Member Info for ZENGAS

Didn't lose as much as you think because i can spot BS companies like BS posters.

Regardless good luck here and i hope you do well.

TYB how about boring versus BS. You spout as much as the company has done this past 15 years.

Lastweek you said you were holding 1.55m shares so that makes you severely underwater, not to mention talking total bs and not being your entry point of 0.35p as you now refer to.

24/8/20 14:08 .525p I am holding 1.5m shares at 0.68 average

17/9/20 10:52 .425p I have added to my pot holding 1.8m shares which is very large for me

27/10/20 15:58 0.45p Madpump no i got In from 0-5-06.5 averaging around 0.59 so not bothered in the slightest.

20/10/20 10:33 Once the stock opens up with a tilapia update along with a Tunisia one, you’ll see why I am in at my entry of 0.5p.

28/10/20 0.40 Rocklawn will make those buying at 0.5p (me) rich lol.

29/10/20 0.40 Morning guys, I am still here :). will open at 1p+ which will be 100% up on my investment.

11/11/20 0.35 I topped up several time yesterday under 0.35p and truly believe that was the absolute bottom.

29/12/20 1.05p Like I said those who were down should have averaged down heavily at 0.35p

20/12/21 1.125 I will add to my holding today. Gla

16/2/21 12.28 Will be adding more here while it’s quiet and holding a nice share price.

**** 18/8/21 17:20 1p. I got in at 0.35p **** and since then AC has done nothing but deliver.

17/8/21 16:15 1.175p Added 187k shares myself. Easy money good top up opportunity.

29/10/21 11:04 1.2p Can’t believe this hasn’t gone up to 1.5, another cheeky top up for me.

28/1/22 14:39 .825 The morning buys were all me. I will top up further into close too.

8 Jul 2022 13:15 .725 Mls I just topped up 65600 shares also. I believe we have hit bottom.

On 17/10/23 1.55m shares with an average of 0.35p ???? - pull the other one on price. It's no wonder you're desperate when anyone tells it like it is.

Attacking a poster is all you can come up with TYB.

FYI i didn't lose loads of money on the back of Azerbaijan so please for once in your life grow up and stop posting that hogwash everytime i or someone else has a different opinion to yourself in trying to justify yourself.

I still fully expect further dilution regardless of what anyone says and this is the 3rd major consolidation. The price was 4.25 when i posted in August and now 3.125p with stock to be issued for part of the US deals. The onus on Zenith was to get the share price higher and reduce the dilution.

As for listing in Canada (they left), Oslo, UK, 'some dutch exchange' ? (Paul1deanos comment) and now the US - fairly incredible when you think about it.

The main market listing here is actually poorer than on AIM because at least there they'd have a nomad.

The FCA reforms are indicating that from next year they may well need a sponsor to comply with the regulations which in turn will be more expensive and at the same time tighten reporting which the sponsor will have to stand over. If a sponsor doesn't take on the role, companies in this position may have to leave the exchange whether you know this or not or even dismiss its relevance. But at least they've got set up in the US so should be business as usual.

Of course winning up to $48m (on the no win no fee basis - how much will that cost ?) would be great if it wasn't for the debt to contend with.

Pitiful to see the share price down to 3.125p compared to 4.25p when i posted in August re dilution potential on the US deals. Obviously the cheaper the share price the more equity and value Stateside would get. Would it not be beneficial for someone to short or just plainly sell low volume stock driving down the price in order for more equity to be issued ?

So as regards the US deals, do they still plan a 60/40 cash/equity deal for the 2nd acquisition there ?

The recipient was to be locked in for a maximum 3 months.

From my post then - " If they don't get good news out and get the share price up prior to closure, then at the current price of £0.00425 it could mean that 76m shares will be issued for the 40% equity element.'

And on the first deal - "on the 1st deal they are considering issuing equity as bonus payment to Stateside for reaching 75 bopd (then at 50 bopd intervals). It's not clear how much it will cost to get to those intervals and as yet it's hard to work out how much additional equity could be issued'.

AEW2023 Underscores Evolving Role Independents Plays in Africa’s Exploration and Production (E&P) Space Independent oil and gas companies are taking on a more proactive role in Africa

Integrating innovation with technology and expertise, independents are leading the next wave of successful oil and gas projects. However, attracting these companies to the market comes with its own challenges. In the current energy transition climate, independents are being increasingly selective with their investments.

Tim O’Hanlon, Senior Advisor at Panoro Energy, acknowledged that, "The industry has adapted and exploration is still going on," however he believes that, "It will be a tough enough gig from here on out, because of the general uncertainty associated with the industry."

As such, fiscal reform has become necessary for attracting independents to markets. O’Hanlon expanded on this topic, stating that, "You need to knock their socks off in terms of attractive fiscal terms."

Echoing these remarks, Ian Cloke, COO of Afentra, stated that, "The race for capital is on, and it’s a global race. Capital will go where it is easiest, so you need to make sure you’re the most attractive one."

"Governments are facing the challenge of deciding whether to adjust fiscal terms, being able to utilize natural resources and beneficiate them for other industries, or leave them in the ground and rely on imports. Ultimately, the prize for government is developing fields rather than leaving them in the ground. So, making terms attractive and allowing fields to be developed in an appropriate timeframe is important."

Rather than focus on frontier opportunities, both Panoro Energy and Afentra prioritize mature assets, with a business structure centered on maintaining production at producing fields. O’Hanlon explained that, "We don’t do frontier. We develop discoveries that were made years ago." This creates significant opportunities for African countries, ensuring IOC divestment does not translate to rapid declines in output.

Similarly, Cloke explained that, "Afentra was set up for mature assets. We see a long journey from a transition perspective in Africa and we see these big assets producing for a number of years."

The panel concluded that through appropriate fiscal reforms, African countries comprising both frontier and established markets will be able to attract independents, leveraging their expertise to unlock new opportunities for energy security.

https://www.marketscreener.com/quote/stock/INVICTUS-ENERGY-LIMITED-105515477/news/AEW2023-Underscores-Evolving-Role-Independents-Plays-in-Africa-s-Exploration-and-Production-E-P-45102941/

AET should mirror Panoros growth

Panoro 3 year history on production, revenue, reserves, net debt, dividends and m/cap

2020 Production = 2200 bopd.

Revenue $26.9m. Cash $5.7m. Debt $21.3m.

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9th Feb 2021 Eq Guinea & Gabon acquisitions of 6900 bopd + 25 mmbo 2P for $140m .

Financed with $70m placing and debt of $90m from Trafigura.

113m shares in issue 21 NOK at this date = N2.37 billion = £174m m/cap.

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RNS 23/2/22 = Year end 2021 Production 7495 bopd. Total 35.8 mmbo 2, Revenue $119.7m. Net debt $72m .

RNS 30/11/22 = "USD 20 million core dividend paid on a quarterly basis in cash weighted towards H2 and subject to average oil price realisation remaining above USD 80 per barrel after the effects of any hedging.

Target distribution for 2023 of USD 30 million subject to higher oil price realisation of USD 90 per barrel being achieved for the year after the effects of any hedging"

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2023 Production

Q1 = 6,320 bopd

H1 2023 results = Revenue $66m. 'Net debt' at 30/6/23 = $50.4m

Working interest production averaged 7,220 bopd in the first half (H1 2022: 7,860 bopd).

71m NOK paid out in Dividends to end H1 = $6.7m paid out so far for H1

$6.7m paid out so far for H1.

117m shares in issue NOK 30 = N3.5 Billion = £260m m/cap against a an average broker target price of $4.18 or £390m m/cap

https://www.marketscreener.com/quote/stock/PANORO-ENERGY-ASA-6278756/consensus/

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AET = same 2P, approx 6,600 bopd. A $10m future dividend = 3.5p or 12.5% at the current s/p or 3.3% yield at a £1 target price = £220.5m m/cap or 15% discount to Panoro. Should track Panoros rising production via 3/05 peak target programme and 3/05A commercial start up - not to mention any further acquisitions.

RR

The Reuters article refers to the black market rate when dollars are in short supply.

Aboki FX is the black market rate.

Aboki FX Lagos parallel market rates https://abokifx.com/home

Below is the official rate and has been in a steady band since being allowed to free float by the Central bank. I'm not expecting any hit on SAVE in this second half. Since it was devalued in June - it 's been steady ever since in a tight band at the 775 level . That's the official bank level - the other is the unofficial black market rate. I seriously doubt if the Central Bank would devalue it again.

Dollar-Naira charts

1 year - https://www.xe.com/currencycharts/?from=USD&to=NGN

last month to date - https://www.xe.com/currencycharts/?from=USD&to=NGN&view=1M

In the 20th Sept presentation the August figures for Afentras interest were at 6,600 bopd

Block 3/05 = 21,000 bopd x 30% = 6,300 bopd.

Block 3/05A 1,450 bopd x 21.33% = 309 bopd.

It will be interesting to see where they are now almost 2 months later given injection rates and continued activity.

3/05 has gone from 17,200 bopd in Q1 to 19,000 bopd in April to 21,000 bopd in August this year. If 3/05 rises by another 1,500 bopd they could soon be through 7,000 bopd.

Ultimately over the next 3-4 years 3/05 alone has the potential to reach 35,000 bopd peak.

Thanks RR. Nothing much that I could add and just waiting out the timeline of the next 8 weeks. Hopefully news before then.

The 8 gas contracts

https://www.savannah-energy.com/operations/nigeria-3/our-assets/

They sold 142 mmcf/d for all of 2022.

I don't know if they have spare capacity for new contracts because if those cornerstone customers take their 80% TOP as well as the others taking 80% of theirs, they could be running at 212 mmcf/d. They mightn't meet those contract requirements.

'Took a further 12 months to complete Exxon on 9/12/23' - should read 9/12/22

Bear in mind

On 2/6/21 we were suspended on the basis of a proposed acquisition and RTO of Exxons interest - There was NO SPA signed.

On 13/6/21 just over 6 months later we signed the SPA with Exxon - but also signed the SPA with Petronas for their interest re Chad.

2 weeks later the adm doc was issued for both SPAs and suspension was lifted -overall in 7 months on 31/12/21.

Took a further 12 months to complete Exxon on 9/12/23 and we discontinued with Petronas in Dec '22.

This time around we've signed the SPA with Petronas for S.Sudan on 12th Dec 2022 along with immediate suspension.

We had a general statement for the adm doc to be issued in H1, then it was moved to be by 30/9/23. This time however it's a mid December month guideline - why not Dec 30th ? It's on or by 15th Dec - so is this seen as the overall final date, both for completion & approval.

Even though we signed the SPA with Petronas in Dec 2022 - i would think it was under discussion long before that - so why i think Jan 2022 might be the effective date.

That leads me to think that when AK said they hoped to have another significant acquisition before the end of 2023 - it could be well progressed.

If S.Sudan concludes - suspension is lifted and there'd be no need for a further suspension unless its a very large acquisition in its own right.

If S.Sudan doesn't go through then they should come back to trading immediately.

Perhaps this could throw a further acquisition into dissaray or they wait and leave a period of trading before an announcement which could be weeks, months away or not happen.

I think the date of 15th December is possibly significant regardless of Christmas - it's mid month and eaxctly 12 months since the SPA was signed.

I think the Government perhaps has been looking at an alternative deal in August on the basis of pre-emption which must be done in a defined period ie getting more money from somewhere else and run the asset themself.

Problem is they want a 5 year payment holiday and they are genuinely broke. From what i know all their oil is pre sold up to 2027 so have no flexibility imo and why i think the touted amount sought from Caltech has been so much to make an alternative deal worthwhile. On the basis of their pre sold oil, i'm not sure if that was based on much higher production figures say pre 2019 and which has fallen way down to todays numbers. Such a deal would leave them in an even more precarious state ie totally dependent on oil revenues something the world financial aid partners are totally against.

FinnCap gave some costings on the renewables last year. (Page 4-5 July 22)

For the mix of solar & wind and 750 MW they had a 13p valuation which was unrisked until in development and up and running.

They estimated 75% would come from debt financing such as specialist infrastructure funds suggested by AK - the remaining 25% provided by SAVE.

For wind the cost was estimated at $0.7m MW. For solar $0.5m MW - an average of $600m GW on a 50-50 wind/solar basis ?.

SAVE were aiming for 1 GW in motion by this year end and 2 GW end of next.

It was to be mid -late next year before the up to 250 MW Niger will be sanctioned with 1st revenues in 2026. On the basis of the F/Cap estimates - that would mean a cost of around $175m of which SAVE would need to find around $44m of their own money but likely spread over 2 years.

Overall on the F/Cap estimate for the 2 GW to be in motion by the end of next year - the cost could be around $1.2 billion with $300m needed from Save although the first 1 GW up and running is likely to self finance a proportion of that with maybe $200-$250m needed to reach 2 GW ?.

Save is aiming for 2 GW by end of next year so it wouldn't surprise me to see projects for 4-5 GW by the end of the decade given the massive target market of an estimated 240 GW across Africa by 2030 from memory.

FinnCap are using about 13p for 750 MW for the mix of wind and solar last year net to SAVE.

That would suggest that a 50/50 mix of wind/solar could be about 17.3p per GW - so if they build out to 2 GW maybe over 34p and if long term there's something like 5 GW about 86p - if reasonably close this would indicate why AK sees it as once in a lifetime opportunity on top of the value from Accugas and the separate hydrocarbon acquisitions and Niger.

On project financing and an average cost of $600m per GW (50/50 Wind/Solar) - we'd need about $150m of our cash per GW.

Obviously a proportion of that becomes self financing when the earlier projects are up and running to help fund later projects.

The net debt profile on Nigeria should still be on track to be cleared in around 2 years (taking into account the added ownership of COTCo interest) - so you'd think should provide a significant level of freed up cash. Over the next 2 years id be disappointed if they haven't increased gas sales by another 25-50% or another $50-$100m sales.

If they can land that crucial and sizeable oil acquisition that can throw off $2-$300m FCF such as Petronas S.S which must be already significantly discounted since the effective deal date - this i would think will be able to build future cash reserves and cover our contribution to grow the renewables. Most of these divestments have a pay back time of 3-4 years from effective date and earlier at much higher oil prices and why i think they're crucial to the entire game plan.

Thanks scotpak, a very well thought out and reasoned post.

Please keep your views coming.

I will remain invested and Accugas must be kept sound with a 45p valuation on debt reduction or more with new contracts.

Gas contracts are increasing- should lead to increased revenues.

Also what happens post compression completion - possible new gas contracts signed pre or after that ?

Transaction costs gripes - yes agree and fair enough but given the prize of an asset(s) that were non recourse debt and capable of $200m+ FCF i'm not put out by these increased costs in trying to land them. Be different if we were doing it all from the original 3 contracts and revenues we had in place but we weren't. They end when the acquisitions end and heavier when your revenue base is lower - less so if we had 1-2 successfully under our belt ie higher income.

What's the REAL negatives/dissapointment here today ?

1) A large $56m hit for the currency devalution - pushing net debt up in the short term but to compensate we have to take into account the Cotco interest.

2) No real info on S.Sudan and relisting.

3) Both only added to the Chad issue all adding up to an outpouring of negative sentiment .

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I don't expect those costs to re - occur. Keep growing the Nigerian revenue on the space we have.

News on S.Sudan should be short term.

As Chad ICC nears - SAVE wait and see outcome - then if not in our favour surely the COTCo interest is not benefically core to us - though on the remaining 31% we own supposed to give us north of $25m/yr FCF on current throughput (but currently in dispute with the Chadians though not on their territory).

So sell the interest pro-rata and reduce the net debt in turn reducing the finance costs along with the principal ?.

DON'T refinance Nigeria - pay it down on the envisaged timeline and it's own growing revenues (Sell Cotco)?. Saves us $100m/yr what could be going to us as Shareholders or a future asset. In saying that we don't know what kind of additional contracts could be being considered with the spare pipeline capacity and buying in 3rd party gas, there could be $50m -$100m+ of new business potential so we're not party to future thoughts?.

If we land an acquisiton well and good - it should be able on it's own merit to entirely repay it's own associated debt. So again - i don't see the point in refinancing Nigeria unless there are fairly significant new gas opportunities on the horizon.

Reconsider/slow the renewables if an acquisition does not come through - or seek a separate listing for it down the road when the projects are ready to be sanctioned .

Niger oil - a lot of groundwork done so absolute worst case as said last week could offload for $100m region imo and knock the n/debt down further - doubt it, but it's there and think Niger situation will resolve. But if not, i'd want a producing acquisition at some point of 20-30k bopd to replace it and bought on it's own merits and debt.

From the SAVE website investment case at the start of 2021 we have through to 2037 - 'Contracted Cumulative Revenues' of around $4.3 billion based on the Take or Pay basis of the 3 customers which are Lafarge (Unicem), Ibom Pwr & Calabar.

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F/yr results in June - "At end 2022 we had over US$3.8bn of future contracted revenues with contracts having average weighted remaining life of 15 years" ie to Calabar, Akwa-Ibom and Unicem.

We are looking to refinance from the 5 year term (now down to about 2.5 remaining) but about $350m figure i think - its about 10% of the contracted revenues.

How much additional revenue (not long term fixed) is able to come through from the additional contracts beyond the 3 cornerstone ones ?

Mulak still too small but DCQ up to 2.5 mmcf/d variable but im not including this figure.

Post period end contracts (both renewed extensions & new)

CHGC up to 10 mmcf/d.

Notore up to 20 mmcf/d (though July -September 2023 ran at 26.3 mmcf/d).

FIPL - (Afam, Eleme & Trans Amadi pwr/stations) up to 65 mmcf/d.

Supplying 80% of the gas for those extended contracts = 68 mmcf/d and if you add that to the fixed contracts it just exceeds 200 mmcf/d on a TOP basis. Now not all of that gas isn't always taken, but invoiced and it has to be available but it's why i think we are at our limitations on contracts until the compression project is completed next year.

In addition -

SPDC also extended - i can't find the original mention or rns of this ?

New agreement with SHELLs SNG started August last month - size not stated.

We have a contract to buy in up to 20 mmcf/d from Amocon and i think we've been using 18 mmcf/d so given the area AMOCON is in - is this what we are supplying to the Shell contracts (SPDC & SNG) ???.

In real terms we are still reducing the net debt as said in my previous post (taking into account COTCo interest) but i'm getting to the stage of really just thinking it would be better paying off the existing finance debt asap in the original timeframe for Nigeria. (Perhaps this may have been considered in the projections from the oil acquistions and put on hold but Chad ran into problems barely 8 months ago).

Instead of financing costs and debt for Accugas/Nigeria -it would turn in to an immediate additional $100m+ net positive per year on top of growing revenues at a time of limited capex once the compression facilities are completed next year. That's cash that could pay down oil assets when combined with their cash generative power at $65/b+ or instead pay a very significant dividend.

ShoreCaps net debt profile was for end 2020 $408m, 2021 $370m, 2022 $404m, 2023 $257m.

"Net debt at the period end" (30/6/23) "admittedly increased to $443m compared to $405m at the end of last year although this appears to reflect in particular the unrealised foreign exchange losses associated wit the Naira devaluation."

It does fluctuate mid year somewhat positively or negatively over the course of the full year but this half year was a tougher one but hopefully and from i can see a short term hurdle.

The FX loss was $54m from the Naira devaluation - which is said to benefit SAVE post devaluation going forward. This has been accounted for in H1.

The payment of $44.9m from SNH in COTCo has been accounted for as recieved as i can see.

The net debt stands at $443m 30/6/23.

Full year end i think with the one of FX devaluation hit it should be below $400m based on the Nigerian/COTCo assets

We gained the Cameroon asset and the remainder of the COTCo interest pro-rata value imo should account for $135m.

Without that COTCo element we would be still on track for about $257m year end - perhaps in time sell it post resolution if no strategic importance without the Chad oil assets.

All in, I still believe we are on track to be net debt free in 24 months as the original envisaged timeline on Nigeria.

Accugas is performing very well and it's fortunate that they added those new gas contracts over the last 18 months and continue to do so.

There's costs that have been added for the acquisition strategy so if these aren't successful, those won't be re-occurring along with the increased head count which could be cut back imo.

On reflection and balance i'm fine with it but i do want to see a a significant acquisition completed to move us up a gear.

There’s a Panmure Gordon 8 page note out. I’m not a client and it’s not accessible on research tree.

RR I’d like to see a presentation and a view from the analysts as well going forward.

The refinancing delays had been put down to the naira dollar issue and now seen as no longer an impediment. So let’s see where they go on this and I’d like it elaborated on. Still need to take a detailed look but there’s costs that can be cut. We’ve been set back by 6 months on the net debt reduction and I’d like to see this back on track by year end so until we know what the position is on the next transaction I guess we’ll have to wait. A talk through presentation definitely needed for clarity imo.

Still going over the accounts from 7am. The one off devaluation of the Naira accounts for about a $54m hit.

While the going concern statement may look worrying. The notes to this are more upbeat further down on rescheduling term or the actual refinancing.

Staff costs have crept up and if the transactions for the acquisitions don’t go through, then they could take the decision to cut those back. A lot of savings could and can be made but we have to wait to see how S . Sudan or any other acquisition pans out this year.

There’s a fair amount of one off costs with the transactions which hadn’t given any ongoing benefit. At least one new net contract and increased gas amounts added in the last 6 weeks. Plenty of income and increasing so hopefully this will overcome last reporting period given we are virtually in Q4 now. If those acquisitions don’t materialise they could cut the bloat for them along with interest savings under a new refinancing agreement.