Member Info for KeithOz

SDX are using the ONHYM rig, I don't know of anyone else who is lined up to use the SV101 this year.

I haven't posted here for a while, since (sadly) there has been nothing worth commenting upon. I am sufficiently sure that things are going to start moving, with the AGM next week, that I have made a substantial top up this morning.

The original Predator rig is available, and I can't understand how anyone could possibly think that DM is not aware of this. He will have been in continuing negotiations with Cluff and other drill providers. It is all part of the negotiation process that Cluff are advertising it as available to all comers - they want a higher price from HE1. DM is of course saying there are plenty of other rig options, he wants a lower price from Cluff. They will meet in the middle in the next couple of days, assuming they have not already agreed in principle, but nothing will be RNS'd until a formal legal contract is signed by both parties, hopefully with a penalty clause for non-fulfilment. They will have learned from previous mistakes not to announce anything until it is written in blood.

I will repeat what I have said here last year. I am fully confident in the geology and the follow-up work that has been completed in 2022, and am sure that a formal discovery can be declared at Tai-3. I am equally sure that HE1 will have a good-for-purpose drill in place in Q2 before the rainy season. This will result in the declaration of at least some Contingent Resources, a substantial increase in Prospective Resources and increased geological chance of success for the other prospects. The latter increase will show up in a revised CPR, based on a proven higher concentration of He (currently 4.4%) plus expanded reservoirs defined at Tai North & Itumbula North, as well as better definition of shallow Lake Beds reservoirs. I expect the 2023 CPR to be in the range of 300-500 BCF.

I only have one remaining concern. There are seven board directors. I have huge respect for Ian Stalker, and he is one of the reasons I am invested here - he also has a substantial shareholding. However, the other six directors combined hold less than 0.1% of the company between them, why do they collectively own less shares than me? I understand that they are currently in a closed period, potentially in possession of price-sensitive information, but once the air is cleared at the AGM, I would expect some concerted buying by the BOD - if this happens, it will help accelerate the inevitable share price increase.

The current market cap of just under £50M is not inappropriate for an exploration company with only Prospective Resources. By the end of 2023, HE1 should have doubled its Prospective Resources, initiated a Contingent Resource, and be approaching production - establishment of a producing Reserve is quite possible by early 2024, enabling access to funding routes that do not further dilute patient shareholders. I think it is quite possible that market cap could be £500M in a year's time, and if not bought out, a £Bn by early 2025.

I definitely wouldn't be out of this over Christmas?

Green hydrogen is produced by electrolysis of water, using electricity from renewable sources, ie solar & power. Since PRD is already established in Morocco, I would have thought that is a good place to start - I can personally vouch for the fact that the coastal region of SW Morocco has more sun & wind than any sane person can put up with. Despite this, Paul has previously talked about PRD setting up a project in Romania. Why Romania, which doesn't rank very high in the global sun & wind tables? Free money, that's why:

https://ec.europa.eu/commission/presscorner/detail/en/IP_22_4865

The EU has offered Romania €149M to invest in green hydrogen projects.

I see a couple of problems relating to the viability of green hydrogen:
- wind & solar are very expensive to set up, and offer very poor returns, which is why most wind & solar farms are only viable with state subsidies. The energy-in:energy-out equation is not at all favourable.
- producing hydrogen by electrolysis is an inefficient process. The hydrogen is then used to produce electricity again via a fuel cell for powering an electric vehicle - a second inefficient process, which has a fatal compounding effect.
-hydrogen is a very small molecule, so it leaks through even the tightest of valves. It has to be transported and used very quickly, otherwise there will be nothing left - a further inefficiency compounding the two already mentioned.

I can see genuine business returns from investing in oil & gas exploration, but get rather concerned when a business I am investing in is reliant upon the whims of state subsidies in order to be profitable, particularly if that state is somewhere like Romania.

Just my initial amateur thoughts, this is an area in which I have never operated.

When HE1 make a formal discovery, that will provide a boost to Noble, both to share price and ability to raise funds. Therefore, it is in Noble's interests to help facilitate HE1 getting a rig. I don't see a problem with a shared rig for Noble to drill their (flat) western prospects, assuming they can put in an angled borehole from land. I suspect they will need different rigs for the steep east shoreline and for submarine drilling.

My concern with Noble, other than the awkward topographical positions of their licences, is that they are further away from the volcanic region to the southeast that is driving the helium migration, and therefore may be outside the 'goldilocks' zone.

@madman - that was the old model beside the new, both are of the whole fan. Sorry you couldn't see the sticky jam in the bucket.

Just drill B1. If the target is as suggested a full year ago, then there will be enough money to buy whatever new projects you want. If it fails, there is still plenty left over from the £3.5M raised to spend on existing projects and/or new replacements. Not drilling it suggests either a complete lack of confidence in the underlying rationale for Kavango, or just a pretence to keep paying lots of peoples' salaries for as long as possible.

If you have a few seconds to spare, I have revised my model for the MOU-Fan.

https://twitter.com/KQuick20704342/status/1621711136197595138

Have a great weekend, everyone.

Seeing the share price go back up is more exciting than the Netflix vampire series that Mrs Oz is watching.

@kas - short answer, I don't know, really not my area of expertise, exactly why the stuff has been sent to the lab. It would be nice if practicable, but would be reliant upon the current drill fluid not being too contaminated - could be difficult to filter out ultra-fine particles.

@Trifle. I agree, in fact it was what I was trying to say but didn't word it very well. Yes, 2 wells are a necessity for a large consumer who is reliant upon you, because they will insist on a supply contract with a penalty clause for non-supply in order to cover themselves. But for someone who is using relatively small gas volumes as a secondary energy source, one well is fine, and I am sure in the current environment they would be delighted to buy a few months' supply at a reasonable discount to market price, and Paul & Lonny would be delighted to sell it. Do not understand the 'we are all doomed' mob on here, there is more than one way to skin a rabbit.

Missed out on the sub-6p bargains first thing this morning, had to pay the outrageous sums of 6.07/6.08 a few minutes ago. Don't I get a discount for all this work?

I wasn't suggesting a CUL, and I'm sure that would be Paul's last choice after his comments about the one he took out to initially get the Guercif licence. He has also made it very clear that he is not going to rush a farmout - definitely not before completing MOU-A, probably not until next year. I think he would be considering:

1. See what savings can be made from downscaling the MOU-1 test. He was suggesting just doing the main zone, which should give 80% of the flow - almost certainly enough to provide an economic operation (although 2 wells are necessary to provide security of supply.)
2. The longest lead time for MOU-A appears to be the casing. Perhaps make a temporary saving by not ordering anything with a shorter lead time, ie that is not on the critical path
3. As has been mentioned, there are always continencies budgeted for exactly this sort of unexpected problem - usually 10-20% of the total budget.
4. Once MOU-1 has been shown to have real live gas, even if an extended flow test has not been completed, then I would think there would be quite a few Moroccan entities interested in a forward purchase of gas.
5. There is an MOU-2 flow test budget that could be 'borrowed' to buy drilling fluid, and reassigned to its original purpose after (4) above.

Probably a few other things I haven't thought of.

How much will a change of drilling mud cost? Assume the borehole is 1500m deep, 22cms diameter. It is larger bore at the top, but drill rods will obviously take up some internal volume (typically about 8cm diameter), so for this rough calculation let's stick with 22cms. The volume will be pr²d = 57,000 L. Assume a standard density of 3.8, gives 217,000 kg. The cheapest bog-standard bulk calcium bromide on Alibaba (yes, I know) is $400/100kg, which gives near enough $868,000. I can't see Lonny using that, so clearly the costs are going to be substantial.

I suspect that Paul was being a little evasive on cash requirements because they simply don't know at this stage how much finishing MOU-2 is going to cost, nor how much they can save by downscaling the testing on MOU-1. As others here have correctly noted, there are ways of getting hold of cash - if it is actually needed - other than a placing.

erm, the potassium-rich mud they are talking about in the article is drilling mud, not natural mud. Our problem is natural very fine-grained sediment derived possibly from volcanic ash (that's only a guess). That natural sediment contains an unusually high proportion of potassium, which is interacting with the drilling mud. Adding any of the four types of drilling mud mentioned in the article will make matters worse.

PHPA (partially hydrolysed polyacrylamide) polymers work with ordinary natural mud by wrapping themselves around the mud particle and preventing the ingress of water - wet clays/muds swell and block the borehole. These are very commonly used, but we seem to have a more specific problem with an ionic clay chemically reacting with the drilling mud. Lonny is absolutely correct to get a full lab analysis done before spending what would be a lot of money on a complete load of new drilling mud, which might still not solve the problem.

@Splice. Plenty of oil - I posted this on Twitter almost a year ago:

https://twitter.com/KQuick20704342/status/1504653923541393408

Apologies if I snapped at a few people - there seemed to be an agenda developing while the presentation was still running, I am happy to be wrong :-)

Now, MOU-A.

The multiple changes of names for prospects and wells are at the least confusing. MOU-1, MOU-2 and MOU-A are the latest names for the wells drilled into the MOU-Fan prospect. MOU-A is either the new name for what we used to call MOU-5, or else it is in a very close position. I have gone back through the old presentations, and extracted comparative data for these 3 wells, for each it is the most recent numbers I can find.

Structural area, km²: MOU-1 : 2.8, MOU-2 : 14.3, MOU-A : 32
Gross reservoir thickness, metres : MOU-1 : 72, MOU-2 : 168, MOU-A : 65*
* MOU-A reservoir number appears only to be the TGB-2 sands, but shallower reservoirs are also expected in the TGB-4 & TGB-6 sands.
The 2020 CPR, which Paul says will be updated soon, indicates MOU-A gross Prospective Resources of:
P90 - 148 BCF, P50 - 426 BCF, P10 - 879 BCF.

Currently, for the 3 combined, we have P10 : 294 BCF, P50 : 819 BCF, P90 : 1823 BCF

Everything I have heard since the release of the two CPRs (porosity, permeability, seal quality, sands thickness, high pressure) would suggest that the indications are that we are likely to be closer to the High Estimate rather than the Best Estimate, and that all these numbers are likely to be on the conservative side. Of course, I could be wrong, just need to do one and a bit more drills, and three flow tests.

So two people who didn't watch this say it was a car crash? One person still complaining that testing equipment is not sitting waiting, obviously didn't listen to Paul's detailed reply. Presumably none of them are invested.

*re. the rig staying on site "No costs for the next couple of months at least"

*P10 (high end) resource estimate requires only 40-50m net pay. Interesting that there appears to be much thicker sand than expected in MOU-2.

* Top of reservoir sands likely to be up to 100m deeper than pre-drill estimate - therefore higher pressure, more gas per cubic metre of reservoir.

*"one or two parties more interested in the oil" - they would do the required 3D seismic.

*25% to be relinquished this year, no firm time frame, no problem, they know which bits they want to keep.

* Premature to talk about funding, still doing the sums, main unknown is cost of replacement mud.

* Main timeline unknown is due to sourcing of mud of yet unknown composition.

*MOU-A earliest date is end of H1 23, due to lead times for casing.

*Elegant solution to bringing in a partner to finance development - they buy a minority stake in the Moroccan subsidiary company, can be done quickly without ONHYM, etc approval. Option to acquire majority stake at leisure.

All in all, the Guercif area has a remarkable geological history that makes it incredibly prospective for hydrocarbons, which is why some of us here are jumping up and down so excitedly. Presentation time.

All Louis10 does across many BBs is to promote the contentious & dubious views of Oilman Jim's paid blog. He's a pita, I would have thought the whole world would have filtered him by now.

@Matt. The Gurecif graben was a deep rift for millions of years, forming the connection between the Atlantic & Mediterranean. Lots of sediments (km deep) were laid down, including many rich in organic matter. Tectonic movement between the European & African plates caused this to sink, exposing it to geothermal heat & pressure, and loading it with even more sediment.

Rivers formed deltas to either side of the graben, and the sediments from these formed underwater landslides - turbidity currents - down into the deeper water of the graben, which were laid down on top of the pre-existing organic-containing sediments, forming turbidites, which have alternating layers of sands & shales. Some of the turbidites are fairly uniform, others more chaotic. They will be thicker the closer you are to the graben edge - in the case of the MOU-fan, the edge of the graben is to the East.

The organic matter in the deep sediments gave rise to gas and/or oil, depending upon the temperature and pressure. These hydrocarbons then migrated, mostly upwards, along the numerous faults caused by the ongoing tectonic events and pooled in the porous sandstone, trapped by overlying mud/shale seals.

Finally, the two tectonic plates squeezed together again, uplifting the oil & gas reservoirs to a shallow enough depth for Paul & Lonny to drill down to them relatively inexpensively. That's the abridged version, of course.