The latest Investing Matters Podcast with Jean Roche, Co-Manager of Schroder UK Mid Cap Investment Trust has just been released. Listen here.
Then, we have from the Auctus Advisors report:
Gross contingent resources: 637 bcf
Gas selling price in Morocco: US$ 11/mcf
Royalty: 3,5%
OPEX: c. US$ 1/mcf
CAPEX: initially US$ 350 mm. Mid life: US$ 60mm. Total: US$ 410 mm. Equivalent to US$ 0,64/mcf
Gross Undiscounted Free cash flow (FCF)= EBITDA - CAPEX
FCF= (Gas price US$ 11/mcf - 3,5% royalty - OPEX US$ 1/mcf - CAPEX US$ 0,64/mcf): US$ 8,96/mcf X 637 bcf: US$ 5.710 mm
Net to CHAR (75% WI): US$ 4.283 mm
Almost all of this FCF will be tax free.
And this is only from the already discovered contingent resources.
Please AP: stop all this nonsense about green hydrogen and renewable energy projects. As a shareholder, I don´t want to see my (potentially very lucrative) interest in Anchois being heavily diluted, just to install a few solar panels in Zambia or Burkina Faso.
Regards
Excerpts from Auctus advisors´ report:
"Following the Anchois-2 well result, 2C contingent resources have been upgraded to 637 bcf."
"A final investment decision is expected to be taken in early 2023. The development of Anchois is expected to be based on 3 subsea wells to achieve first gas in early 2025 and production of 70 mmcf/d (gross) initially increasing to 100 mmcf/d by the end of year 2. The overall remaining development cost for the A and B sands to first gas is estimated at ~US$350 mm (gross) based on the re-entry of the Anchois-2 well and most of the capex associated with the subsea infrastructure and a 100 mmcf/d onshore processing plant. Additional compression could also be required after 3-4 years of production, estimated to cost ~US$50-60 mm (gross). "
"Financing: The key steps to funding the project include the securing of gas sales contract (see above), debt funding (Reserves Based Lending) and equity funding. 70% of the project cost to first gas is likely to be funded with debt (~US$245 mm). Société Générale has been appointed as lead bank with the potential participation of Moroccan banks. The balance of the cost of the project is likely to be funded by a combination of pre-pay and industry participants. Given the strategic nature of natural gas, the very strong economics of the project and very large running room with regards to the resources volumes, we have assumed that the company would secure a farm-in partner, where a stake (we have assumed 25% WI) in the company’s licences would be sold in return for a carry and a refund of past costs (~US$40 mm). The overall net equity funding exposure of Chariot post farm-out and pre carry and past costs refund is only US$55 mm. In 2019 and for a project with smaller resources (410 bcf for IOG compared to 637 bcf for Anchois) and lower gas prices at the time, IOG was able to sell 50% of its UK SNS gas development to CalEnergy (Warren Buffet) for £40 mm in cash plus a net carry of up to £125 mm. Given the strength of the economics of the Anchois, we believe Chariot should be able to attract a 25% farm-in partner on terms sufficient to reduce its net equity exposure to zero."
"We are forecasting 70 mmcf/d gross production at Anchois from 2025 increasing to 100 mmcf/d in 2027. Fiscal terms in Morocco consist of 3.5% royalty, and 31% corporation tax but there is a 10 year corporation tax holiday from start of production. "
"With heavy fuel oil being the main substitute for gas, domestic Moroccan gas prices are very high. We note that SDX Energy’s gas realizations are ~US$11-12/mcf in Morocco. "
"Is it possible that future phases of Anchois / Lixus / Rissana could have their own pipeline to Europe?"
Totally unnecessary, in my oppinion.
There is enough capacity in the GME pipeline to transport all the gas we could produce.
There is not need to overcomplicate the business model.
Regards
Hi Jimmy.
You wrote:
"There are two gas powered electricity power stations that consume most of the gas in Morocco, so once they are fully supplied, the balance can be exported."
Sound Energy (SOU) has already signed a gas sales agreement with Morocco's Office National de l'Electricité et de l'Eau Potable ("ONEE"), the state power company of Morocco. SOU will supply gas for domestic power plants for gas-to-power generation (transit via GME line), minimum volume of 0.3 bcm/year.
It´s highly likely that, by the time Anchois gets online, the domestic demand for power generation will already be attended by Sound.
The price for the minimum annual volume guaranteed by ONNE is US$ 7,93/mcf.
See SOU´s announcements here:
https://www.lse.co.uk/rns/SOU/tendrara-gas-sales-agreement-signature-of-mou-fsnd93u8g3ie3yv.html
https://www.lse.co.uk/rns/SOU/gas-sales-agreement-phase-2-tendara-development-e3qvzzki3znghkf.html
Regards
Local gas demand in Morocco was c. 120 mmcfd in 2021.
Future gas production:
- Sound Energy is expected to be producing c. 65 mmcfd by 2025. It already signed 2 gas sales contracts: one with local group Afriquia Gaz, to provide c. 10 mmcfd to local industrial customers, and one with ONEE (local electricity distributor) for c. 30 mmcfd
- SDX is currently producing 7 mmcfd, and they expect to keep increasing production.
Assuming they produce c. 15 mmcfd by 2025, we have:
Demand: 120 mmcfd
Production:
Sound Energy: 65 mmcfd
SDX Energy: 15 mmcfd
Total production (before taking account Anchois): 80 mmcfd
Local market déficit forecast for 2025 (before Anchois first production): 40 mmcfd
I´m sure that our partner, the state company ONHYM, will ask us to first attend the local demand, before sending any remaining gas to Spain.
Then, if CHAR produces 70 mmcfd in 2025, we will have to sell the first 40 mmcfd in the local market, and will have a surplus of 30 mmcfd to export to Spain.
This is exactly the breakdown of oil sales forecast by Cenkos in their March 2022 report (see page 16 of the report).
One consequence of this reasoning is that we can not fully take forecast european gas prices as the basis for the calc of the NPV of our contingent resources. For the amount of gas to be sold locally, these prices are not relevant at all.
Regards
Yes Jimmy.
The upside is enormous. The current price in Spain is Euros 172/MWH (equivalent to US$ 50/mcf)
Source: https://www.mibgas.es/es
I would like to see a revised development plan with enhanced facilities/pipelines, and lots of drilling in 2023 and 2024, in order to have explosive (and tax-free) production numbers from 2025.
Regards
F
Hi Jimmy:
When CHAR inform the best estimates of contingent resources assigned to Anchois (previously 361 bcf, now 637 bcf) are they talking about gross resources, or net to Chariot?
I always understood that they were net recources to CHARIOT.
But, looking at last December presentation (page 21), it showed 361 bcf of best estimate contingent resources (the estimate before recent drilling), with the following foot note: "Source: Estimates of Gross Contingent & Prospective Resources from NSAI Independent Resource Assessment 2019, 2020"
What do you think?
Regards
Fernan
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
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