Member Info for ZENGAS

Transparency you joking ? It was on ADVFN first.

Can't see any of this in subsequent events inthe accounts released 28th June when they could have mentioned it (as they could have ATOG/Tunisia DD).
They previously RNSd that the mechanism for compensation was through a renegotiated reduced day rate.

Again the court order brought to light on AD V F N on friday by a poster but no one commented until proven it was factual.

If the rig is/was so dodgey what was the company doing that AAOG used to give it a full inspection/sign off.
AAOG continually mired in problems, staff leaving, rig disputes etc.

Also didn't they delay driling until they found the best rig when there was previously one in country.
If they have the money to pay this they should do so because others may be less willing to deal with them in terms of rig supply. Also if they do pay SMP does this now leave them with a drain/shortfall of $650k in their forward palns for drilling/capital raise.
Now involved in a legal case and if they pursue it and actally lose it where will that leave AAOG ?

I agree pawn that the delays are there re the Nigeria deal but it is no more dodgy that the rep of Congo which fares worse than Nigeria if you look at Transparency International.

The IMF has just agreed a bail out for R o Congo 2 days ago despite many reservations about it.
It's the PSC terms that's important otherwise the licence mightn't be worth as much whether its 20 or 25 years or not. The entire what I see fiasco over ATOG etc which came to light and was only dealt with by the company after it was blogged and commented on by those that spoke about it in depth.

pawn, unlike AAOG,
Savp have more than one asset and something in reserve. They're backed by blue chip investors and the world bank and have a decent experienced board.
It's ok DS saying they have a 25 year licence. No problem with that, but by his own admission they haven't the PSC terms worked out. So how can a licence be acceptable and say you have it when the terms aren't agreed.

You have to question it
Listen carefully to the interview re licence. A 25 year licence offered yes but the detail still being worked out by civil servants. Don't know enough what the new PSC terms are. Will they be as favourable or more costly as to who shares what? The detail does not even appear to be in the licence yet.

Also re the CPR - porosity etc - this is still a minefield. Much key data missing by their own admission as to production. Talking about production but doesn't know how much oil might be recoverable, is there or how long sustainable. By his own admission the Djeno is the only one that can be a company maker - especially looking at the original CPR estimates at IPO spread over approaching 400m shares now compared to just under 70m when they issued all shares etc for the field. If the Djeno is mediocre it's a stagnant company. If it doesn't live up to expectations on the next well, then it's lights out

At 8:40 in Sefton mistakes payment being received from ENI instead of SNPC - ENI being the partner on the Medco fields in Tunisia (aka ATOG) - is his head all over the place ?

https://www.youtube.com/watch?v=FzEqQJrz06I Watch and listen with care.

Oil and how much is what some are ultimately forgetting. OK saying the Djeno has oil but no new CPR could be put together.

After IPO and after all share issues etc for acquiring the Tilapia field, the shares in issue have increased from 69.5m to roughly 400m now post funding.

The onus now is to prove how much actual P2 there is ie whether it's less, in line or more than the the CPR at the time of listing and how that warrants any future valuation based on 400m shares when previously 69.5m on the P2.

Likewise they need to have sufficient P2 in the Djeno where they hope to produce 5k bopd - ie how long will it will produce for in terms of lifespan ? and again spread over the greater number of shares in issue for any proposed dividends.

The lowly price share price reflects the risk on how much P2, potential lifespan there might be and why a CPR now would have been helpful but why they haven't got enough info to back it up.

If for some reasons the debacles continue and they can't produce enough oil then a further funding would erode the company valuation further in terms of m/cap against reserves/production potential.

In that scenario I can see how a new asset being introduced if it is producing, would be best or not in AAOG with way too many shares in issue.

If however it is in ATOG it is completely free of being lumbered with too many shares in issue (compared to being in AAOG) as to delivering growth.

Imo that's not the point and as AAOG shareholder funds were used for the asset, then the asset should be secured for AAOG to help rebuild shareholder value here even if the resultant greater growth is less with it being in AAOG compared to ATOG.

Like I said previously on a d v fn - if you have two companies you have 2 salary and bonus packages where if it's just one company you have one salary/bonus package.

If a good producing asset can get off to the races in ATOG unhindered by too much existing dilution rather than in AAOG with 400m existing shares, that's where the bigger value is.

If AAOG were to balls up again at Tilapia it would drag down and hinder the potential of such an asset so I can see why it would be better in ATOG but to me it's all a huge conflict of interest and when the asset was pursued at cost to AAOG it should go to AAOG full stop.

AAOG could stagnate if these well results are more of the same or at worse the company could fail. But if a producing asset were added rather than being put in ATOG then it's survival would be better and it could continue on a growth pad with the new asset (of course not to its better potential unhindered in ATOG).

The revolving Orabank facility ($14.9m drawn call it $15m) is different from the undrawn $50m Oil trading group loan. $20m of this can be drawn in $5m tranches with $30m uncommitted.

On the expectation that the deal goes ahead it's worth considering what the bigger pictiure is given we are told it would be transformational for Savps growth.

1. There is 40 TCF of available gas that can be tied into the Accugas network. That's some 6.6 billion boe. Savp can either buy reserves or instead as majority owner of Accugas - negotiate supply to deliver to customers (same as they do from Savps Uquo field and eventually Stubb Creek gas).

2. Current gas pipeline capacity is around 66,000 boepd - room for over 100% growth and at higher margin.

3. Stubb Creek oil facility to be debottlenecked and give circa 5,000 bopd (from current circa 3k bopd gross).

4. Marginal fields, partnerships/farm-ins and acquistion potential for further oil reserves/production (as well as any gas).

5. Currently 134 mmboe 2P/2C + 50 mmbo estimated reserves in Niger = 184 mmboe.

6. Should be much repeatable drilling success in Niger from a mid case risked of 2.8 billion bls recoverable (given 100% success rate so far so not unrealistc that they could tote up 500 mmbls from Niger).

7. Niger EPS with initial 1,000 bopd rising to 5k. (Estimated to generate an extra $10m/yr free cassh flow per 1k bopd).

8. Gas business has had over $1b invested in infrastructure and facilities. With growing customers/supply, it could become a $2b value gross business over time - seperate from Savp that has the Nigeria reserves/field production etc and Niger.

9. With significant free cash generation of up to $150m/yr from current Nigeria ops or any new customers, should be in a position to buy/farm into thus adding more production/reserves and increasing cash generation.

10. Bottom line it's both an oil producer, gas producer and an integrated gas supply business with it's own facilities and infrastructure which will make up a combination of valuation elements.

From above opportunities -

500 mmbo alone could be worth around $2 billion Niger/Nigeria (using $4/barrel) .
Gas reserves could be worth $1b ?
Valuation of Accugas interest $1b ?

I beleive a $2 billion valuation is achievable for Savp and about 142p on 1b shares in issue.

Hurdle price is 42p for incentives so i would have thought 3-3.5x that for a decent pay off at least and comes to 147p on 3.5x.

Prior placings and averages again would need a similar return factor.

If you consider all the factors above post successful deal closure, the potential prize on offer is huge.

Paul 3 months away according to the article re CNPC/Benin .
FID October. Contractors picked by November. Benin is separate to any of the NNPC refinery plans.
As far as i'm aware that includes servicing debt. I also spoke to SAVP not too along ago about what happens to cash flow since deal inception and I was told this would benefit shareholders as it was reducing debt.
While I mentioned reserves, 2C, production and cash flow we also have to include the valuation for a totally separate gas business (ie not just based on reserves/2C or production alone) so somewhere in around $900m-$1b of deal value excluding Niger.

On deal completion they were meant to receive (sale/purchase agreement etc) some $70-$90m cash. (with ongoing free monthly cash flow of circa $9-10m/month). They also have that $50m loan facility. Impact of any potential Niger partner ? could introduce additional cash payment and on a 30%-50% farmout would reduce a gross $4m (Sokor Alt) - $6m-$10m well substantially.

The Nigeria free cash flow for this year was estimated at $115.3m (DCQ) or $103.7m (TOP).
For 2020 it was estimated at $153.5m (DCQ) or $120m (TOP).
In the following 2 years this was forecast to rise to $172.6m (DCQ) or $138.3m (TOP).

From memory around $60-$70/b oil was forecast to contribute a further $10m per 1k bopd from Niger under the EPS/trucking before short pipeline build.

The Benin pipeline was also to be ready for first oil by January 2022 (2.5 years).
10k bopd of future Niger production could yield circa $100m/yr free cash flow.
1st year dividend earmarked for $12.5m of that cash flow so could rise in line with percentage increase in DCQ/TOP in subsequent years.

Nigeria 2P = 75 MMBOE + 59 MMBOE 2C = 134 mmboe.
Niger discoveries mentioned as 50 mmbo reserves.
Possibly so far 180 mmboe.

Further Nigeria upside in terms of acquisitions, plus existing exploration there and top side of 2.8 billion bls recoverable mid case in Niger.

1 July 2019
San Leon Energy plc ("San Leon" or the "Company") announces that Eroton (the operator of the OML 18 licence, onshore Nigeria) has received a 20-year licence renewal for OML 18. The licence now expires in 2039.
Oisin Fanning, Chief Executive Officer, commented:
"The OML 18 licence renewal is excellent news for San Leon's investment in Nigeria, securing Eroton's rights to develop the fields in OML 18 for another 20 years."

Idriss Deby pushes back
The June meeting in N'Djamena between CNPC's brand new chairman Qijun Hou and the Chadian head of state was no chance encounter. The frosty relations between the two needed attending to. According to internal CNPC documents, the Chinese company has scrapped the idea of taking its pipeline through Chad meaning the cash-strapped state, hard hit by the 2014 fall in oil prices, can no longer count on extra transit fee revenues. CNPC, which is also active in Chad via the Ronier and Mimosa fields that feed the Djermaya refinery and also provide crude oil for export does not want to be even more dependent on the country. Yet, only in September 2018, the former CNPC chairman, Wang Yilin had met with Deby in Beijing. Deby used the occasion to urge the Chinese firm to export its Nigerian crude oil through his country Given its rocky experience in Chad, where Deby had closed its refinery following a dispute with the government over petroleum product prices, and hit with hefty fines regarding the operation conditions of its fields, CNPC is unwilling to build the pipeline through the country. On paper, however, it is the most economical solution. CNPC costs the Chad option at an estimated $1.18 billion. If it had opted for the Chadian route, it would only need to build 700 km of pipeline to connect Agadem to the existing Doba line that leads on to Kribi Port on Cameroon's coast.

Wanting to call the shots
The CNPC's decision to dash the Chadian route is also based on another key factor: its dependence or independence, rather, from other oil firms. The section of pipeline that leaves from Doba has been operated by American major ExxonMobil since 2003. This would give the Chinese firm very little room for manoeuvre in its future trade negotiations. This route also runs through three countries - Niger, Chad and Cameroon - meaning more stakeholders involved and more potential for squabbles over how the pipeline is run.

The oil major China National Petroleum Corp (CNPC) plans to start exporting part of the crude oil produced on its Nigerian field Agadem by 2022. It seems to have discarded the option of building an export pipeline through Chad, much to President Idriss Deby displeasure, and would rather take it through Benin out to the coast.
Benin bound
As we revealed, representatives of the Nigerien and Benin governments held several meetings with CNPC in Paris to discuss the export pipeline project. Nigerien president Mahamadou Issoufou validated a project that uses the Benin option at a cabinet meeting in June even though this route is 1,000 km longer than the Chad pipeline. It is also far more expensive, ringing in at $2.25 billion according to the CNPC's internal calculations. The company has already set a schedule for the project. According to our sources, the final investment decision will be taken in October this year and the first contractors will be picked by November. The goal is to have the pipeline and the reception facilities at the Beninese port of Seme completed and ready to use by January 2022. The oil major aims to produce at least 90,000 bpd of crude oil for export. While most of this output will come from Agadem¸ there are identified reserves on Savannah Petroleum blocks R1, R2, R3 and R4, and Sonatrach Kufra as well as CNPC's other block Bilma.

There was a new $50m debt facility put in place barely 9 months ago with an oil trading company.
I would say this will start to be drawn to get us to first oil in Niger.

Re Niger Amdigh well test - doubt if they will engage a rig for that alone without other activity and perhaps new drilling. They say deliver "first oil in H2" and also "to recommence exploration drilling in H2".

The exploration drilling should add more reserves and this is totally separate from any development drilling.

If they are delivering/or going to deliver first oil + explo drilling then I can see the loan facility being used against production and/or reserves. Very latest from AEI is that CNPC see major oil through the new Benin pipeline in circa 3 years so an ideal time for a partner to also potentially enter (which Savp have mentioned).

Bottom line is imo Niger very much forgotten by PIs.

Yesterdays 3 trades of 707693, 457693 and 250,000 = 1.415m - the 457693 & 250,000 trade was the same combined amount to balance the first 707,693 trade so imo definitely a buyer and a seller.

Nigeria delay - likely perhaps ministerial as nominees for posts not submitted as early as hoped for and why imo Savp give 'continue to expect' completion guidelines which im sure they get from government/industry and beyond their control. I don't see it set in stone but take the view it will happen given world bank and other investors onboard.

S/P is more from PIs impatience/fear and thinking deadline is set in stone when it never has been and is an expected guideline only.

At the time of the last placing - "As announced in previous regulatory updates, the Company expects a cash inflow of US$90m upon completion of the Seven Energy Transaction."

They have a $50m facility from the oil trading group arranged just over 6 months ago. I believe they were going to lease/rent the EPS facility equipment. They've submitted the feasibility scheme to Niger government 2 months ago.

One thing they do have is 5 separate discovered fields in Niger and near term production. There have been other entrants into Niger since. CNPC/Government are favouring the Benin route. I've no doubt there will be interest in us and our fields there if not already.

Exploration wells are still low cost (circa under $4.5m) to drill the Sokor alternances to where most of the easy oil can be discovered so not one shot wonders or high cost wells - ie miss and the moneys all gone.

With up to 2.8 billion bls RISKED recoverable (about 4 billion bls unrisked) mid case, it's an opportunity that can't be ignored imo given the 100% success rate so far.

As regards empire building, i suppose it depends on how you look at or gauge their strategy. If it was to derisk - have 2 separate asset bases ie Niger and Nigeria and keep as much of the upside in Niger as possible and Nigeria would be a cash cow to fund Niger ? At the moment we still have all of Niger and around $10-$15 billion worth of oil at $4-$6/b for the risked figure to chase and a good chunk of it very low risk so imo if I can't get a 100p out of this for Niger alone i'll be surprised. Niger will kick off sooner or later. AK has a huge stake in this to deliver value and there's too many top end institutions involved in this not to recognise the huge value potential here from Niger alone.

Company and brokers I believe were using circa $6/b for Niger.

They have supposedly around 52 mmbls from the 5 discoveries and using $4-$6/b = maybe $200m-$300m/£150m/£225m value - so at 880m shares = 17-25p range. Near term production for cash flow.
With a 2.8 billion recoverable range there's still huge upside even with a partner.
10% success from that 2.8 billion bls is around £1-£1.50.

I know the deal is holding everything up but I definitely haven't lost sight of what's in Niger at very low exploration risk as evidenced to date. Even at this diluted level solely for Niger the upside is substantial and why I haven't thought about selling. I think many have forgotten about this as they focus on will it/won't it happen in Nigeria.
With the oil discoveries there, they have a $50m loan facility they might tap from the oil trading group.
If the Nigerian deal successfully closes I think they said it would bring in some $90m (nearly 6 months ago). I did ask one time what's happening to all the cash that's being generated by continuing operations the longer this goes on and if I recall I think I read it correctly that this was reducing the overall debt level that Accugas/Savp/IIMB were taking on and ultimately beneficial for shareholders.

Also regards elements of the deal causing delay, another factor is the Nigerian Electricity Regulator approval of the Creek Town - Calabar gas pipeline that was being bought. With that going through the regulator for approval, it in turn would have to be wrapped up and finalised before everything submitted for government approval. We as PIs can't pinpoint what is causing the delay. But if shorters, PIs others etc drip sell as the s/p goes lower exacerbating the decline over the Nigerian deal uncertainty while ignoring the 100% success rate and upside in Niger, there's not much anyone can do. If the company hasn't got all clearance yet they may be just waiting like the rest of us for sign off so can't say much other than before and i'm sure they know investors don't want to hear another expected time frame for completion... ??

The implementation agreement was signed on the 4th Feb. Then a series of pre agreed work streams were to be concluded from that point onwards.

Given there are a number of companies involved (look at Frontier and UERL plus the UERL minorities buy out alone) it takes all those individual actions to come through at that end in a timely fashion. There's 2 fields plus pipelines and gas plant and therefore only takes the delay in one strand while the majority of the deal may already be completed before up for ministerial approval.

New customers have been pursued and a new power station signed up as well as a new pricing structure to Calabar I believe plus additional pipeline construction/buy out. Stubb Creek (UERL) isn't crucial imo to the deal though it has significant 2C that will supply customers when the Uquo field depletes in the future. It has relatively small oil production but the Uquo gas field is important now as it supplies the customers and I suppose the main rationale/driver in buying the gas supply business as an overall package.

My understanding is Niger ops will restart asap. (board wont say what rationale they have for their plan). I feel cashflow from Nigeria would fund this in the short term before taking on any partner. That might be why they decided to delay on Niger. Maybe they feel that even with a delay that with the outstanding 100% success rate they want to capture as much of the easier earlier successes rather than introduce a partner too cheaply or early.

Luck Counts - you mean you're only doing your research now ?
He didn't join Savp - he formed it.

It's the team that he has assembed around him that counts. Is 5 out of 5 ie 100% drilling success in Niger not testament to that. Is that muppetry or winning 4 blocks in Niger ?

Is bringing onboard a high number of blue chip financial institutions also not testament to that and who themselves will have already done their research and dd in backing the company. He also convinced the IFC (World Bank) to become investors in Savp. There are more parties than just Savp to the deal and are not negotiated by just anyone.

If you've done your research you'd see who was used to negotiate in Niger.

Cove Energy was a 20+ bagger and founded by 2 resource investors (neither were oil or gas men) but they brought people in. Savp isn't Andrew Knott alone if you think that is the issue.

I seem to recall Peter Levine being a lawyer and not having any oil/gas experience but created and built a small oil company from scratch to a £1.4 billion takeover.

Likewise Henry Cameron a solictior building Sibir Eenergy oil company from zero to a £1.9 billion takeover.
If your going to be critical at least don't make an eejit of yourself in that thought process of one mans ability. Last time I heard, he doesn't interpret seismic or pick drilling locations either but then that's not his role.

While taking longer than expected, last time i looked the long awaited implemenation agreement had finally been signed to progress the deal towards final sanction.

Axxela says it does 80 mmcf/d.

Accugas supply 3x greater at circa 240 mmcf/d with more customers to tie in.

Axxela appears to be solely the gas supply/pipeline business and not gas reserves or fields which make up the Savp acquisition (ie Uquo, Stubb Creek reserves and production and sales to Accugas - plus Accugas gas business/supply/pipelines etc/sales to customers) .

Whatever the landscape it's a vote of confidence from Helios in Nigerian gas supply.

Worth drawing attention to those 7 critical CGDPs (of which Accugas are involved).

LAGOS, April 4 (Reuters) - Nigerian oil company Oando said on Thursday it had sold its 25 percent stake in local gas and power company Axxela to majority investor Helios Investment partners for $41.5 million as it works on cutting its debt.
Oando has in recent years transformed itself from a fuel retailer to an oil producer competing with multinationals such as Shell and Exxon Mobil, but its growth has been largely funded by debt.
It hived off its power and gas subsidiaries in 2015, selling a 75 percent stake in the new business, Axxela, to Helios for $115.8 million in 2016.
The Soros-backed private equity firm now owns 100 percent of Axxela following Oando’s divestment, Axxela said on Thursday.
Axxela said it delivers up to around 80 million standard cubic feet (scuf) per day to over 160 industrial and commercial customers.
https://uk.reuters.com/article/nigeria-oando-divestiture/update-1-oando-sells-25-pct-stake-in-nigerian-gas-company-to-private-equity-firm-helios-idUKL8N21M4RY
Axxela is a designated natural gas shipper on the West African Gas Pipeline and is also the pioneering private sector-led developer of natural gas distribution in Nigeria, delivering at peak 80 million standard cubic feet per day to over 160 industrial and commercial customers via a vast network of gas infrastructure.
With over 280km in gas pipeline infrastructure built, Axxela provides unique energy solutions primarily through its subsidiaries: Gaslink Nigeria, Gas Network Services, and Central Horizon Gas Company.
The acquisition by Helios was effected through HIP GLOVER S.à.r.l, a special purpose vehicle incorporated by Helios, which in 2016 had acquired the initial 75% interest in Axxela for $115.8m.
We will continue to maintain significant presence in the Midstream as well as grow our gas aspirations via our Upstream gas assets in our NAOC Joint Venture wherein we have four gas projects within the NNPC’s Seven Critical Gas Development Projects (CGDPs), which are responsible for almost 50% of the 42 TCF that will be delivered by the seven CGDPs by 2020.”
Bolaji Osunsanya, CEO of Axxela, added: “As we position to become the preferred and fast-growing gas and power portfolio across Sub-Saharan Africa, we pay homage to our origins, legacy, and storied history as an Oando portfolio company.
"As we commence a new journey, our audacious growth initiatives across Nigeria and the sub-region will leverage our industry expertise, experience, and longevity; while our affiliation as a full-fledged Helios company will improve our access to capital."
https://www.africaglobalfunds.com/news/private-equity/deals/helios-takes-25-interest-in-axxela/

CEO has 2.17m shares at last summers uk listing plus 3m options.

David Neuhauser is a director and holds 31.9m via Livermore.