim...because I don´t know exactly what are the basis for it (I think nobody here knows)
I was talking about the eventual responsability of related companies within the same group, when one dormant subsidiary with no assets is charged with a tax obligation.

Maybe SARL AU never had assets. It´s only "asset" was an exploration license that was relinquished, originating the current tax claim. In that case, I don´t know if the moroccan tax authority will have the right to pursue other SOU´s subsidiaries, in order to receive the amound due by SARL AU.
Regards

I don´t know the moroccan tax legislation, nor the local rules about liabilities.
But, if the SARL AU subsidiary is a limited liability company, with neither assets not operations, there is a chance that the moroccan tax authority will have no assets no take in order to make good the tax claim. It´s likely that the tax claim was raised by the state after the company got "dormant".
Maybe that´s what MS tried to say in the Q&A session.
Unless, of course, the moroccan legislation gives the state the right to pursue other companies within the same group, in order to receive the amount due by SARL AU.
I don´t know. It all depends on the specifics of the moroccan tax laws.
But I´m sure MS had something in mind when he said that.

Regards

You can listen to the question to Mohammed about the tax contingencies of both subsidiaries, and his answer, from 42:38 in the video of the Q&A session.
Regards

In the Q&A session that took place on May 30, one of the managers (I think it was Mohammed Seghiri) said that, because SARL AU is a "dormant" subsidiary, its eventual tax liability will have no impact on SOU´s operations.

Regards

The Anoual drilling is included in the "drilling package" of 3 wells currently being offered to potential farm-in partners, together with 2 wells in the Tendrara license (SK-1 and TE-4, if my memory is good).
So far management hasn´t said a word about how are we going to accomplish with the minimum seismic contractual obligation in the Sidi license.

Regards

Hi Jimmy.
I noticed the production rates forecast in the HIS Market report:
https://ihsmarkit.com/research-analysis/moroccos-anchois-discovery.html
Phase 1: initially 40 mmcfd, ramping up to 70 mmcfd in year 3
Phase 2: c. 100 mmcfd from 2.030 on
At these production rates, if Anchois has c. 1tcf of gross reserves, we will spend more than 30 years to deplete the reservoir.
Production after the 10th year will have a minimum effect on NPV, not least because of the uncertainty about gas market prices in that distant future.
It doesn´t matter if the upcoming CPF informes additional reserves, if those reserves are going to be put in production 15 or 20 years from now.
Is it possible to substantially increase the initial production? What is the maximum production rate doable? How many wells do we need to drill to achieve that rate? From the HIS Markit repot, each well seems to have an initial production rate of c. 20 mmcfd
Is it possible to drill 2 or more wells simultaneously, by contracting more than one drilling rig, in order not to delay first production?
why don´t we drill 10 additional wells after FID (5 wells in 2023 and 5 in 2024), to have an initial production rate of c. 240 mmcfd (including the 2 wells already drilled)?
The cost of drilling those 10 additional wells will be c. US$ 210 mm.
EBITDA from a production rate of 240 mmcfd could be hundreds of US$ millons per year (net to Chariot) depending on natural gas prices.
At forecast gas prices for next year, the cost of drilling a well (c. US$ 21 million), with an initial production rate of 20 mmcfd, could be repay in less than 2 or 3 months. The opportunity is now.

Regards

Fernan

Anchois-2 had a drilling cost of US$ c. 21 million (see May 24, 2021 news release).
Assuming that drilling the satellites will cost about the same, then we will need around US$ 100 million to drill all of them (Anchois N, W, NW, SW and WSW).
Maybe we can avoid to drill Anchois NW, that has only 29 bcf of prospective resources. (see May presentation, page 21). Instead of that, we can go deeper in one well to explore the potential of the Sub-Nappe play, keeping thet total drilling budget around US$ 100 million.

Regards

Ok Eric. Thanks for the info. Very appreciated.

Regards

The research notes assumes that Sound keeps the original 75% of the equity for phase 2.
We don´t have the money to fund our equity contribution (c. US$ 60 million, as per the latest press release). Then, our equity interest will have to be reduced. I`m assuming a 50% farm out.
By the way, I would like SOU to reinvest most of the cash flow in exploration, instead of paying a dividend.
Our drilling cost in Tendrara is c. US$ 8 millon per well
At current european gas prices, a gas discovery could have a NPV of US$ 2.5/mcf (my own estimate).
Then, a potential 1tcf discovery, divided by 2.5 b shares outstanding (my own estimate), will have a NPV of US$ 1/share. Better than receiving this US$ 8 millon as a dividend.

I have always thought that the chance for a big share price appreciation will have to come from exploration, funded out of operational cash flows.

Regards

Fernan

There was someone here that became excited a few days ago about the potential 3-wells carry in block 3B/4B.
Today Gil talked about "drilling 1 or 2 wells in 3B/4B" (7:00 minute in the interview).

This guy has cero credibiility.
He pumped a lot of bad failures in the past. I can mentioned a few: Sound Energy, Victoria oil and gas, Caza oil and gas, etc, etc