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Nigerian Indies: The Talented Tenth Annual

By the Editorial Board of the Africa Oil+Gas Report…


Africa’s growth as an industrial marketplace is going to be determined by its exceptional companies


Nigeria is the main playground of Africa’s homegrown independents.

Nowhere else on the continent provides the ready breeding ground for this unique species of Exploration and production companies.

 But what do we mean by the term Independent?

When an E&P company, holding one or several oil and gas permits, and exploring and or producing them, is not large enough to be considered a Major, then it is an independent. The world has only six majors: ExxonMobil, Shell, Chevron, BP, TOTAL and, to a lesser extent, ENI. All other E&P companies, the largest of them being ConocoPhillips, are ranked as Independents.

 Over 25 private Nigerian owned, indigenous independents produce oil and gas from the bowels of their hydrocarbon rich country. In 2018, their total, operated crude oil output averaged slightly less than four hundred thousand barrels of oil per day (400,000BOPD). That’s a significant contribution from the private sector in any petrostate in the world.

 Some of these companies are leading the charge on in-country beneficiation of hydrocarbon resources. Some are keen champions of the industrial society. Yet many-and justifiably so-are just about the extraction: “to win and carry away”.

 At the Africa Oil+Gas Report, we understand that a continuous evaluation of the context of growth and challenges of the Nigerian independent provides a clear line of sight to opportunities for investment in Africa’s hydrocarbon properties.

Excited by its success at achieving first oil, First E&P Presents a model of its FPSO to DPR

THE TALENTED TENTH ANNUAL, of which this article is the fourth edition, is our rough but intelligible ranking of the top 10 progressive, indigenous Nigerian E&P Independents.

This is where we publish, in few hundred words, efforts of those Nigerian indies, who show the most willingness and ability to grow; who are keen on operatorship and not content to be mere partners. Those firms whose choice of projects help catalyse the industrial economy and who exhibit old fashioned aggressiveness that is not contaminated by the rentier instinct.

While corporate governance issues light up on our radar, we take more than a cursory look at the debt profile. We have a soft spot for companies who are angling to diversify into midstream, even downstream segments, to help tackle the country’s industrial challenges. We are, of course, passionate about healthy focus on community development.

We acknowledge that a company’s emphasis on everything but profit will not guarantee its survival.

This list, which we will continue to update and publish yearly, is unlikely to ever include companies who become operators by default.

Disclaimer: This is not a stamp of approval for any investment decision. It is an analytical piece by a set of journalists focused on ways and means of operations of upstream E&P companies in Africa.


No. 1 -NDEP

For the first time in the short history of The Talented Tenth, SEPLAT Petroleum is not occupying the top position.

The lead, this year, is taken by Niger Delta Exploration and Production (NDEP), which had competed fiercely against SEPLAT for the three consecutive years that the latter had been crowned winner.

NDEP remains the most integrated energy player among Nigeria’s independents; crude oil output, gas processing plant and a refinery designed to produce, among other products, gasoline.

The Ogbele refinery comprises three modular trains that can process 11,000BOPD at optimum to output Diesel, Marine Diesel, DPK, Naphtha and High Pour Fuel Oil. NDEP envisages that when all the trains are running optimally, by the end of the second quarter 2021 at the latest, the Train 3 will fully convert all Naphtha to Premium Motor Spirit (Gasoline) at an average daily output of some 600,000 Litres.

NDEP has been producing crude oil from Ogbele field for 15 years, exploiting a marginal field whose recoverable reserves was estimated at 5Million Barrels at the time it was acquired.  In two of the four ranking years of The Talented Tenth, NDEP has bolstered output of its primary product. Between 2018 and 2019, it grew production from 6,500BOPD to 9,000BOPD. Between then and 2020, it pushed upwards to 12,000BOPD, but OPEC+ curtailment compelled the output to be capped at 9,000BOPD for the October-December 2020 Quarter.

Since 2011, the company has operated a 100Million standard cubic feet per day (100MMscf/d) gas processing plant from which it pipes 35MMscf/d to the NLNG system at Bonny. A Nigerian offtaker purchases another 1MMscf/d for onward sale to industrial outlets. The company started acquiring additional capacity build-up for the gas processing plant in 2019. Early in 2020, it took a Final Investment Decision (FID) to increase the processing capacity to 400MMscf/d. “Investments in this project will continue, with completion projected before the end of Q4 2024”, NDEP explains in a report. “After extensive internal and external economic, financial and technical re-evaluations, the aim was to position Ogbele as an emerging gas processing hub, in the Eastern Niger Delta region”.

The refinery project initially came on stream in 2012 as a 1,000BOPD capacity topping plant, producing 85,860 litres of diesel every day from 540BOPD of crude. In late 2019, a second 5,000BOPD train was added.  With another 5,000BOPD train completed in October 2020, the three train 11,000BOPD refinery is fully functional.

Apart from the Ogbele marginal field, the company operates two other upstream assets: the Omerelu marginal field onshore, still undeveloped and the Oil Prospecting Lease (OPL) 227, an exploration acreage, offshore. NDEP drilled an appraisal well in OPL 227 in 2019 by drilling, with disappointing results. It deployed a rig on the Omerelu structure and encountered gas in the sidetrack hole, as prognosed.  In the meantime, NDEP achieves its full crude output capacity when the Trans Niger Pipeline, the evacuation facility, is not shut in due to vandalism, which is the most significant challenge.

NDEP has 42% (majority) stake in NDWestern, the entity that holds 45% in OML 34, which averaged gross production of 20,000BOPD of crude and 300MMscf/d of gas in October 2020.

NDEP is keen on winning the credentials of a Pan African hydrocarbon upstream player. It is in a joint venture with NilePet, the South Sudanese state hydrocarbon company. It won a lease in the Ugandan 2015/2016 bid round but dropped the asset as a result of governance concerns. It is in an ongoing conversation with the Mozambican government, for a licencing award for onshore natural gas development.

NDEP is a nimble enterprise that was founded in the late 1990s with the idea of having more than a handful of shareholders pooling resources, a contrarian thinking to the concept that created most Nigerian independents, so it holds a regular, annual, well attended General Meetings, although it has remained shy of listing on the local stock exchange, let alone any international bourse.

One chink in NDEP’s governance armour had been the leadership succession. For most of 2019, the company was certain of the handover of the Chief Executive position from Layiwola Fatona, who has run the company from the beginning, in 1996, to Toba Akinmoladun, an ex-Shell General Manager. It didn’t work out. In February 2021, two full months outside the scope of this report, the company took on board Gbite Falade, as Mr. Fatona’s successor. Any commentary on the success or otherwise of this succession will have to wait for the 2021 edition of The Talented Tenth Annual.

NDEP is proud of its partnership deal with the host communities around the Ogbele field which involves a clause that allocates 5% of the annual profit to the communities. It is one of the most generous partnerships that any Nigerian independent has initiated with its neighbouring constituents.

NDEP is a smart, highly technically resourced company that is continually looking forward.


SEPLAT has grown larger in asset holding since the last ranking. With the acquisition of AIM listed Eland Oil and Gas in December 2019, the company now holds participating interests in OML 40 and Ubima marginal field.

Its portfolio now comprises eight oil blocks- direct interests in seven blocks in the Niger Delta area, four of which (OMLs 4, 38, 41 & 53) SEPLAT operates, and one further (OML 55) revenue interest.

SEPLAT Petroleum remains the most transparently governed E&P independent operating in the country.

In 2020, it welcomed a new Chief Executive Officer, taking over from a man who co-founded the company 11 years ago. The British accountant Roger Brown’s taking of the reins of SEPLAT from the Nigerian geologist and entrepreneur, Austin Avuru, is a textbook story and stuff of legend. Brown is an employee of the company; he wasn’t coming from “corporate headquarters abroad” to take charge. In a fragile petrostate where opacity is the norm, this kind of open court running of one of the largest enterprises in the land, counts for a lot. As we have indicated here before, whereas The Talented Tenth Annual has to rely on its own intelligence gathering skills for accessing the production figures and operational challenges of most Nigerian independents, this dual listed company (London Stock Exchange, Nigerian Stock Exchange) has its data laid out bare in public, even when the details are not entirely-in the slang of the social media-likeable.

2019 could be said to be the year of SEPLAT.

In March of that year, it took the Final Investment Decision (FID) to proceed with the Assa North-Ohaji South (ANOH) gas and condensate project at OML 53. In December it completed the acquisition of Eland Oil & Gas. The ANOH project entails the valourisation of 300MMscf/d of gas from those straddle fields (Assa North and Ohaji South) through a short pipeline into the Obiafu-Obrikom-Oben (OB3) pipeline, the grid length, east –west gas transmission line, which terminates at SEPLAT’s Oben facility, a hub “ideally located to aggregate and supply gas to Nigeria’s main demand centres on the Lagos and Abuja axes”. That FID, for a project of $700Million worth, affirmed the company’s leadership in the country’s domestic gas market.

But that was a year before the period covered in this report. Whilst work is going on in ANOH, there has been a drop in gas output in SEPLAT’s western Niger Delta assets. Gross supply from OMLs 4, 38 and 41, has dropped from 291MMscf/d in 2019, to less than 220MMscf/d for most of 2020.

Liquids production in the first nine months of 2020, leaped to 33,327BOPD, surpassing the company’s 2015 output (29,000BOPD), which is the record in the company’s 11-year history.  But this was on the back of the additional crude output contributed by Eland and incremental output from OML 53.

There was, fortunately, a decrease in losses arising from crude evacuation in the Transf Forcados Pipeline, but the alternative route is far from ready; the Amukpe-Escravos Pipeline is now expected operational in H2 2021.

SEPLAT started business as a Special Purpose Vehicle for the acquisition of Shell/TOTAL/ENI’s 45% in OMLs 4, 38 and 41 and rapidly grew production from 20,000BOEPD (gas + liquids) in 2010 to 50,000BOEPD in six acreages including Oil Prospecting Lease (OPL 283) and OMLs 52, 53 in 2018. These figures are net to SEPLAT.

In 2019, SEPLAT was not as aggressive at the drill bit as it could have been, but in 2020, its vow to “return to a level of drilling and development activity not seen since 2015”, was thwarted by the Pandemic.

Even the best run entities in Nigeria are affronted, when “Nigeria Happens”. As we went to press with this edition, the news broke that the building in which SEPLAT Corporate Headquarters is located, in Lagos, was sealed in connection with a court case by Access Bank, the country’s top lender, against Cardinal Drilling Services Limited, a third-party providing drilling services to SEPLAT. Cardinal Drilling has outstanding loan obligations to Access Bank. SEPLAT insists it is neither a shareholder in Cardinal Drilling, nor has outstanding loan obligations or guarantees to Access Bank and did not at any time make any commitments or guarantees in respect of Cardinal Drilling’s loan obligations to Access Bank. It argues that there is no merit or justification “for this action against it and has taken prompt legal action to vacate the court order pursuant to which the building was sealed”. But three weeks after that statement was issued, a high court order insisted that SEPLAT’s Corporate offices could still remain under lock and key if that was what Access Bank wished and that the case was only going to be heard in late January 2021. This is not good optics.

Despite the daunting Nigerian risk, SEPLAT looks sure to prevail and grow in the next five years, with its corporate governance structure, its constant watching its pocket with ratio of spending and debt to production revenue and its ability to manage its relationship with all the state hydrocarbon companies it works with, including the NPDC (with which it has a Joint Venture operations in OMLs 4, 38 & 41, the Nigerian Gas Transmission Company (with which it has formed an Incorporated Joint Venture midstream gas company) and NAPIMS, the investment arm of NNPC which runs the JV relationship in OML 53.

No 3- NDWestern

NDWestern benefits from the technical strength of NDEP, the top performer in this year’s ranking. Founded in 2011, it is majorly owned by NDEP (42%), Petrolin (40%), First E&P (10%) and Waltersmith Petroman (8%). It was formed as a Special Purpose Vehicle for the acquisition of the 45% stake owned by Shell/TOTAL/ENI in OMl 34, the gas and condensate rich asset in the Western Niger Delta. This company is a joint operator, with state firm NPDC, of OML 34.

In 2020, the NPDC/NDWestern JV swept past the SEPLAT/NDPC JV as the largest indigenous producer and supplier of natural gas into the domestic market. Its gross output of 310Million standard cubic feet per day (310MMscf/d) on average in that timeframe betters the nearest local competitor by around 25%. The Joint Venture supplies the 1,000MW Transcorp Power Plant at Ughelli, the 1,320MW (capacity) Egbin Power Plant in Lagos, Olorunsogo Plant in Ogun State in Nigeria’s southwest, as well as other offtakers through transport lines operated by the Nigerian Gas Transportation Company. The company envisages production of over 400MMscf/d “if the off-takers will perform”.

With a string of newly completed wells, the JV has also boosted liquid hydrocarbon production by 25%, consistently averaging in excess of 20,000BOPD in the last half year of 2020.

NDWestern has completed Front End Engineering Design (FEED) on a 10,000BPD refinery on OML 34 and hopes to convince NPDC to jointly take a Final Investment Decision by second quarter 2021. NDWestern’s 2020 revenue, up to October 2020, was running north of $200Million, with 33% operating profit. Gas offtake has been higher than forecast and the company has been pleasantly surprised that crude oil prices were doing better, as of end of 3Q 2020, than had been predicted earlier in the year, when the contagion forced down prices to sub $10 levels.

Like every E&P player, NDWestern is facing severe headwinds. The order from the Nigerian National Petroleum Corporation (NNPC), parent company of the NPDC, to slash Capital Expenses (CAPEX) by 30%, means that a number of growth projects will roll off to the back burner. Compounding this is the demand by the NPDC, to take over the role of Chief Operating Officer (COO) of the Asset Management Teams (AMTs) in some of the Nigerian independents it has Joint Venture with,including, of course, NPDC. The chronically inefficient NPDCIt is also asking to include a larger proportion of technical managers in the teams. The companies are pushing back.

But if there’s any surefooted Nigerian company which has a solid future, at least in the near term, NDWestern is one.


Waltersmith Petroman’s main claim to the top four of The Talented Tenth for all our four annual rankings, is its advance the industrial economy on the back of a small hydrocarbon resource.

It neither has the breadth of an NDEP (No 1), nor the volume of a SEPLAT (No2). But it keeps on charging forward. Its yearning to contribute to the country’s industrial growth is a crucial marker point. Waltersmith is a marginal field producer who produces barely 7,000BOPD at the most but has, since 2017. relentlessly pursued the idea of a phased refinery complex; a gas processing plant and gas fired power plant as centrepieces of an industrial park to service factories, and provide support to industries and other enterprises in a space spanning over 65 Hectares. When it commissioned the project’s first phase: a 5,000BOPD modular refinery last November, it was clear to everyone that it was on course of delivering the hub it promised. That commissioning event doubled as groundbreaking ceremony for the next two phases, (a 25000BPD Condensate Refinery and a 20,000BOPD Oil Refinery) leading to a 50,000BOPD refinery complex producing, by the company’s own estimates about 2.7BIllion litres of products per annum by 2024.

Will it deliver?

Actually, it had started to.

Three things have progressed since the late November launch: the Nigerian Content Development and Mentoring Board (NCDMB), which helped finance the 5,000BOPD, refinery, says it is ready to support the next phase. In late December, SEPLAT announced it had inked a crude purchasing agreement with Waltersmith to supply the refinery as much as 4,000BOPD of crude. The United Nations Industrial Development Organisation (UNIDO) and United Nations Economic Commission for Africa (UNECA) have signed a Technical support agreement with the company for the development of the Industrial Park. This entails preparation of project concept, feasibility studies, business plan, fund raising, promotion and attracting companies and overall implementation. Much work still has to be done.

As there isn’t a significant upside in the Ibigwe field resources itself, Waltersmith is eyeing oil and gas assets in the vicinity. “We are still engaging the Presidency, Ministry of Petroleum Resources and NNPC to resolve the feedstock issue, including condensate in OML 53 on a wholistic basis”, the company says in its brief.  “Thereafter we will take FID”, it explains.  “All our current partners and more (read NCDMB and Africa Investment Corporation AFC) are lined up for participation in the next phase”, which is the 25,000BPD Condensate refinery. This ambition to run an industrial park with a significant bolstering of  in-country beneficiation of Nigeria’s hydrocarbon resources is what makes Waltersmith one of our favourites. But it also has the potential to pull the company down. The second phase of the refinery project is challenged by NNPC’s insistence that the condensate from the SEPLAT operated OML 53’s ANOH development is rightfully its own to offtake and it is going ahead to build its own condensate refinery on ANOH field. It would seem like a joke, that NNPC says it actually wants to build a new refinery, but even if it eventually doesn’t, the publicity the state hydrocarbon company is making about it is enough to diminish the bankability of Waltersmith’s project. In any case, for as long as NNPC makes the claim it wants to build a condensate refinery on ANOH field, it is taking out the very feedstock that Waltersmith has banked its refinery project on. And what if Waltersmith doesn’t succeed in winning any asset in the marginal field bid round?

Created in 1996, Waltersmith was awarded the Ibigwe field (then located in OML 16 but now OPL 2004) in 2003 through the marginal field licensing round. It has had three field development phases, involving six successful wells, since it took up the licence. It started production in 2008, ramping up from an initial 500BOPD to the current optimum output of 7,00BOPD over a period of ten years. It also has 8% equity of NDWestern, which itself has 45% of OML 34. In 2016, Waltersmith won the Turaco acreage in Uganda, after a keenly contested bid round, but dropped the asset because of “unfavourable terms”.

In 2019, the company was awarded an 80% stake and operatorship in Block EG-23 in Equatorial Guinea’s Niger Delta basin. Its partners include Hawtai Energy (HK) Limited and GEPetrol (the National Oil Company of Equatorial Guinea), with whom a draft PSC has been successfully negotiated and awaiting execution with the Ministry of Mines and Hydrocarbons who doubles as the Concessionaire and the government of Equatorial Guinea. Block EG-23 has a total area of 592 square kilometers and located offshore in water depths of 50-100 metres.

Waltersmith is not an open company with a large pool of shareholders and an independent board like SEPLAT and NDEP. But in 2019, the company’s Executive Chairman ceded the Chief Executive position to Chikezie Nwosu, a technically honed, experienced industry hand who has worked at top levels at Shell and Addax.  The company also revamped its management and brought in a broad range of technical and managerial skills from key E&P companies in the industry. If there’s anything, Waltersmith gets the messaging right. And we are willing to believe it. The Talented Tenth gets the sense that, the large, ever attendant Nigerian risk notwithstanding, this company will continue taking a several steps forward, to enable Nigeria’s industrialisation, in the short to medium term.


Platform Petroleum, also a marginal field producer, makes the Talented Tenth for the first time in its four editions. 13 years after the company commenced production of condensate, exported as crude oil, from the Egbaoma field, in Oil Mining Lease(OML) 38 in the north west of the Niger Delta basin, it started supplying lean natural gas to the Nigerian domestic gas market, through the Nigerian Gas Company (NGC) operated Oben-Obiafu-Obrikom (OB3) pipeline. With a 10 year Gas Sales Agreement with the NGC, committing 10 – 30Million standard cubic feet of gas per day supply to the OB3, Platform becomes a local natural gas supplier of some reckoning, the only indigenous marginal field operator with that level of commitment of gas into the “national gas grid”. It’s a steep reversal from the situation in 2014 when, after installing a 30MMscf/d gas processing plant, the company faced commissioning hitches and had to bring in partners to take financial and operational stake in the plant. What qualifies Platform for the Talented Tenth, is that willingness for portfolio diversification, beyond a mere producer and exporter of liquid hydrocarbons in the first place.

Platform has been in continuous, uninterrupted output (except for the standard outage by vandals and militants) all these years. It has produced, on operated gross basis, an average of 3,000BOPD for 2020. The company is the first of the 31 indigenous E&P independents, awarded 24 marginal fields by the Nigerian government in 2004, to reach first oil. It commenced production in September 2007, after 34 months of taking over what was then named Umutu/Asuokpu field (later renamed Egbaoma field). Platform reached this point with the help of Newcross, another Nigerian E&P firm, which provided some financing and took 40% stake in a Joint Venture. The partners constructed and commissioned a 48km crude export pipeline, from their field, eastwards to ENI’s export facility in Kwale. The pipeline to Kwale now serves other companies who operate marginal fields in the vicinity, called the cluster, including Pillar Oil (which produces the Umuseti field), Energia (which produces the Ebendo field) and Midwestern Oil&Gas (which produces the Umusadege field).

Platform is neither as diversified as NDEP (No 1 on this list), nor has it the scope of a SEPLAT (No 2), but it can take a large credit for the creation of SEPLAT in 2009. It was Platform’s search to grow beyond being a mere one marginal field producer that led it to request Shell to divest OML 38 to it. At the time Shell decided to respond, there was also a request by Shebah Exploration, another local producer, on the table. The two companies formed SEPLAT from their names and Platform today, still holds as much as 7.5% of SEPLAT’s entire equity.

But Platform remains an independent company outside the arrangement and still has ambition to grow.


Eroton makes the Talented Tenth largely through the quality of its asset.

It is the 45% holder and operator of OML 18, onshore eastern Niger Delta, a property with, as of 2017, 2P reserves of 576Million barrels of crude and 3.2Trillion cubic feet of gas. Its average operated (gross) output is between 35,000BOPD and 45,000BOPD (before OPEC restrictions, which has now compelled it to produce 27,500BOPD).

It has industrial ambitions for its huge gas resources, though it produced less than 40MMscf/d, in spite of all those huge reserves, it is the sole supplier of natural gas to Notore, the fertiliser producer, its sister company, whose offtake is constrained by its ongoing Turn Around Maintenance.

Eroton has a proposal to develop up to 224Billion standard cubic feet of gas, for peak offtake of 260MMscf/d, according to the latest annual report by the Department of Petroleum Resources, Nigeria’s hydrocarbon regulatory agency. It says it expects to pool this volume from four fields: Alakiri (81MMsc/d), Cawthorne Channel (133MMscf/d), Akaso (41MMscf/d) and Opolo (5MMscf/d) in OML 18. It is the highest planned production of associated gas, in pre-development phase, by any company in the country. No further information about this project is located anywhere else.

As Eroton searches for offtakers for its putative gas projects, it is concerned about the 25-35% losses it incurs in crude evacuation, as a result of vandalism of the export pipeline: Nembe Creek Trunk Line (NCTL). Eroton is the promoter of the Alternative Crude Oil Evacuation System (ACOES) project, currently under construction by Energy Link Infrastructure (Malta) Ltd. (ELI), a third party in which Eroton is invested. ACOES is being built to provide a dedicated oil export route from OML 18, comprising a new pipeline and a floating storage and offloading vessel (FSO), ELI Akaso. The ACOES pipeline component is expected to have a throughput capability of 100,000BOPD, while the FSO has a storage capacity of 2Million bbls of oil. Once commissioned, ELI’s charges are expected to be comparable to current NCTL handling fees.

Eroton has the added advantage of a combined experience of its constituent founders. An outgrowth of Martwestern Energy, formed by Midwestern, operator of the 15,000BOPD Umusadege field and Mart Resources, the Canadian junior which has now been bought out by the former through the London listed San Leon, it also has Sahara Energy as a part owner. It proposes, next year, to continue the development drilling campaign it ended last April, with another three wells in the second half of 2021.


Neconde has shifted away from Pipeline evacuation

After a series of false starts, Neconde has become a valid member of Nigerian indigenous gas producers’ club. Two years after announcing, with fanfare, the revamp and commissioning of the Odidi Gas processing plant, in OML 42, which it jointly operates with NPDC, Neconde finally started reporting meaningful volumes of utilised gas, in third quarter 2020. In October 2020, utilised gas averaged 18MMscf/d, but that was a low and was largely due to crude output challenges brought about by community workers’ strike. At optimum, it has been delivering around 35MMscf/d in the last three months.

Field data received by Africa Oil+Gas Report between November 2018-when the gas plant was deemed commissioned -and July 2020, had indicated that most of the gas produced in OML 42 was simply flared. Utilised gas for the period averaged less than 2MMscf/d. It was thus noteworthy to start seeing utilised gas ticking upwards. What’s important to The Talented Tenth here is a Nigerian independent adding natural gas to the value stream.

Prior to this small achievement, Neconde Energy had largely been in the ranking due to its daring, alternative crude evacuation method. Since the third quarter of-2018, the NPDC/Neconde JV had opted out of exporting its crude through the Shell-led, Trans Forcados Pipeline System TFPS. It is the only one of the nine Nigerian independents impacted by the 16 month long shut in of the TFPS from 2016 to 2017, to have decided to permanently stay out of the uncertainty engendered by pumping crude through this influential facility. For that it has recorded a significant drop in redundancy and been rewarded with consistency of output at above 40,000BOPD for 80% of the period between July 2018 and October 2020. The company has more significant control than its peers, in delivering specific volumes from the well-head to the terminal. But how it has achieved this is also important. The NPDC/Neconde Joint Venture barges its crude through rivers to the Forcados terminal. To get export ready crude into the boats, it had to install a treatment facility. For the barging, the company has to pay cabotage fees, inland waterways number permit and DPR permit. Marine work is difficult because of the logistics and, as illegal bunkers can attack the barged crude on the way, the security cost is high. The Nigerian Navy escorts the barged crude with gunboats in front and back.

Neconde was formed by Nestoil, a leading local oilfield construction company and Yinka Folawiyo, holder of the OML 113 (containing the Aje field). From the outset, it has been the one of the most aggressive of the four Nigerian Independents who acquired Shell/TOTAL/ENI’s equity in four acreages in 2012. It was the most vocal in disputing the operatorship of the state firm NPDC, which has served largely in holding back production in these assets at a time of rising oil prices, a situation that has now, in retrospect, proved to be value destroying, as the loans raised for those acquisitions could no longer be rapidly paid back in the low-price era.

A corporate governance structure to enable sustainability of operations and regulatory compliance could help Neconde a great deal.


Conoil Producing, the country’s first real Nigerian independent operator of E&P assets, has been around for close to 30 years.

It has delivered on the original promise of ‘The Indigenous Thrust” of the Nigerian Military Government, which granted petroleum prospecting licences to “Nigerian Businesses who had performed well in other areas of endeavour”.

But its current average production of 20,000BOPD is, to put it mildly, punching below its weight.

And this is not about OPEC+ curtailment.

The challenges to maintain output at 20, 000BOPD and even double it, as is the plan, have far less to do with the subsurface than above ground issues and largely centre around leadership. Conoil has been haemorrhaging smart technical talent in the last five years, without durable replacement.

The company has seen off two managing directors since December 2015.

Conoil operates Oil Mining Leases (OMLs) 103, 59, 150 and 153. In 2015, the company signalled aggressive drilling and comprehensive exploitation of these assets and targeted 40,000BOPD by 2019, at the latest.  But that enthusiasm has waned. Outside of the operated acreages, Conoil is not exploring the full benefits of the partnership it has with TOTAL, to allow the French major to operate the gas reserves in OML 136 and Oil in OML 257.

27 years since it made its first oil discovery and 29 years since it was first awarded an exploratory tract, Conoil has prevailed. But it doesn’t have a technical or managerial succession planning scenario, which is a disadvantage. It will likely be around in the next five years, most likely in its current form, but a higher production than 20,000BOPD is not guaranteed, even in the best of local and international environments. The Company’s main risk to being an exceptional performer in the Nigerian environment is its own self.


First E&P commenced oil production from the Anyala West field in shallow offshore Oil Mining Leases (OMLs) 83 & 85 in October 2020. It is the fourth Nigerian indigenous operator of an offshore acreage but only the second, after Conoil, who didn’t become an operator by default.

It has taken two undeveloped discoveries to first oil, six years after it bought the assets from Chevron. Although First E&P had developed (and is still developing) these properties as part of a joint venture with NNPC, which is credited with supporting with prompt cash call payments, it has done so clearly in an adverse period of relatively lower crude oil prices.

The company started producing into the FPSO Abigail-Joseph from four producer wells and has added more wells (in 2021, which is outside the scope of this report).

First E&P had always come across, to the editorial board of the Africa Oil+Gas Report, as a candidate for inclusion in The Talented Tenth, but always looked over because it wasn’t an operating producer of hydrocarbon asset. It also wasn’t clear to the board what First E&P wanted to do with its gas assets.  The company came to public consciousness in 2012, when it took a $67Million loan to acquire 10% stake in NDWestern, as the latter purchased 45% of OML 34. A full year later, First E&P convinced Chevron to sell its 40% stake in OMLs 83 and 85 for an amount slightly less than $70Million. First E&P was also

Involved in Dangote subsidiary WAEP’s purchase of OMLs 71 and 72 from Shell/TOTAL/ENI for about $300Million.

Pan African Ambition-

In 2019, First E&P, pulled ahead in Ghana’s first licencing round, winning Block GH_WB_02, or Block 2, one of the three blocks available for competitive bidding. The remaining two of the five blocks on offer were expressly for direct negotiations.  Ghana’s Ministry of Energy received 15 applications for Block 2, the highest number for any block. First E&P and its local content partner Elandel Energy (Ghana) Limited were invited for negotiations on the detailed terms of the Petroleum Agreement.

Gas Challenge

First E&P does not have a firmed-up offtake agreement, for the gas being produced in association with the crude oil from the Madu and Anyala fields.

One of the two gas monetization plans we know the company has considered is that Madu and Anyala fields will supply a fifth of the 600MMscf/d targeted for the first phase of the East West Offshore Gas Gathering System promoted by Dangote Industries. The second of the plan is to pipe the gas to some yet-to be firmly defined gas commercialisation project hosted in Chevron operated OML 86. The Dangote gas gathering project is, for now, farfetched. It’s unlikely to be delivered in the next five years. As for OML 86, Chevron is looking to sell the asset, so it is not going to proceed with a gas infrastructure. Africa Oil+Gas Report believes that the associated gas accompanying the crude out of the subsurface is significant.


Aiteo Exploration & Production makes the Number 10 on The Talented Tenth, for largely the same reason it showed up on the list in the last three years: the sheer size of its main hydrocarbon property, the OML 29 (Estimated 2P reserves: 2.2Billion BOE as of 2015), of which it holds 45%, purchased from Shell, TOTAL and ENI in 2015. We have no idea of the reserves estimate currently, but the company has averaged roughly 70,000BOPD from 2016 to 2019. The rapid increase in output, from the 35,000BOPD level when the purchase was completed, to 90,000BOPD reached by early 2017, has halted. Production averaged 70,000BOPD in 2018, and hovered between 65,000 and 85,000BOPD in 2019, with the key challenge being the vandalism of the 97 kilometre Nembe Creek Trunk Line, the crude evacuation facility which Aiteo operates. OPEC+ curtailment is a feature of the year 2020 and it has constrained production at lower than 50,000BOPD for most of the last five months.

Aiteo’s assets were part of Shell’s Eastern Gas Cluster, but the company, despite the huge resources, is not one of Nigeria’s top seven indigenous producers of natural gas.

Waltersmith’s 5,000BOPD First Phase Refinery

If there is any E&P firm that badly needs to increase hydrocarbon output after the pandemic, if only to assure its lenders, it is Aiteo. It has a $2Billion+ debt to restructure and can’t readily access fresh source of funding.

International lenders eye it warily, because of the aura around the company, which comes from its being founded and largely owned by a crude oil and petroleum products dealer who had close ties to the much-vilified former minister of Petroleum, Diezani Alison-Madueke.

Aiteo’s directors; in executive management or otherwise, are not published on its website. The founder’s name and career history are the only items on the site. This is a sort of hint at Maximum rulership.

The company’s charming, personable Managing Director, who is an experienced ex Shell manager, has been quoted in the media as saying that the NCTL pipeline “is a source of comfort to the company’s lenders”. That claim runs contrary to what Africa Oil+Gas Report has heard from some of the lenders, who would prefer not to be named. Their concern is that part of the lender-borrower consent was that Aiteo would ensure considerable uptime of the pipeline so that production would be assured, but the company has not delivered on that.

Just about every E&P company in the world is having a surreal time at the moment. And in Nigeria, the risks are higher than in many petroleum jurisdictions, but the question we ask is can Aiteo continue to deliver, in the way it is currently structured, in the next five years?

This report is a slightly edited version of what was originally published in the December 2020 edition of the monthly Africa Oil+Gas Report, which means that the magazine’s paying subscribers read it six months ago.

ENI and BP to Explore Combining Angolan Interests into New Joint Venture

BP and ENI have entered into a non-binding memorandum of understanding (MoU) to progress detailed discussions on combining their upstream portfolios in Angola, including all their oil, gas and LNG interests in the country.

The companies believe that combining their efforts in a new joint venture company would bring significant opportunities for them to jointly boost future developments and operations in Angola. In particular, it would be expected to generate significant synergies, create more efficient operations, and increase investment and growth in the basin. The new venture would reflect both companies’ commitment to continue developing the upstream sector potential of Angola.

The new company would be supported by Eni and bp, benefitting from the competencies and personnel of each, and would be expected to be self-funded. A business plan for the company would be agreed by bp and Eni to allow it to capture future opportunities in exploration, development and possibly portfolio growth, both in Angola and regionally.

HSE performance, project delivery and production efficiency will be priority areas for the management. The companies’ social investment commitments in the country will continue to be honoured.



BP and ENI have informed the Angolan Government of their intention. Any final transaction will be subject to relevant Governmental, regulatory, and partner approvals.

The companies have appointed advisors that will support the companies in raising finance for the new joint venture. 

ENI is operator of block 15/06, and exploration blocks Cabinda North, Cabinda Centro, 1/14 and soon 28 and is also operator of the New Gas Consortium (NGC). In addition, Eni has a stake in the non-operated blocks 0 (Cabinda), 3/05, 3 / 05A, 14, 14 K / A-IMI, 15 and in Angola LNG.

BP is operator of Blocks 18 and 31 offshore Angola, and has non-operated stakes in blocks 15, 17, 20, and soon 29. bp also has non-operated interests in the NGC and Angola LNG.

Africa Oil+Gas Report’s May 2021 Edition is Out

The Africa Oil+Gas Report has released the May 2021 edition of its monthly magazine and has distributed the e-copies, in pdf format, to its tens of thousand paying subscribers around the globe.

The theme of the current issue is the refining opportunity on the continent, with some of the highlights of the rich, market intelligence filled, 52-page industry trade journal listed below:


  • Africa’s Refining Boom is at Hand
  • Four Countries Close the Gap
  • South Africa Abdicates Leadership
  • Dangote: What Took So Long?
  • Refiners want Crude in Local Currency

A sweeping overview of Africa’s refining landscape is something that AOGR undertakes once every year, even though the ‘Refining Gap’ section is a prominent part of our monthly issues, as well as our website.

But this particular edition is a celebration of an imminent boom in the continent’s hydrocarbon processing activity.

We are not unaware that this is happening in the context of a global energy transition and what some have described as the twilight of the fossil fuel era. So, some can argue: Why the hoorah if Africa is waking up to manufacture gasoline and aviation fuel when the rest of the world is talking about electric vehicles and the growing preference for zoom link over physical conferences?

Our response is that we will celebrate this moment; any morsel of information about Africa’s industrialization, Africa’s beneficiation of its natural rec sources, is an idea we will promote at Africa Oil+Gas Report.

Other highlights of the edition include:


..Of Ghana,



Eq. Guinea,



Nigerian Indies’ Latest Production Update

Angolan Export Numbers, Block by Block


Angola Rig Count, Detailed Activity

Nigeria Rig Count, Detailed Activity

To access the edition, please click here.




South Africa Sprouts New Shoots

In the last five years, several E&P companies, primarily owned by South Africans, have left the upstream market, such that it is tempting to declare the end of the growth of South African E&Pindependents. 

JSE listed SacOil, badly burned by its dealings in Nigeria with local partners Transcorp and NigDel, has turned into a downstream company and changed its name to Efora. 

Thombo Petroleum, owned by Trevor Ridley, former Petroleum Advisor at BHP Billiton, disappeared into the folds of Canadian owned Africa Energy Corp.

But apart from Sasol Exploration and Production International, which is the most visible and best resourced South African bornE&P company, there are a number of companies to consider:

JSE and ASX listed Renergen describes itself as an integrated alternative and renewable energy business that invests in early-tage alternative energy projects.

But it started its project life six years ago by acquiring an onshore natural gas acreage from Molopo South Africa Exploration and Production. Renergen holds the first, and currently only, onshore petroleum production right in South Africa. 

Several homegrown independent South African companies, including Tshipise Energy (Pty) and Sungu Sungu Petroleum, are exploring for natural gas, in coal beds, in the Karoo and offshore Orange Basin, but their distance to development is, at best, far off. 

Renergen is the only one pumping natural gas from subsurface reservoirs into the local market. It has been supplying compressed natural gas to transportation companies since May 2016.

South African National Petroleum Company (formerly PetroSA), the only other natural gas producer in the country, is a state-owned enterprise.

Renergen is working on ramping up production from its acreage, which holds an estimated 142Billion standard cubic feet of proven and probable reserves, near Virginia, about 300km southwest of Johannesburg. It has moved intoliquefied natural gas (LNG) production, “primarily serving the growing domestic heavy duty truck market across Africa and emerging markets”, it says. Renergen has signed an offtake agreement with South African Breweries (SAB) for the supply of liquefied natural gas to power its delivery trucks. For this project, it initially rolled out compressed natural gas to a small fleet of SAB trucks in Gauteng, the country’s major commercial province.

A POTENTIAL STAR IN THE SOUTH AFRICAN E&PFIRMAMENT is Sunbird, a gas explorer and developer which owns a 76% interest in the Ibhubesi Gas Project, Block 2A, offshore of the west coast of South Africa and is the operator of the block. The company was originally owned by Australians, and was sold to South Africans in 2016. The Ibhubesi Gas Project is the country’s largest, undeveloped gas discovery, in the opinion of Sunbird and the local media. Theindependently certified gas reserves are 540 Bcf (2P) with “best estimate” prospectivity of close to 8 Tcf of gas, according to the company. The immediate focus of the project is provision of gas to the Ankerlig Power Station, an 11 year old, 1,338MW capacity thermal plant, designed to be fired by natural gas, but instead, utilizing expensive diesel fuel.Sunbird’s JV partner PetroSA, holds the remaining 24% in Ibhubesi.

Sunbird, for now, remains no more than a potential.

Five years after the Department of Environmental Affairs (DEA) issued an Environmental Authorisation (EA) for the project, the company is not anywhere close to concluding the gas sales negotiations with Eskom, the South African state power utility which owns the Ankerlig power plant. Nor is Sunbird seen to be progressing any deal to sell gas for industrial uses like Renergen is doing.  

TOTAL Boosts Gross Angolan Output With a 40,000BOPD Development

French major TOTAL, has announced the start of production from Zinia Phase 2 short-cycle project, in its prolific Block 17, in deepwater off Angola.

The field is hooked up to the existing Pazflor’s FPSO (Floating Production, Storage and Offloading unit). 

The project includes the drilling of nine wells and is expected to reach a production of 40,000 barrels of oil per day by mid-2022. 

TOTAL operates Block 17 with 38%. Partners include Equinor 22.16%, ExxonMobil 19% and BP 15.84% and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor. 

Gross crude oil volume exported from Block 17 in March 2021 was 10, 455,209 barrels, amounting to 337, 265BOPD, according to Angolan government statistics.

Located in water depths from 600 to 1,200 metres and about 150 kilometres from the Angolan coast, Zinia Phase 2 resources are estimated at 65Million barrels of oil. 



TOTAL said that the project’s entire development “was carried out according to schedule and for a CAPEX more than 10% below budget, representing a saving of $150Million. 

“It involved more than 3Million manhours of work, of which 2 million were performed in Angola, without any incident”.

The Block 17 production license was recently extended until 2045.

Angolan Bid Round for Onshore Leases Starts today, April 30, 2021

Angola’s hydrocarbon industry regulator, the National Agency of Petroleum, Gas and Biofuels (ANPG), as an National Concessionaire, announces, under the terms of Articles 6 and 7 of Presidential Decree No. 86/18, of 2 April, the opening of the Public Tender for the bidding of new oil blocks, namely:
• Terrestrial Basin of the Lower Congo (CON 1, CON 5 and CON 6);
• Terrestrial Kwanza Basin (KON 5, KON 6, KON 8, KON 9, KON 17 and KON 20)

This announcement is located within the scope of the General Strategy for the Attribution of Petroleum Concessions for the period 2019-2025, approved by Presidential Decree no. 52/19, of 18 February
For each of the blocks mentioned above, the proposals to be submitted must comply with the following requirements:

1. Proposals must be submitted in Portuguese or, if in another language, accompanied by an official translation into Portuguese;
2. Proposals must indicate the company’s interest in being an operator or non-operator, as well as the participation it intends to obtain in the block (s) to which it competes;
3. The form of contract to be signed between the National Concessionaire and its Associates, will be the Production Sharing Contract (CPP);
4. The blocks that are the object of bidding are inserted in the maps available on the ANPG portal;
5. Companies, national or foreign, small, medium or large, may compete individually or in consortium;
6. In case of submission of proposals in a consortium, each of the companies that make up the consortium will be evaluated individually for the purposes of their qualification;
7. Companies competing for the position of operator or non-operator must pay a participation fee (Entry Fee) in the amount of $ US 1 000 000,00 (OneMillion United States Dollars) , which grants access the data package for the Lower Congo and Kwanza Terrestrial Basins;
8. The application and proposal submission models reproduced here will be published on the ANPG portal (;
9. Proposals must be delivered by 17:30 (GMT + 1) on 9 June 2021 in a closed and sealed envelope. All proposals submitted after this date will be considered invalid;
10. All proposals must be sent to the following address:

Torres do Carmo Building – Tower II
Rua Lopes de Lima, Municipality of Luanda
Luanda – Republic of Angola
5th Floor
Telephone: 22-64-28550 / 931-793-204
Att .: Hermenegildo Buila, Director of Negotiations at ANPG
Ref .: Proposal – Bidding Round 2020
All proposals will be opened in a Public Act, to be held on June 10, 2021, at a time and place to be announced in due time, in the most popular newspaper in Angola, on the ANPG portal and in at least one international publication of scope worldwide;
11. For the evaluation of the competing companies, the weighting of the proposals will be used, as presented in the attached Terms of Reference, and the evaluation of the technical and financial capacity of the companies will also be taken into account;
12. Pursuant to Presidential Legislative Decree No. 3/12, of 16 March, national companies are only exempt from the payment of the Signature Bonus and Contributions for Social Projects, and must participate, according to their share in the respective Group. Contractor, in the payment of the Contribution for Environmental Protection;
13. Companies covered by Presidential Legislative Decree No. 3/12, of 16 March, which compete as operators must submit proposals for all terms in the tender, including the elements that are exempt from payment, as referred to in the preceding paragraph.

The competing entities that intend to assume the role of non-operator must prove their suitability and financial capacity, by presenting the following information:
a) Your business name or company name;
b) The place of incorporation, registration and the address of its headquarters;
c) The main activities carried out;
d) Detailed information on its equity structure, namely, the values of equity, realizable assets and fixed assets, as well as liabilities payable;
e) Letter of comfort from reputable banking institutions, which pay their financial capacity;
f) The annual reports of the activity carried out, including the balance sheet and accounts for the last 3 (three) years, or since its constitution, if the investing entity was established less than three years ago, audited by an audit entity independent and with proven experience;
g) Detailed information on his experience in oil research and production, including details of reserves and production;
h) The number of employees employed and the professional experience of management personnel in the area of research and production of hydrocarbons;
i) Detailed information on the legal and arbitration disputes that have existed against the company in the last five years (Declaration of Responsibility);
j) Detailed information on advance plans, future obligations, including work programs or risks that may impact on your ability to comply with the work program that is established for the Angolan concessions of which you will be a part;
k) Detailed information on the business activity carried out in Angola until the date of submission of the application (if applicable).
Entities wishing to assume the role of operator must, in addition to presenting the elements referred to in the requirements for non-operator, provide proof of the following requirements:
a) Be the holder of competence and experience in the management and execution of petroleum operations;
b) Have technical and operational competence;
c) Have an efficient organizational structure;
d) Present information that he considers relevant about his experience in the execution of petroleum operations, in order to enhance his candidacy, namely in the fields of safety, environmental protection, prevention of pollution and employment situations, integration and training of Angolan personnel .

The entities must additionally present the following requirements:
a) Demonstrate the respective Quality, Health, Safety and Environment Policy where the commitment to the Prevention of damage to Health, the Prevention of Environmental Pollution, the Protection of Heritage and continuous improvement is evident;
b) Comply with applicable laws and regulations;
c) Demonstrate that its employees have the necessary skills to guarantee compliance with Quality, Health, Safety and Environment aspects;
d) Demonstrate the mechanisms used to assess and manage Quality, Health, Safety and Environment risks;
e) Highlight the use of methodologies that eliminate the causes of non-conformities in order to avoid repetition, and eliminate the causes of potential non-conformities;
f) Demonstrate that it has the competence to implement and maintain Quality, Health, Safety and Environment Management Systems in oil and gas exploration and production operations;
g) To present the methods to be used to control and respond to emergencies and fight spills;
h) Present the Management Indicators of the last six months and the mechanisms to be used to assess the performance of Quality, Health, Safety and Environment.



VAALCO to Replace the ‘Expensive’ FPSO Petróleo Nautipa on Gabon’s Etame Field

US minnow VAALCO is looking to reduce its operating costs on the Etame field, offshore Gabon, by dispensing with the services of Petróleo Nautipathe Floating Production, Storage and Offloading (FPSO) owned and managed by the Norwegian service company BW Offshore.

The operator has announced that it has signed a non-binding letter of intent with the Omni Offshore Terminals Pte Ltd to provide and operate a Floating Storage and Offloading (FSO) unit on the field for up to 11 years.

The one-year contract extension with BW Offshore for PetróleoNautipa expires in September 2022. Gross crude oil output on the Etame field is 17,200BOPD, of which VAALCO holds 31.1% operated interest.

“The Omni FSO proposal could reduce VAALCO’s operating costs by 15% to 25% when compared to the current FPSO contract during the term of the proposed agreement”, VAALCOsays in a release. “Maintaining the current FPSO beyond its current contract or transitioning to a different FPSO would require substantial capital costs”, it adds. “Estimated capital investment of $40 – $50Million gross ($25 – $32Million net to VAALCO) for deployment of the Omni FSO and the required field reconfiguration, with approximately 20% invested in the second half of 2021 and the balance in 2022 with an expected payback of less than three years”.

VAALCO explains that in the new field configuration, the FSOwould store and offload the production and processing would be completed on the existing platforms.

The company is currently forecasting that its capital costs for the FSO and field reconfiguration, as well as its planned 2021/2022 drilling programme, can be funded with cash from operations and cash on hand;

VAALCO and Omni, having agreed to an exclusivity period through June 1, 2021, will engage in further discussions with the intent to finalize a definitive agreement.

VAALCO however says that there is as yet no assurance that itsagreement with Omni will be finalized “and any such agreement will be subject to Board approval by both parties as well as Etame joint-owner and Gabonese government approvals”.

TOTAL Declares Force Majeure on Mozambique LNG Project

Macson Obojemoinmien, in Lagos

French major TOTAL has declared a Force Majeure on the 12.8Million Metric Tonne Per Annum (12.8MMTA) Liquefied Natural Gas (LNG) project in Afungi, in Mozambique’s north easternmost province of Cabo Delgado.

“Considering the evolution of the security situation in the north of the Cabo Delgado province in Mozambique, TOTAL confirms the withdrawal of all Mozambique LNG project personnel from the Afungi site”, the company says in a brifing released Monday, April 26, 2021. “This situation leads TOTAL, as operator of Mozambique LNG project, to declare force majeure”, the company explains.

The Cabo Delgado province has suffered debilitating attacks by Islamic insurgents. The attacks have led to deaths of dozens of people and s displacements of thousands more.

“TOTAL expresses its solidarity with the government and people of Mozambique and wishes that the actions carried out by the government of Mozambique and its regional and international partners will enable the restoration of security and stability in Cabo Delgado province in a sustained manner”, the company says.

“TOTAL E&P Mozambique Area 1 Limitada, a wholly owned subsidiary of Total SE, operates Mozambique LNG with a 26.5% participating interest alongside ENH Rovuma Área Um, S.A. (15%), Mitsui E&P Mozambique Area1 Limited (20%), ONGC Videsh Rovuma Limited (10%), Beas Rovuma Energy Mozambique Limited (10%), BPRL Ventures Mozambique B.V. (10%), and PTTEP Mozambique Area 1 Limited (8.5%)”.


Eunisell Explores Feasibility of Vendor Funded Early Production Facility for Barracuda Field

Eunisell Limited, the Nigerian owned provider of oilfield services and facilities, has entered into a non-binding collaboration agreement (CA) with ADM Energy, an upstream E&P company.

Under the terms of the CA, subject to the completion of certain due diligence, ADM and Eunisell will explore collaboration opportunities to carry out development of Barracuda Field in OML 141 and associated work-related activity in Nigeria.  It is the intention of both parties, together with the risk sharing consortium in respect of Barracuda Field, that a formal agreement will be entered into in advance of any work commencing.

The CA may be terminated by mutual consent.

“Eunisell has decades of experience in engineering, production, operations and enhanced production techniques within Nigeria and the Parties intend to work together to use their combined experience to accelerate production of oil and gas assets, initially concentrating initiating production at the Barracuda field in which ADM recently invested”, a press release stated.  “Activities under the intended scope of work may include early production facility supply, procurement, construction and commissioning of production facilities, extended well testing and laboratory services”.

Following discussions, Eunisell may consider providing vendor financing to achieve the scope of work to be agreed, subject to terms and conditions to be determined at the point of an award of contract.

Eunisell has been a key facilitator for the Nigerian oil and gas marketplace for many years, helping operators to reach their production goals faster and at less capital costs. We look forward to building a relationship and are excited by the potential of working alongside them to support the development of our investments such as the Barracuda Field in OML 141.”



ENI’s New Angolan Find to Push Net Output Beyond 115,000BOEPD

By Sully Manope

ENI’s new discovery of oil in Cuica-1 in Angola’s CabaçaDevelopment Area in Block 15/06 takes the Italian player on course of topping up its 100,000Barrels of Oil Per Day (BOPD) net in the country.

The well-head location, intentionally placed close to the Armada Olombendo FPSO East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production, thus immediately creating value while extending the FPSO production plateau. It is expected that production will start within six months after discovery.

Cuica-1 encountered 80 metres total column of reservoir of light oil (38°API) in Miocene sandstones located in in a water depth of 500 metres, ENI says that this discovery translates to a size estimated between 200 and 250Million barrels of oil in place.

The company net 100,000BOPD (crude oil alone) in total export volume from Blocks O, 3/05. 3/05A, 14, 15 and 15/06 in February 2021, according to the Angolan regulatory agency, ANPG

The New Field Well (NFW) has been drilled as a deviated well by the Libongos drillship and reached a total vertical depth of 4100 metres, good petrophysical properties. The discovery well is going to be sidetracked updip to be placed in an optimal position as a producer well. “The result of the intensive data collection indicates an expected production capacity of around 10,000 barrels of oil per day”, ENI says in a statement.

“Cuica is the second significant oil discovery inside the existing Cabaça Development Area and confirms the Block 15/06 Joint Venture’s commitment to leverage the favorable legal framework on additional exploration activities within existing Development Areas, as promoted through the Presidential Legislative Decree No. 5/18 of 18 May 2018”, the company said.

“Pursuant to the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the re-launch of the exploration campaign post-2020 COVID-19 pandemic and the drop of oil price”. A three-year extension of the exploration period of Block 15/06 has been recently granted until November 2023.


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