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Although AC's diction is difficult to transcribe the following few extracts seem of note:

AC in reply to Q re 2P Reserves; “2P reserves currently 9 million [barrels oil] which with El Bibane, Ezzaouia and Robbana of at least 11m....totals 20m plus”
Stig “with 20m 2P the market capitalisation is very low”
AC “300-400NOK is more realistic” ie £26-35m.

AC “Tilapia deal will be automatically followed by second acquisition” This presumably relates to the 07.07.2020 RNS re a Joint Venture Agreement for acquisition of a second asset in Congo Brazzaville, and which I enlarged on in a 10.07.2020 post.

AC “another high producing acquisition in another West African country” mentioned as imminent and with reference to 4000-12,000 bopd. Context of conversation implied this is not Nigeria but more likely to be the “West African” country referred to in the 12.02.2020 RNS and which I suggested in a 18.06.2020 'answer to MG' would most likely be in Gabon, with Angola or Cameroon as possible alternatives.

Subdued response both here and Oslo I see.

CanaryITM thanks for the response, much appreciated. I do not have access to sufficient data on El Bibane, at present, to offer any meaningful assessment of the potential operation but from what the ETAP [Enterprise tunisienne d'activites petrolieres] geologists have revealed from their study of the Jeffara Basin, the El Bibane concession appear to be favourably located for further discoveries.

The configuration of the six wells at El Bibane suggests a field-size of maybe 20sq km ie only c10% of the total concession [228 sq km] and is in a region of the Jeffara Basin where there is a preponderance of hydrocarbon trap types, eg anticlines, fault-controlled, stratigraphic and salt-diapirs. Furthermore the main Zebbag dolomite reservoir is locally highly porous, which with high permeability accounts for the initial high production rates from some of the wells, eg EBB-4 at 1400 bopd and EBB-3 at 1790 bopd.

An indication of the possible potential of El Bibane is that Candax Energy paid $43.7m in 2005 to acquire 74% of El Bibane, plus 31% of Ezzaouia, 80% of Robbana, 75% of Al Manzah [non-operational], 80% of Chaal Permit [non-operational] & 50% of SEEB Power Facility, and in 2007 spent $25.4m mostly on upgrading the El Bibane infrastructure and drilling 3 wells. In 2012 Candax paid a further $4m for an additional 24% of El Bibane and 14% of Ezzaouia, so total outlay on El Bibane was maybe around $35m.

With regard to the timing of the $3.5m intervention at EBB-3, AC mentioned in today's Stig Myrseth interview that he anticipated expenditure of £300,000-£400,000 [if I heard correctly] on work-overs sufficient to achieve year end targets, so obviously excluding EBB-3. Fast-tracking EBB-3 would be unwise as the probability of success is maybe 60/40 at best and failure or partial success, perceived as a disaster by PI's at this stage in the companies development.

The April 30th 2021 RNS relating to the acquisition of El Bibane, as for the Robbana Field, emphasises the “undeveloped potential”, with contingent reserves [1C] evaluated Dec 31st 2019 as 25.7 MMSTBO remaining oil in place, and 6.5 BCF [billion cubic feet] of natural gas. As part of development a US$3.5m well intervention at well EBB-3, to restore production of 500+ bopd, is mentioned as under consideration, although I anticipate this may be of lower priority than land-based developments at Ezzaouia, Robbana and Sidi el Kilani, unless specific and favourable loan financing is forthcoming.

For those unfamiliar with the geography, the field is confined to the northern end of an offshore concession approximately 20 x 10 km in extent, extending from the coastal lagoon of Bibane, north-eastwards into the Gulf of Gabes and c30km from the Tunisian-Libyan maritime border. The 6 wells with service platforms, of which 3 wells are currently in use, are aligned SW-NE along the crest of a geological structural high, 16-18km from shore in 7-8m water depth. The field is 20km ESE of the landward Ezzaouia Field.

The main O & G reservoir is the Lower Cretaceous [Cenomanian], Lower Zebbag Formation of fractured dolomite interbedded with shales and evaporites, which latter probably forms a top seal to a 50m oil rim below a well defined gas cap. The dolomites have a porosity of around 15% and are accessed at approx 2150m depth. A second, unexploited reservoir occurs in the deeper Jurassic [Kimmerigian] clastics of the M'rabtine Formation with a potential 15m pay-zone of 10-19% porosity. Well EBB-1 tested at 800 BCPD [barrels condensate per day] and 15.7 MMCFGPD [million cubic feet gas per day] from the Zebbag.

Production from well EBB-5 is pumped via an 18km 8-inch pipeline [initially from EBB-3] to the MARETAP [joint ETAP/EPZ operating company] processing facility at Zarzis where the oil, gas and water are separated. Oil is then piped to the 200,000 barrel MARETAP Zarzis Storage & Offloading Facility [commissioned 2008] and co-mingled with oil from Ezzaouia and Robbana awaiting sale. Dry gas [currently 5.5-6 MMCFGPD from EBB-5] is returned under pressure for re-injection via EBB-4 into the reservoir formation to enhance condensate production. Historically dry gas was supplied under contract to the adjacent SEEB Power Facility [operational May 2003 to January 2010] which generated electricity for the Tunisian grid. After that facility ceased operations the gas re-injection scheme was developed and commissioned in May 2012. The April RNS statement that “It is expected that, by utilising new technologies, well EBB-4 may achieve commercial production of natural gas in addition to its current use as an injector well” implies the possibility of future sales of surplus dry gas. Since previous gas flows from EBB-5 stabilised at 8 MMCFGPD [ equating to 1328 barrels oil equivalent] the potential revenue from gas sales is significant.
AGEOS.

As was made clear in the April 30th RNS, “The key significance of the acquisition of ….Robbana is the undeveloped potential” defined as of December 31st, 2019, as “contingent reserves [1C] of remaining oil in place as 10.99 MMSTBO.” [million stock tank barrels], for which the suggested initial exploitation is “an infill well, to be drilled in the proximity of well ROB-1 [currently producing 25 bopd from the Mu1 reservoir by beam-pump] expected to produce approximately 200 bopd.”

These contingent reserves are assigned to the Lower Cretaceous [Valanginian-Berriasian] Upper Meloussi Formation Mu1[upper Meloussi reservoir] and Mu2 [lower Meloussi reservoir], both of clastic/dolomite lithology of 12-21% permeability. Further geological modelling indicates an additional 5.4 Mmbls [million barrels oil] from the deeper Middle Meloussi Formation, and 2 other locations for development wells possibly with side-tracks. Water and/or gas injection to enhance production may be part of that model. The Field occupies only 1.68 acres of the 11,856 acres Concession. As ROB-1 initially tested at 817 bopd, 84 mcfp/d gas and 26-70% water from 2103-2137m, and MZR-1 on the adjacent Mazrane Field tested 616 bopd, 30-48% water, at 3100psi reservoir pressure, from 2055-2075m, the 200 bopd for an infill at Robbana is conservative.

Fluids from Robbana are trucked to a production facility for the El Bibane Concession where they are separated and processed. The oil is then piped to the Zarzis Storage Facility where it is lifted and sold along with oil from the Ezzaouia and El Bibane Fields.

Robbana, with Ezzaouia and El Bibane, are the main fields within the geologically defined Jeffara Basin, which has been the focus of a petrophysical reservoir and petroleum prospectivity evaluation by ETAP geologists in recent years, so the ZEN acquisitions are very timely in being able to take advantage of the considerable data and interpretative value arising from that work.
AGEOS.

callit, I omitted too much detail as it will only assist in identifying the Field. However, in answer to your question I can add that there are 2 wells involved in the gas cycling process. One produces "wet gas" from which the condensate is extracted; the other receives pressurised "dry gas" which enhances the reservoir pressure to optimise "wet gas" flow. The total system will be balanced and controlled to ensure equilibbrium between the two variables of 'max condensate' and 'minimun dry gas'.

The “Potential Acquisitions” which are the subject of yesterday's RNS are readily identifiable to anyone familiar with the Tunisian O & G industry and from available information appear to have synergy's with ZEN's other acquisitions and potential for further development.

Disclosure of the Field identities would not be appropriate at this stage but it is possible to add that the “First” has previously been assessed as having potential for gas production and sale in addition to the 500-600 bopd production re-instatement. The unrisked prospective gas resources might also be amenable to ZEN's gas to power conversion technology. Longer term there is the potential for exploration of a deeper Triassic reservoir.

The “Second” Field was assessed pre-2020 as having the potential for several new wells and for side-tracks from the current production well. This has a beam pumping system and produces from a single horizon in a Cretaceous reservoir.
AGEOS

The concluding comment, below, from AC in today's RNS clearly implies ongoing negotiations regarding a possible further acquisition in Tunisia in addition to SLK and Ezzaouia.

“The Board is increasingly confident regarding Zenith Energy's establishment in Tunisia, where we are currently assessing certain additional oil production and development opportunities to further enrich our portfolio."

Whilst nothing not already released in RNS will be revealed in tomorrow's presentation and Q & A, it will be interesting to see if there are any hints as to the anticipated scale of operations in Tunisia. The most recent information I have on ENI's plans to 2030, and its current operations in the country, suggests there are far more opportunities for significant production and developmental acquisitions available to ZEN than I was previously aware of, and as indicated in my 09.03.2021 post. Tomorrow's update will hopefully elucidate further.
AGEOS.

Continuation:

Whatever the proposed “production optimisation and workover activities” entail, it seems likely that AC will have agreed to an immediate “cash call” from MARETAP as part of the Ezzaouia Field acquisition deal, both to assure ETAP of his financial commitment and to ensure as rapid a progression to the 1000 bopd target as possible. Hopefully the forthcoming presentation and associated company announcements will confirm such developments.
AGEOS.

continuation:

Whatever the proposed “production optimisation and workover activities” entail, it seems likely that AC will have agreed to an immediate “cash call” from MARETAP as part of the Ezzaouia Field acquisition deal, both to assure ETAP of his financial commitment and to ensure as rapid a progression to the 1000 bopd target as possible. Hopefully the forthcoming presentation and associated company announcements will confirm such developments.
AGEOS.

The March 24th RNS confirming completion of the Ezzaouia acquisition included a comment by AC to the effect that workover and drilling activities to develop the “significant unexploited potential” were anticipated to commence “in the very near future” following consultation with our partners.

Leaving aside the admittedly debatable interpretation of what “in the very near future” actually means timewise, there appears to be two components to the intended work program as described in the March 15th RNS announcing the acquisition. The first is described as “Planned field production optimisation and workover activities expected to increase Ezzaouia gross production to 1000 bopd (potentially resulting in a production of 450 bopd net to Zenith).” The second refers to the “New Concession” and “the agreed work program between ETAP and EPZ” signed by both parties and currently awaiting parliamentary approval. This includes “the drilling of a side-track, the drilling of a replacement well and that of a development well” during the course of the new 20-year concession.

From what I understand of the geological assessment of field potential as discussed in a report prepared by ETAP geologists in 2014, and the current operational context, I infer that the first element of the proposed developments ie “production optimisation and workover activities” will be fast tracked, under the auspices of MARETAP the joint ETAP/EPZ operating company. MARETAP operates on a cash-call basis so any work agreed will require a 50% cash contribution from ZEN and will be sub-contracted.

In the absence of information to the contrary I assume all six EZZ wells [no's, 1, 2, 9, 11,17 & 18] operational in June 2015 are producing and that flow is primarily, if not exclusively, from the Upper Jurassic M'rabtine formation, for which the wells were optimised during 2012/13/14 following a decline in production from the Lower Cretaceous Zebbag dolomitic carbonates which were historically the main reservoir. The M'rabtine reservoirs are sandstones with 17% porosity and 130 md permeability, interbedded with carbonates and shales. The current cumulative production of 465 bopd compares with an estimated 750 bopd maximum in mid-2015.
I assume that a significant portion of the decline is due to reduced flow from CaCO3 scaling of production pipes, as there is a CO2 component to the gas and a high water content, so de-scaling is probably part of the initial workovers. Since EZZ-11 was brought on line in 2015 after perforation of a newly identified production zone, there may also be scope for similar interventions in other wells sufficient to achieve the 1000 bopd.

To be continued

Florida.

It is standard legal practice to ensure that any SPA contract contains protection against contingent liabilities of the kind you describe. The SPA with Candax is therefore likely to include the proviso that “completion” is conditional on the “New Concession” receiving parliamentary approval and passage into State Law. Most if not all of the negative scenarios you outline would therefore not arise.

continuation:

There is much to add regarding the geotechnical aspects of the new acquisition and of the developmental potential, but that can wait until more appropriate times. For now and after an inevitably superficial appraisal, this appears to be another potentially profitable and well executed acquisition by AC.
AGEOS.

Having just read MarketG's excellent account I realise my effort pales into insignificance. However it perhaps reinforces some of the more important aspects of the deal.

The Ezzaouia oilfield was low on my list of 33 potential acquisitions in Tunisia largely due to the recent award of a new 20-year concession, as confirmed in the RNS. Of the five fields [ Ezzaouia, El Bibane, Robbana, Belli & Al Manzah] in which ECUMED, the Tunisian subsidiary of Candax Energy Inc, has an interest, Ezzaouia is by far the most productive, so it appeared to be the least likely candidate for disposal. Also as Candax is 100% owned by Geofinance N V, a private equity investment company which only acquired the asset in 2015, a disposal seemed unlikely and even then only on terms disproportionately favourable to the seller. In that latter respect I'm glad to be proved wrong as AC appears to have achieved acquisition under very advantageous terms.

Acquisition of the entire share capital of EPZ [ECUMED Petroleum Zarzis Ltd] by ZEAL [Zenith Energy Africa Ltd] is crucial to the deal, as the 20-year New Concession, “Ezzaouia”, was applied for, and granted to, EPZ and ETAP [state oil company with 55% interest]. The agreed work programme has also been signed jointly by EPZ & ETAP and most importantly, the currently awaited parliamentary approval, will relate to the “New Concession” in the names of EPZ and ETAP. Legally, the acquisition of EPZ by ZEAL does not materially influence that process of parliamentary approval of the concession itself so there should be no consequential delay in granting of that approval.

With regard to the terms of the SPA [share purchase agreement], the cash payment of US$150,000 is well covered by the recent capital raise, and presumably the US$100,000 share issue will be at the share price current within 60 days of completion, so the higher the SP the lower the dilution, minimal though that will be. The royalty of US$0.35 per barrel, [ie 45% net to EPZ], for 10 years, with a minimum of US$50,000 per annum, implies a calculation based on a minimum average production of 391 bopd per annum. In total a very advantageous outlay for the anticipated production and development potential.

Operational costs are as yet unknown but as MARETAP, the joint operating company will be owned in partnership with ETAP [on a 50/50 basis according to Candax], expenditure over and above day to day operations will be by mutual agreement. It is reassuring that a major remediation program of all six producing wells was completed in 2012, involving de-scaling and replacement of jet-pumps with sucker-rod pumps. So hopefully no seriously expensive upgrades due in the near future.

To be continued

CanaryInTheMine

In answer to your question regarding the Nigeria Marginal Field bid, AC is on record in his comments following the 18.09.2020 RNS as saying:

“In the event our Bid is accepted, we have already received positive indications from a number of pan-African financial institutions regarding obtaining the necessary financing to develop the asset and achieving commercial production.”

I have no doubt therefore that the signature bonus of up to $5m will have been factored in to the financial pre-planning and will have been part of the discussions with those financial institutions. It should therefore not be an issue relating to current cash flow.

Quote from Financia Fox interview 02.02.2021 at 15.23mins "so in Congo we are discussing already our second and possible third and fourth assets"
I've posted details of potential targets in several posts, eg 10.07.2020.

continuation:

Mazarine Energy, a private equity enterprise backed by Carlyle Group, wants a partner to help finance up to half of its interests in the Ghrib, SMG-1, Zaafrane and Douiret concessions. Current production is 1400 boed and new wells are planned in association with ETAP which has a 50% interest. I doubt AC would be interested in any private enterprise partnerships.

Serinus Energy in its most recent presentation [Jan 2021] appears positive about future development of its Sabria, Chouech Es Saida and Ech Chouech concessions. Its 100% WI in the none-producing Zinnia Field which expired Dec 2020, does not however seem to have been renewed so is presumably now open for negotiation.

If ZEN acquire one or more additional fields in Tunisia, it will be to build production and enhance the potential for further development of those assets, The next few months will probably reveal the extent to which they are successful in that objective.
AGEOS

continuation:

OMV, the Austrian conglomerate has already disposed of most of its former interests in Tunisia, mostly to Perenco in 2017/18, but retains a stake in 8 southern fields producing a net total of 5000 boe/d, comprised of Chourouq 50% [ETAP 50%] 160bopd, Durra 50% [ETAP 50%] 600bopd, Nawara 50% [ETAP 50%] 2500bopd, Anaguid Est 50% [ETAP 50%] 290bopd, Jinane 50% [ETAP 50%] 123bopd, Banafsej Sud 50% [ETAP 50%], Adam 20% and Sondes 40% [ETAP 50%] zero production. Nawara includes a major gas'condensate project of considerable strategic importance to the country and forms part of OMV's growth strategy. The Durra/Mona Field may however be negotiable and of interest to ZEN as Wood Mackenzie issued a report on it in September 2020, it being two oil finds brought onstream in 2011 within a previously known gas/condensate Silurian reservoir. The oil is trucked to the nearby Cherouq facilities.

Perenco, a rapidly growing mid-tier global, has since 2002 increased its Tunisian interests to 10,000boed of condensate and substantial LPG and gas production. Following a swathe of acquisitions in 2017 & 2018, including 50% of SEREPT, a JV with ETAP, and considerable investment in 3D onshore seismic, Perenco is unlikely to be offloading any of its interests. More likely it will be competing to acquire further interests and is a likely candidate for the UPL Saouaf farm-in.

Panoro Energy reported 2020 production of 4000bopd [1160bopd net] from its 29.4% share of the TPS assets, ie 3 onshore fields and 2 in shallow waters offshore from the city of Sfax. It also has a 52.5% interest in the Sfax Offshore Exploration Permit and the Ras El Besh concession, including 3 recent oil finds, P50 estimates of 250m barrels in place and very considerable exploration potential. Panoro is currently acquiring massive offshore interests in Equatorial Guinea and Gabon from Tullow Oil so with its Tunisian focus apparently also on the offshore potential, there is the possibility of it offloading the three onshore fields of Gremda/El Ain, Rhemoura 390 bopd and Guebiba/El Hajeb 2500-3000bopd, all ETAP 51% and Panora 49% interest. These fields have similar geotechnical characteristics to those of Sidi El Kilani so might be of interest to ZEN.

To be continued

Florida, thanks for your response. Yes, the SLK concession and the N Kairouan Permit have a great deal more potential than just work-overs of the current producing wells. I mentioned aspects of this potential in posts dated 14.06.2020 & 13.09.2020 but there is much more. The permit area, excluding SLK, has been targeted by 22 exploration wells, 6 of which flowed oil to surface from the Abiod and/or Bireno-Douleb reservoirs, so with the recent advances in seismic interpretation could well justify further exploration and development drilling. . The adjacent 536 sq km Bouhajla Permit could also be on ZEN's radar following the $7m BHN-1 failed intervention by DualEx as it leaves at least 3 other targets immediately west of the SLK Field. However all this is potential mid to long-term so I will not enlarge further at this stage.

What is currently more relevant is that on the assumption that ZEN would only be interested in acquiring additional onshore fields with mature oil production, and preferably with associated developmental and prospective potential, there are approximately 33 possible candidates. ETAP, the Tunisian national oil company, has an interest in all but 9 of these.

Sidi El Kilani, the first acquisition, was an obvious target, being the only field in which two global O & G companies had their sole Tunisian representation, so at the time a prime candidate for divestment of minority interests. With both KUFPEC and CNPC thus out of the picture, that leaves ENI [ENI Tunisia BV] and Total [CFTP] the only national majors with interests, those of the former being by far the most significant.

ENI are diversifying into solar, and gas to electricity conversion, and have major offshore O & G production [Maamoura, Baraka.] and exploration interests in the marine extension of the Pelagian Basin [ a geological construct] between Tunisia and Sicily. They are also active in further developing the major MLD [Makhrouga, Laarich, Debbech] and El Borma Fields in the south. Of the remaining 5 or 6 onshore legacy fields, all in the far south, Oued Zar/ Hammouda may be on offer as it is the subject of a July 2019 Wood Mackenzie report, but with both oil and gas production in steep decline from a 9500bopd peak in 1999 [5150bopd by 2010] and an associated gas to power plant to maintain, I doubt ZEN would be tempted. Likewise for any of the other southern fields.

Total's interests are now largely upstream, so CFTP its Tunisian subsidiary, has relatively limited O & G production and that committed to maintaining its upstream services. So highly unlikely to be offloading any of its onshore fields, all 100% owned.

To be continued

Those familiar with the terms of the Tunisian acquisition will know that in addition to the 45% interest in the 204 sq km Sidi El Kilani concession, which contains the SLK Oilfield, ZEN will also acquire a working interest in the approximately 2200 sq km N Kairouan Permit. The extent of the permit area is shown on a map on the ZEN website via operations/Tunisia.

It is worth noting in view of the recent references to Upland Resources that UPL's 4004 sq km Saouaf Licence occupies the area immediately north and west of the two most northerly blocks of ZEN's N Kairouan Permit area.

The most recent [15.02.2021] RNS from UPL confirms 15 potential plays within the Saouaf area centred on a Mesozoic [Lwr Cretaceous Ressas Formation reef deposit on a Jurassic, Nara Formation platform, with shale seal.] carbonate platform and an unspecified Sub-Salt target of at least four structural highs of between 61 & 192 sq km in extent. Limited legacy drilling in the area indicates gas reservoirs, estimated at P50 [Best] of 1.1 TCF [= 183 Mboe ie oil equivalent] from the best prospect with a 22% probability of success. There is also the SNJ oil prospect [based on well SNJ-1] with an estimated 42Mbbl, not mentioned in this RNS. Upland consider their data acquisition and analysis sufficiently advanced to justify inviting applications for a potential farm-in.

Whilst I do not anticipate ZEN having any interest in that latter respect, it is nevertheless significant that the Saouaf area does offer such prospectivity and is adjacent to the N Kairouan Permit area. A geo-structural map of Saouaf on the UPL website, although out of focus and therefore largely useless, does however show the SW Enfidha structural high[?] as extending into the N Kairouan area, and a regional NE-SW structural trend which should favour the development of other such highs into ZEN's acreage. The Kairouan Basin [ a geologically defined area] was the subject of a study by OMV geologists in 2017 which incorporated the 2D & 3D seismic from the N Kairouan Permit area and concluded that the Sidi El Kilani Field is a structural high elevated by a Triassic salt diapir above Palaeozoic basement. If the latter includes similar fluviatile reservoir rocks to those of the S Tunisian Palaeozoic Berkine-Ghadames Basin there is the prospect of a new major oil province in the sub-salt zone within the Kairouan area.

Although Saouaf does not appear a likely target for ZEN acquisition there are others which do and upon which I could post details if of interest to anyone. Otherwise I shall await further news.
AGEOS.

The reference in this 12th Feb 'Le Congolais.fr' article relating to Tilapia, translated as “The site's production is expected to rise to 1,500 barrels per day after the development work.” is probably an unattributed quote from the 13.02.2019 Production Plan for TLP-103C released by AAOG.

That stated “TLP-103C to produce from the upper reservoirs by comingling production from R2 and the Mengo, following a double completion including a one-off frack of the Mengo” to produce an “Initial anticipated aggregate flowrate in excess of 1500 bopd for the first 14-18 months.”

Aqualight's speculations that the reference to 1500 bopd implies work on other wells is, I'm sure, incorrect. Although 6 wells and 2 sidetracks were drilled prior to end-2016, only one well [TLP-101V] and one sidetrack [TLP-101ST] were drilled from onshore, all others having been drilled offshore. None of the offshore wells are likely to be reinstated.

Zen will no doubt release operational plans for Tilapia after the PSC [Production Sharing Contract] has been successfully concluded.

Sarge123, good to know you're still here; patience soon to be rewarded, hopefully.
AGEOS