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TSX Lithium explorer International Lithium Corp prepares to drill at Raleigh Lake
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Member Since: Fri, 31st May 2013

Number of Share Chat Posts (all time): 1,484
Number of Share Chat Posts (last 30 days): 72

Last Posted: Tue 12:22

Post Distribution over the last 30 days

Tue 12:22

@Proffit I am currently away on holiday until next week but have of course kept an eye on my investments. I wanted to wait for the expected interview before judging and as expected everything is developing as expected. They have hit every deadline so far on what has been a fairly sporty programne, and I expect the partnering deal Isa lot closer than many are prepared to appreciate.

With all due respect the talk of placings etc has no grounds when the company has around $17m in the Bank and is seeking a partner to pay a healthy portion of the costs on a license that is proving to be as valuable as was advertised. To continually judge the company on historic evidence that came from a time when they had no material discovery on the books, is simply wrong. In my opinion, at these levels, this is screaming buy. But it is for the individual to decide against their own research.

Until next week.
Thu 10:03

Suresh786 I have tried to include my thoughts on questions in my reply to O&W but the key message for me is that this gas discovery was handed on a plate to CHAR (yes that company that does bad deals apparently), that does not mean that it will then automatically be handed to someone else in the same manner.

It is worth more than just an appraisal well carry because it has come far enough down the risk ladder. So yes I expect a drill plus some help with the development costs. The exploration well is phase 2 and isn't required for the first 10 years of gas at 90mmscf/d, so it doesn't need to be in the discussions with any front end partners.

This is just my opinion of course, no more.
Thu 09:57

(2 of 2)

Thus far my investigations demonstrate that it should be well within reach although I would wish to take a further look at this when the FS is released shortly.

What is important to remember is that the government partner and holder of the remaining 25% of the license ONHYM, at development level, which is where Anchois 1 would be post appraisal well, is responsible for its full share of the development costs. So no free carry, which is very important in all of this.

Any potential partner that comes in is negotiating a percentage of of a very profitable low risk gas play (and this is in part dealing with Suresh786 question), that they would in my view of gladly paid for had it been available to them. CHAR have secured 75% for just a $1m commitment to seismic. They don't even need to commit to a drill because over $100m has already been spent on the play through the 4 drills that have taken place.

I am looking for a circa 50/50 split so around 37.5% each. For CHAR to give that away for just $15m for an appraisal drill would be criminal. I expect multiple interest because I view the CAPEX as being fairly low (currently $350m of which 75% = $262m is with CHAR and their partner). For a very good chance at a 22 year plus gas project of oil equivalent 16,000 bopd, that is very manageable and would leave ample room for further payments. Paticularly when we see that the gas play has the potential (be it more risky) to more than double in size on further discoveries at the many satellites around Anchois.

So I expect the appraisal to be covered + a cash payment that at the very least would help CHAR on its way towards its share of the development costs. It may not be big money but at a total contribution of say $130m, even 20% would help set up CHAR for debt financing facilities for their share.

That said I do still fully expect sizeable dilution but at just 365m shares in issue and 37.5% delivering 6,000 bopd equivalent, the stock can handle it.

The above are just examples. I have no idea how much CHAR really wants of this play but what it shows is just how doable it all is when the hard work of exploration has been done and one is left still holding 75% of the license. That wouldn't happen on a wildcat. So they have far more aces in their hand than ever before and from these levels I expected to be rewarded well for my support.
Thu 09:43

(1 of 2)

@Olderandwiser Good morning I trust you are well and many thanks for your kind words.

I am just about to jet off on holiday for 10 days but wanted to respond to your questions.

In my opinion the two stocks aren't in the same league in terms of impact and standing, but as is the way with AIM, CHAR with the right tailwinds has the ability to outperform BMN over the next few years simply because it is coming from such a low base.

That said I fully expect BMN to be sitting at several multiples of its current price within the next 2 years because the market has still to factor in its energy platform, which is coming on very well now.

The key difference in terms of standing right now is that CHAR has a perceived history of doing bad deals for its shareholders. The trouble is that analysis is based on a minnow oil company attempting to convince major partners to join it on a wildcat drill. Those sorts of deals place CHAR bargaining position at a very low ebb.

The Lixus license, which has been given them on a plate is a completely different animal altogether and the market is in my view unwilling to look close enough at it to appreciate the strength of its viability and thus value it more realistically.

I wouldn't wish to go too far into what can be achieved here but to place it all in context I will say this ;

No further drilling at Anchois 1 and the existing gas discovery can deliver a phase 1 70mmscf/d for over 10 years.

1 further successful appraisal well drill at Anchois 1 to open up Gas Sands C and the that becomes 90mmscf/d for over 10 years.

I further exploration well at Anchois N with an independently assessed COS of 43% and the play becomes 90mmscf/d for over 22 years.

That play sits within a jurisdiction where there is a 10 year corporate tax holiday, with low royalties at just 5%. Furthermore, the Moroccan gas market will offer prices in the region of $8.50 per mcf at $70 brent. Even at $60 brent we are talking $7.50 per mcf for something that's likely going to cost well under $2 per mcf to get to market, plus with the GME pipeline siting just 30km in land from Lixus landfall, there is a direct link to the European market.

There will be the need for further drilling to expand the discoveries of course but what I am expressing here is the criteria on the table when CHAR sit down and talk with potential partners. Will there be significant interest at those levels and with that gas market so near, and for me the answer is unequivocally yes.

With around £13.5m in the bank all of what I have just described is currently being priced at under £3m. What it should be priced at is for the individual to decide. It is not my call nor would I want it to be. DYOR always

But in my opinion even with a question mark over BOD performance, the still opportunity far outweighs that risk at these levels. The only outstanding detail for me which I have tried to eliminate is the CAPEX
12 Jun '19

As a clear example of what I am talking about, I have found clear evidence that flowline pipes can be laid at approximately $37,500 per in/km. For a 14 inch diameter pipe that equates to $525,000 per km. At 40km the flow line element of the construction should on that basis therefore come in at around $21m.

Given I have just allowed $70m for the total construction, that leaves $50m for 4 subsea trees, a manifold and the associated equipment, which looks a little top heavy but let's see.
12 Jun '19

PS I could make a strong argument for being 10-120% over because the figures I have used are deliberately conservative because I would clearly rather be over and horribly under.

Lets see what comes out when the FS is released shortly.
12 Jun '19

Apologies I left out the appraisal drill, which i had in at $14m (see previous comparison with RBD-1 costs).

So my total phase 1 cost estimate is currently running at circa at around $360m.

If its anywhere close to that figure then I will very pleased for a variety of different reasons.
12 Jun '19

Further to my ongoing costing analysis, here is a relevant example of costs in the industry today.

In Oct 2018 CNOOC purchased the following subsea system (equipment only) from Aker Solutions for $205m.

"The subsea production system for the Lingshui 17-2 field consists of 11 horizontal subsea trees, four manifolds, topside and subsea control system and a vertical tie-in connection system.

The work scope also includes more than 70 kilometers of static and dynamic umbilicals, linking the subsea development to a new, semisubmersible platform."


According to the latest June presentation from CHAR, which contains extracts from ongoing FS, the phase 1 development of Anchois requires ;

"2 - 4 subsea producer wells connected via a 6 slot manifold (additional slots for future wells)

40 km 14” subsea flow line with control umbilical" (See slide 8 below)

The rest is onshore and includes "Onshore Processing Facility" and "Export via 14” onshore pipeline," which could be as little as 30km if they decide to go down the SOU route and connect straight into the GME pipeline.

Other than 1 appraisal drill that's it for a phase 1 and a 90mmscf/d gas supply.

If we take the numbers from the case study that I posted back in April then we see that back in 2007 each subsea tree cost $4.5m and each manifold $5.7m with associated equipment for the manifold coming in at a further $9m.

Even if we ignore the associated manifold equipment we are talking 7 x $4.5m and 3 x $5.7m just on the trees and manifolds. That's $48.5m at 2007 prices, which is $60m in today's money.

Whilst umbilical and flow line costs are never like for like as it depends on diameter and product etc, a broad comparison can still be created by removing the 30km. using the 2007 study value of $1.5m per km would create a further $45m saving, although I have read various papers now that state flow lines are considerably cheaper. Still on that basis we are talking about a comparable cost for the off shore equipment of circa $110m.

According to the 2007 case study construction costs were circa 40% of the total costs, giving is an offshore all in cost of circa $180m.

The SOU gas plant and 120km on shore pipeline is costing $184m. Fro what I have been able to find out there is likely a round $15-20m in savings on that cost due to the shorter (30km) pipeline.

So we are talking circa $165m for all on shore activities and a total project estimate of $345m of which 25% is ONYM costs.

Its not 100% accurate but its not designed to be. It is designed to answer any concerns I my have for the capex. At a figure around about that level, supplying equiv 16,000 bopd, the project is going to get a lot of interest.

12 Jun '19

@Badger2017 In my opinion they already have forged a strong relationship with the Moroccan government as evidenced by the fact they were handed Lixus on a plate. This is a company that has no history of bringing fields into production and yet they were handed a viable 70m barrel of oil equivalent gas discovery, by a country desperate to create its own energy supplies.

That to me shouts strong relationship already.

I believe this is now about costs to develop, which I expect to be well within reach compared to the anticipated revenues, and asset investment interest, which I expect to be sizeable given said partner would be contributing towards an appraisal well and development costs, which are low risk.
11 Jun '19

“The reason that traders were willing to stockpile is not only because they realized that the current price had been at a comparatively low level but also because they are expecting the price to rise amid possibly growing demand stemming from an anticipated check on the implementation of the new rebar policy,” a Chinese market source said.

There's the understatement of the year.

What doesn't quite add up here is the article also states ;

"Many Chinese traders entered the market for restocking ferro-vanadium and vanadium nitrogen in anticipation of continued price increases in the coming weeks amid market chatter that China would implement checks on rebar quality in the near future."

Am I to believe that Chinese traders in vanadium don't have a good handle on the authority's approach to Chinese regulations, new licenses, and inspections, as described by BMO in their market update.

That aside, this is yet more evidence that prices are going to rise one way or the other.

11 Jun '19

PS I am under no illusions that the market clearly isn't prepared to see this opportunity at the moment. The interest here is so slight that one could argue that posting is a waste of one's time.

However, that has never put me off before and won't do now either. From what I have seen this is a really solid opportunity with far less risk than the market would care to currently assign. In my opinion.

As always time will tell but I very much like what I see.
11 Jun '19

Appreciated and indeed I agree.

If CHAR were hunting partners on even an 'exciting' exploration prospect then I wouldn't be here but they aren't. On an exploration prospect and 75% ownership they would have to give the majority of it away just to get a drill done. Previous history is a case in point on that front.

Lixus is a completely different animal. Exploration is done. It is a limited appraisal programme of 1 drill that is designed to deliver a phase 1 90mmscf/d development for over 10 years 40 km from a very lucrative gas market.

That is highly desirable and will in my opinion signal multiple interested parties because it will be a very profitable project that has the ability to expand through just 1 additional exploration drill and further phase 1 paid for capex.

I still agree that juniors such as CHAR have more to lose than to win these days but one must be careful to paint them all with the same brush. With this particular play and that anticipated competition, CHAR should get a very good deal, which is simply not even close to being reflected in the current circa £4m valuation assigned to Lixus.
11 Jun '19

Yes but perhaps they do have a plan but have yet to reveal what it is.

AMER have stated previously that OXY bought into their blocks because of the OBA. That means they didn't come looking for minimum volume of 9,000 bopd, they came after the 50-70,000 bopd design capacity that has been repeated in the AGM presentation from 14th May 2019 (see slide 13).

Slide 13 is rather telling in that it also shows that the OCP at 450,000 bopd is currently 65% under utilised and is part of the solution that allows oil to be transported at $5 per/bbl from OBA.

So the "bottleneck" lies solely with the RODA pipeline and the stated 20-40,000 b/d additional capacity with debottlenecking for which the slide repeats the message that can be found in the Annual Reports each year that the company has "Projects Identified to increase RODA capacity"

At top end that gives AMER and its partner OXY volume of nearly 50,000 bopd.

I have no doubt that how this will be achieved has all been discussed at length between the parties and that AMER had no chance of either affording it or even convincing the locals to allow it, prior to OXY coming on board.

That revelation brings a whole new meaning to the 3rd party oil agreement, which is about the authority to transport oil not how much they actually pump in 2019. It also strongly supports OXY belief in the prospectivity of those Putamayo blocks and compounds the likelihood of OXY taking out AMER once the success starts to show itself.

That why I am happy to ride this out until the end of 2020 and then review progress at that point. In the meantime I would like to see solid progress on the other blocks and in particular CP0-5 in order to give AMER stronger cash flows to protect its bargaining position across the board and allow it to partake in all the growth that is no doubt coming on its active blocks.

11 Jun '19

The other thing to consider is a vanadium producer involved in this 3 way tie up and there aren't a great many Bushveld Minerals around with which to agree such a product right now.

The vast majority of vanadium is produced as a secondary product with limited control over supply and price.

The other 2 pure play producers aren't even thinking batteries and direct relationships with those that produce them. Everybody else is trying to get a spade in the ground. Yes AVL are interested in pursuing this route but without an active mine they aren't going to get very far very fast.

The only other similar play out there right now is that of VRB Energy and Pangang V&T, which involves of course the often revered Robert Friedland. So that makes 2 world and the other is China based working with a secondary producer of vanadium and thus far does not have a publicly declared electrolyte leasing product.

So if you want to talk vanadium (leasing products) perhaps you really do need to come the Bushveld.

There is no chance the wider market can truly appreciate the significance of this update yet. However, Vanadium and VRFBs are no longer some dirty secret and the likes of BMN and what they are attempting to do, is far more known today than perhaps is currently perceived.

So the enormity of this cannot go unnoticed for very long but even if it does the contracts will soon start showing themselves and then it will be an avalanche.

as the BE reports have repeatedly stated backed up by the latest Annual Report, which states under BE "Strategic Objectives" (see page 8).

"Grow its VRFB project pipeline across Africa"

In my opinion that pipeline has been awaiting this leasing product, which will now be fully implemented in line with the growth of the business into an electrolyte supplier and VRFB project developer. It won't happen tomorrow but that is not what is important, it is the fact it is going to happen and how big a deal it will be when it does.
11 Jun '19

@kevkan et al.

The way I understand it and why I am so excited about this leasing model is that it is not solely about the tie up with Avalon Battery but about successfully pulling together what is said to be a very complicated process and getting it over the line.

The RNS is very clear when it says ;

"The complexity stemmed from developing financial and non-financial terms acceptable to three different parties - a vanadium producer, a battery company and an electricity customer. The structures and documentation created from this project are available to both Bushveld Energy and Avalon Battery to use in future projects, making it easier and faster to execute vanadium electrolyte rentals in the future."

That is the key message here. The product has reached a stage where by all 3 parties and their no doubt extensive legal teams, were able to agree a means by which the product could go live.

The VRFB manufacturing sector is fragmented and currently short of viable projects. Without wishing to sound too dramatic, this product is the answer they have been looking for, which will enable them to compete with lithium in the various tenders they are no doubt taking part in but aren't currently winning. Yes each company will have its own legal team and will wish to pour over the details but there is now a template that has done all the hard work and so should far more readily get over the line.

As the RNS goes on to say ;

"The majority of the challenges in implementing the product commercially were not financial but legal, including title ownership and risk allocation. Considering the uniqueness of the product, it was also critical to draft a legal agreement that current and future customers would be amenable to."

Given how necessary this product is to make VRFBs competitive enough to increase their tender win counts, it is not about UET being "aggrieved" but more about when and how will they and the rest of the VRFB manufacturing sector also becomes involved with this product because without it they are likely going nowhere.

As the Avalon Battery blog states ;

"One of the biggest hesitations our customers have about adding batteries to new or existing solar arrays is that they don’t understand their value, and they are legitimately concerned about the technology and commercial risk from what can be a significant up-front investment. "

"By deferring a large portion of the battery cost we not only help our customers afford storage, it also gives them comfort that the battery is going to work, as expected, over its design life.”

By expanding the ability for VRFBs to win significantly more work, what this product will do is get more and more live examples on the ground, which in turn will improve that customer understanding, and further expand the various avenues for more business across the board.

It is a true watershed moment that will have VRFB companies hammering at the BE door.
11 Jun '19

II think what is important to remember is that AMER reported the Indico-1 discovery on 10th Dec due to "press speculation," which I was not able to find at the time.

Reports from India state that Indico-1 was drilled between 7th Nov and 15th Dec. However, ONGC Videsh did not release their official statement until 5th Jan. Yes we had Christmas (Does that affect ONGC overseas arm) but still the 'delay' was palpable.

Of course given ONGC Videsh size, they are not the sort of operation that needs to update the market the moment they strike oil. They operate in 40 countries after all.

It may be that AMER will follow the same route as before, finding good reason to announce the results well before ONGC. Or they could have had their hand slapped for jumping the gun and will instead follow the lead of the operator this time around.

Furthermore, if Sol-1 isn't a duster and it is instead a very solid oil discovery then surely AMER would be wise keeping this separated from a general operations update, so that it can have the impact it deserves. They area BOD on the back foot and have already demonstrated a desire to prove to the market their worth by exploiting the good news as far as they are able.

Who knows? What all of that says is there is at least enough doubt out there to allow one to keep an open mind about Sol-1 be it a cautious one at that.
11 Jun '19

Morning everyone,

One thought I had about this particular update was the timing that it took to achieve ANH approval on the OXY deal and what that could potentially mean for Put 8. The deal was signed off on 23rd Nov so the change of ownership took circa 6 months.

The Put 8 buyout was announced on 20th March, which would give us a rough estimate of end of Sept for the approvals. Of course AMER is also looking for approval to drill within the block also, which may complicate things further but at the very least there is a workable target there for commencement and achieving the first drill towards the end of this year.

The 14th May presentation (slide 12) highlights very well just how close Bienparado is to the OBA pipeline and infrastructure and I remain convinced that this will be the first drill location, whatever the company says about first come first served on the approvals from ANH.

I have read talk of an expectation that Put 8 will be farmed out but if we are indeed seeking greater ambition from the BOD then surely with Platanillo ageing Put 8 is a ready made replacement field. AMER are clearly demonstrating that cash flow isn't a problem particularly with the Indico-2 drill to come, which I am sure we all have great expectation for. Therefore, it makes sense to push on with production through maintaining full ownership of Put 8, which for me is an exciting field at 100% ownership and the OBA right on its doorstep.

Other than that the RNS was very solid. Given the general sentiment demonstrated on this BB I do think they need to maintain this level of success for at least the remainder of the year before investors perhaps start to trust their intentions and achievements more. Whatever happens in the remainder of this year I have no doubt that 2020 is going to be much busier around here as Put 8, OXY and CP0-5 really kick in.
10 Jun '19

In my view it is misguided to continually compare the actions of the past (wildcat drills in deep water) with the potential actions of the future (significant gas discovery in shallow waters with substantial appraisal driven upside) when the two situations could not be more different.

Furthermore, it is inevitable that this company will have to fund raise in order to get into production, even if they sell off a sizeable portion of the Lixus license. That is thr stage they are at so with all due respect it is stating the obvious.

The key here is defining the probabilities. I have over the last few months attempted to de-construct the Lixus opportunity. What is clear is that 1 further appraisal well delivers Phase 1 90mmmscf/d in full. 1 further exploration well on a drill with 43% COS delivers phase 2 in full. So from that perspective the risk is minimal and the rewards high, thus the bargaining position a very strong one. To automatically disregard that position due to past deals being perceived (perhaps quite rightly) as poor, even though they never had anything like the same economics and risk profiles, for me makes no sense at all.

That aside, I have been further reviewing the costs of the phase 1 development and the headline figure I employed of circa $350m. I doing so I came across the enclosed document, which includes information on the standardisation of subsea components. What it points to is the fact that a good many components have seen their costs reduce by 50% in the last few years alone (article is dated 2017). My case study was from 2007 and I had included a 15% reduction in overall costs due to cost savings. The view point however in this article points towards costs being even lower such that the off shore element of the costs could even now be below $300m.

Given that ONYM are responsible for their own costs at development level, which is what we are talking about here, then CHAR could be selling a share of circa $225m in total costs (drills included) to enjoy a 22 year continuous supply of gas to the very profitable Moroccan market with the knowledge that the revenues could then go on to pay for a more extensive exploration programme that could more than double that gas supply.

On Namibia CHAR couldn't sell that cost because it wasn't realistic, nor could they claim that their government partner would pay their costs because they were negotiating exploration drills, which even on RSD-1 off Morocco would have meant being covered by any incoming partner.

It is these differences that should be studied and measured against as opposed to simply taking any previous situation and assuming it will always apply.

The $300m figure does not include the CPF at landfall because I think they will loom to outsource this just like SOU have. But lets see. FS study is imminent.

10 Jun '19

Afternoon everyone, haven't posted here for a while. Still very much committed to my end of 2020 plan. Whilst i had hoped for stronger drilling by this point in time, I am not as disappointed with the progress here as many are. For me 2020 will constitute the true measure of the potential here as ONGC and OXY kick on with their drilling commitments and Put 8 really coems into its own. in the meantime there is certainly room for some front end growth in the valuation, particularly if Sol delivers a good result. Another 3,000 plus bopd well would mean 3 on shore wells each delivering substantial flow and all far in excess of any individual well at Llanos 34.

Then of course there is Indico 2 and 3 to come, which will test the depth of the Indico structure and for me, add significant further reserves at CP0-5.

I have read much here regarding the possibility of a takeover. nobody really knows what will happen but I cannot see ONGC keeping AMER on board at CP0-5 forever. Technical and local expertise aside, they are for me too big to want to carry such a junior partner. Strong further success on that license in my opinion will lead to an offer there at the very least.

With regards to Sol-1, according to the ONGC tender documentation for the 3 drill programme that started with Indico-1, the drill and test phases are anticipated as follows ;

Indico 1 - 39 days
Sol and Aguila - Each 32 days

(see page 70 of the enclosed document).

There are various reports that discuss the timelines for the Indico drill. This one here states 7th November for the spud and 15th dec for the completion. AMER have it closer to the start of Nov and reported on 10th Dec. Either way the total number of days is near as damn it 39 days.

Sol-1 isn't Indico but the estmiate thus far has been correct, which would point towards an announcement from Wednesday this week


10 Jun '19

Thank you pb940 as always.

2 points of significant interest in that SP Angel Update.

1. It is interesting that the BMN house broker feels able to point out that "we expect ESKOM to discover further grid-scale applications for VFRB batteries as the trial progresses."

I have been a key driver of the message regarding the significance Eskom BESS Project but SP Angel are correct, the battery is being tested at Rosherville in order to establish its potential to fit into the Eskom business and operational models as a whole, it is not there purely to establish whether it is suitable for the BESS project alone. The BESS Project as big as it is is a pilot programme only.

There is absolutely nothing stopping Eskom procuring further battery supplies outside of this programme for completely different uses or even seeking solutions for export to other SADC countries. After all Eskom is an importer of energy and an exporter of technology for the transmission and distribution of power, so it already has a significant foothold in the SADC.

2. This is the very first time that a broker has commenced to measure a value for what Bushveld Energy means to the overall BMN business. It is a watershed moment that will trigger further and for me speedy upgrades as the rest of the platform comes together and the contracts are announced to go with it. Big big moment in the short life of Bushveld Energy.

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