Canadian independent ReconAfrica has reported a successful flow of natural gas and “potential liquids” to surface from two separate zones in the Kavango West 1X (KW1X) discovery well in the onshore Kavango Basin in North east Namibia
The upper Huttenberg flowed natural gas and potential liquid content to surface, the same way the Upper Elandshoek flowed hydrocarbons to surface earlier
The company says that Vertical production testing at KW1X is now complete; and, Huttenberg formation has been prioritized for an open-hole horizontal production test, targeting up to 1,000 metres of horizontal section.
The uppermost zone of the Huttenberg formation flowed natural gas and potential liquid content to surface immediately upon perforation, ahead of any acid stimulation, and was flared through the relief flare stack. Flow rates were not measured from the Huttenberg due to equipment limitations, which has been rectified for the upcoming open hole horizontal production test by way of procuring the necessary equipment, which is currently being shipped to site, and by changing the surface operations service provider at site. Production samples, including both natural gas and potential liquid content have been collected in several IsoTubes with results of the compositional analysis expected in the coming weeks from samples sent to laboratories in the United States.
This test result completes vertical production testing operations at KW1X. Surface testing equipment associated with the vertical programme has been stood down and demobilized as the Company advances to Open-Hole Horizontal Production Test
Having flowed natural gas and potentially liquids to surface from two separate zones at KW1X, the next stage of success-based testing is to proceed with an open-hole horizontal production test in the uppermost zone of the Huttenberg formation, with an option for an additional horizontal test in the uppermost zone of the Elandshoek formation.
The Huttenberg formation was selected for the initial horizontal test based on:
Flow of natural gas and potential liquids to surface;
75 metres of pay identified from original well log analysis;
Presence of matrix porosity between large natural fractures;
Longer horizontal lateral section due to being approximately 600 metres shallower than the Elandshoek;
The Jarvie-1 rig is expected to drill up to 1,000 metres of horizontal section through the Huttenberg formation.
Brian Reinsborough, ReconAfrica’s President and CEO, says the company has a high level of confidence moving forward with an open-hole horizontal production test in the Huttenberg formation.
“ KW1X’s well results do not just validate a single structure; it also opens running room across the block. We have mapped 22 structures using existing seismic data and anticipate the inventory could grow with additional seismic coverage on PEL 73. Confirming the KW1X results with a flow rate test on a horizontal sidetrack as soon as possible will ultimately support resource and reserve bookings and a final investment decision on this emerging Damara Fold Belt Play.”
From Vertical to Horizontal: The Path Forward
ReconAfrica explains that the purpose of the vertical production testing programme was to determine which parts of the reservoir, if any, could flow hydrocarbons to surface.
“It was not to determine flow rate as cased vertical wells are not the optimized development design for this fractured reservoir. Phase one production testing achieved a critical milestone; the programme established two of the six zones of interest identified in the well contain hydrocarbons capable of flowing to surface. This does not preclude the other sections from flowing hydrocarbons via a more optimized horizontal open hole completion.
“The next step, an open-hole horizontal production test in the upper Huttenberg zone, is designed to establish a representative flow rate over a large, exposed reservoir section uninhibited by production casing, cement and perforations. An open-hole horizontal well is required to achieve maximum reservoir penetration and optimal fracture intersection, consistent with the natural fracture orientation observed in the reservoir. Horizontal development of the Damara Fold Belt structures is also expected to reduce surface land disturbance as well as the number of wells required per structure, resulting in lower field development costs and improved capital efficiency.
“Formation imaging log (FMI) analysis from wells drilled through the Otavi reservoir indicates fracture density ranging from 1.0 to 12.7 fractures per metre (P90–P10), with fracture orientation running parallel to the fold structure. The current well design contemplates a horizontal lateral of up to 1,000 metres to optimally intersect these natural fracture swarms. Completing the well open hole, without casing or cement, is intended to maximize flow from fractures. These fractures have inclinations of 50-90 degrees, with most fractures being vertical, to near vertical. The horizontal well will be drilled perpendicular to the fracture orientation. Open fractures in analogue carbonate fields enhance permeability and often link matrix porosity with the reservoirs”.
A Critical Assessment of Promise, Pitfalls, and the Imperative of Substance Over Strategy
Background and Context
On March 13, 2026, President Bola Tinubu announced the Presidential Petroleum Reform & Value Optimisation Taskforce — a nine-member body chaired by Fola Adeola, co-founder of Guaranty Trust Bank, tasked with producing three reform blueprints within six months. The announcement arrives at a particularly fraught moment. Nigeria averaged just 1.46Million barrels per day (BOPD) in 2025, some 500,000 BOPD below its own budget target of 2.06MMBOPD, generating a revenue shortfall exceeding $6.8Billion in the first eight months of the year alone. By January 2026, crude output had slipped further to 1.31MMBOPD — a 190,000BOPD deficit against Nigeria’s OPEC allocation.
These are not marginal misses. They reflect a structural and governance failure playing out against a backdrop of acute institutional turbulence. In April 2025, President Tinubu sacked the entire NNPC board, replacing Group CEO Mele Kyari with Bayo Ojulari, former Managing Director of SNEPCO, the UK major Shell’s deepwater subsidiary in Nigeria. A widely circulated industry fable captured the deeper dysfunction: an “Energy Whisperer” — a well-positioned presidential adviser — allegedly meddled in NNPC’s operational turf while the Chief Barrel Keeper (the GCEO) watched helplessly as committees replaced drilling plans. Meanwhile, the Attorney-General of the Federation communicated sweeping PIA amendments that would merge NUPRC’s regulatory role with that of a commercial operator, vest all NNPC shares in the Ministry of Finance Incorporated (MOFI), and make the NNPC board subordinate to shareholder directives — changes that drew sharp warnings of re-politicisation and investor flight. It is against this combustible backdrop of turf wars, legislative overreach, and chronic underproduction that the new Taskforce must be assessed.
The Taskforce Membership: Credibility and Composition
The membership profile is the taskforce’s most credible feature. Fola Adeola brings the financial rigour of a co-founder who built GTBank into one of Africa’s most admired institutions. Ademola Adeyemi-Bero, founder and CEO of First Exploration & Petroleum Development Company (First E&P), provides 38 years of upstream operating experience — precisely the operational intelligence that previous reform committees have lacked. Osagie Okunbor, former Chairman of Shell Companies in Nigeria, adds the perspective of someone who navigated the structural challenges of Niger Delta operations and Shell’s onshore divestment process. Abubakar Suleiman, CEO of Sterling Bank, contributes capital markets expertise directly relevant to the liquidity unlocking mandate. What is perhaps most notable is what the composition avoids: career civil servants, political surrogates, and the consultants whose PowerPoint slides have long substituted for policy in Abuja.
The Case For: Arguments in the Taskforce’s Favour
Coordination Amid Structural Chaos
The fable’s core insight— that the sector is drowning in competing directives and overlapping committees — is grounded in reality. The proposed PIA amendments reveal different arms of the executive pulling in contradictory directions simultaneously: one seeking to commercialise NNPC, another to re-politicise it under MOFI, a third allegedly intervening in GCEO-level decisions. The presidential directive that all existing committees align under the taskforce is, at minimum, an attempt to impose a single coherent architecture on this dysfunction.
Technical Focus and a Credible Capital Mandate
The explicit framing as a “technical reform body rather than a representative committee” matters. Nigeria’s reform history is littered with committees whose compositions were dictated by geopolitical balance rather than expertise — the PIA took two decades to pass partly for this reason. A leaner, technically constituted body reporting monthly to the President, with an interim report at three months and final outputs at six, carries a more credible accountability structure. Its Capital & Liquidity Acceleration Blueprint, targeting $5-10Billion in sectoral liquidity, is the most consequential deliverable: the administration has already attracted $17Billion in new investments since 2023, and a 50-block licensing round was held at year-end 2025. The taskforce could provide the regulatory scaffolding and near term operational guidelines needed to convert signed commitments into near term barrels — the most important metric for an oil producing nation.
The Case Against: Structural and Systemic Risks
Another Committee in a Sector Drowning in Them
Barrels do not emerge from strategy documents or roundtables — they emerge from well- work, maintenance, and operational discipline. Nigeria’s 2025 production shortfall was driven by infrastructure bottlenecks, security challenges, regulatory approval delays, and underinvestment in infill drilling. None of these yield to a six-month blueprint. The risk is that the taskforce becomes another procedural layer substituting for the hard work of actually lifting crude.
The Implementation Gap
Nigeria’s reform history is a history of reports filed and forgotten. The PIA — signed after two decades — has already faced contested, politically driven amendment attempts by the very administration that inherited it. A taskforce that dissolves upon final report submission has no institutional stake in execution. Its blueprints will be only as durable as the political will to implement them, which has historically evaporated the moment the next crisis demands attention.
Governance Contradictions and Scope Overreach
The AGF’s proposed amendments — merging NUPRC’s regulatory and commercial roles, subordinating the NNPC board to MOFI — represent precisely the re-politicisation the PIA was designed to prevent. The taskforce must navigate this contradiction without alienating the executive branches that created it or the investors it needs to attract. It is also, in practice, a parallel policymaking structure operating alongside the Ministry of Petroleum, NNPC, NUPRC, and the Special Adviser on Energy. The Energy Whisperer did not lack a mandate — the problem was accountability. The taskforce risks the same outcome if these political exposures go unmanaged.
The Operational Depth Gap
The taskforce’s membership skews toward banking, entrepreneurship, and high-level energy management rather than field-level petroleum engineering. Nigeria’s production crisis is fundamentally operational: ageing infrastructure, deferred maintenance, suboptimal reservoir management, and underfunded well-work programmes. The reforms most likely to move the needle — accelerated well interventions, fast-tracked JV cash call resolutions, creative financing mechanism, security-enabled field access — require subsurface technical expertise that is currently underrepresented in the group.
Recommendation: Shore Up the Taskforce with Operational Firepower
The most urgent gap to close is upstream operational depth. An authoritative September 2025 op-ed I wrote in Africa Oil+Gas Report, argued that Nigeria’s incremental barrels are hiding in plain sight — not in new licensing rounds or sweeping OML-level divestments, but in disciplined, field-level execution on assets that already exist. The evidence is compelling: First E&P’s phased development of OMLs 83-85 and Elcrest’s transformation of OML 40 from 3,000 to over 30,000 BOPD both succeeded through technically rigorous, field-specific strategies. A government committee that proposed NNPC divest a minimum 25% equity stake in select Joint Ventures at the OML level — without specifying how production growth would follow — missed this lesson entirely.
Ademola Adeyemi-Bero — founder of First E&P, the very company that exemplifies field- level execution — is the taskforce’s single greatest operational asset. But one experienced operator cannot serve as the sole technical engine of a body tasked with restructuring an entire sector. He needs to be backed.
The taskforce should be formally augmented with a dedicated Technical Working SubGroup comprising reservoir engineers, well intervention specialists, production technologists, and field development planners drawn from both the NNPC system and the independent operator community. This sub-group should focus exclusively on the zero-to- eighteen-month production recovery horizon. Its first task should be an independent review of NNPC’s Project Fit for Purpose — the corporation’s own well remediation and field management programme — stress-tested against a granular well-by-well, reservoir- by-reservoir assessment of production candidates across the NNPC Joint Venture and NEPL-controlled asset base. That level of technical granularity is the only credible basis on which the Capital & Liquidity Acceleration Blueprint can distinguish between capital that generates incremental barrels and capital that generates incremental bureaucracy.
The Implementation Toolkit for Immediate Structural Fixes should include a dedicated work stream mapping the regulatory, financial, and contractual bottlenecks — cash call arrears, slow work programme approvals, JV partner disputes — that routinely defer well interventions that are technically ready to execute. On the divestment architecture, the taskforce should favour a field-level farm-down model anchored on clustering fields around defined 2P reserves thresholds over OML-level equity sales. This approach aligns investor incentives with production growth rather than mere ownership transfer, and it is the architecture validated by Nigeria’s most successful indigenous operators. The recent security improvements across the Niger Delta represent a narrowing window: exploiting them requires a queue of execution-ready subsurface work programmes, not another round of feasibility studies. With proper operational backing working alongside Adeyemi- Bero, the taskforce is the right instrument to build and validate that queue.
Conclusion: Strategy Without Substance is the Enemy
The Presidential Petroleum Reform & Value Optimisation Taskforce is, in conception, better designed than most of its predecessors. Its membership has genuine credibility. Its mandate is time-bound. Its framing as a technical rather than representative body is structurally sound. And the urgency that animates it — a sector losing billions in unrealised revenue while targets slip year after year — is not manufactured.
But the fable’s moral — that in a land where strategy replaces substance, the ground may be full of oil while the treasury runs on empty — is a warning the taskforce must take seriously. The six-month clock is running. The Energy Whisperer’s playbook of endless frameworks and glossy blueprints is precisely what this initiative was established to supersede. The difference between this taskforce and every committee that came before it will not be determined by the quality of its reports. It will be determined by whether those reports translate, within a politically volatile environment, into barrels actually lifted and revenues actually remitted.
For that to happen, the President must do something historically difficult: insulate the taskforce from the governance pressures — ministerial interference, turf wars, and premature legislative rewriting — that have undermined every prior reform effort. The Chief Barrel Keeper’s plea remains the right one. Let the work be done. The Taskforce’s job is to remove the obstacles. Whether it can do so, in six months, against the full weight of Nigerian institutional inertia, is the only question that ultimately matters.
“Barrels do not emerge from strategy documents or roundtables — they emerge from well- work, maintenance, and operational discipline. Nigeria’s 2025 production shortfall was driven by infrastructure bottlenecks, security challenges, regulatory approval delays, and underinvestment in infill drilling. None of these yield to a six-month blueprint. The risk is that the taskforce becomes another procedural layer substituting for the hard work of actually lifting crude.”
Sources: State House Press Release (March 13, 2026); Petroleum Industry (Amendment) Bill, 2025; PIA Amendment Industry Commentary; NUPRCProduction Data 2025-2026; Punch, Vanguard, OilPrice.com, EcoPrn Agency; DimejiBassir, “Finding Nigeria’s Elusive Incremental Oil Barrels, “Africa Oil+Gas Report, September24, 2025.
Dimeji Bassir, Managing Director of Ofserv, is a value-driven executive with 25+ years of operational, consulting and commercial experience across multiple verticals in the global (USA, Africa, Europe) energy industry. Previous roles include Country Manager, Nigeria at GE Oilfield Technology (2008 – 2010). He is a frequent contributor to Africa Oil+Gas Report.
The Nigerian Content Development and Monitoring Board (NCDMB) will have the power to enter into financial partnerships with public and private institutions, among other new regulatory functions, if the law setting up the institution is amended in the current form being presented at the National Assembly.
The bill before the House of Representatives, the lower chamber in Nigeria’s bicameral legislature, will repeal the Nigerian Oil and Gas Industry Content Development Act, 2010, and enact a ‘Nigerian Oil and Gas Industry Content Development Act’, “that will among other things cure defects observed in the existing Act”, in its place.
Central to the proposed amendment is the enhancement of the authority and capacities of the Nigerian Content Development and Monitoring Board (NCDMB).
The bill gives approval to the Board to participate in equity investments and allocate twenty percent of the money received in the Nigerian Content Development Fund to be used to defray administrative expenses. “This is also an innovative provision as there is no such provision in the existing NOGICD Act. and others”, according to a statement signed by Director/Committee Clerk of the House Committee on Nigerian Content Development and Monitoring Board of Nigeria’s National Assembly.
The bill also seeks to provide statutory approval for existing funds managed by the NCDMB, including the Nigerian Content Intervention Fund (NCI), NCDMB Research and Development Fund, Working Capital and Capacity Building Fund, Women in Oil and Gas Fund Bank, and NOGAPS Manufacturing Fund that the Board presently established and had been operating on.
In a bid to streamline and monitor project approval processes, the bill prescribes strict timelines for the NCDMB to approve or disapprove projects and programmes for industry operators and contractors. This measure aims to introduce a limitation on contract cycles and unnecessary delays to improve efficiency and give statutory backing to the agreement reached among the Board, Nigerian National Petroleum Corporation Limited (NNPCL) and International Oil Companies (IOCs) on limitation of contract cycle in the Nigerian Oil and Gas Industry.
In terms of enforcement, the proposed legislation grants the NCDMB prosecutorial powers to address criminal offenses outlined in the bill.
Moreover, it empowers the Board to impose administrative sanctions for non-criminal violations, providing a comprehensive mechanism for regulatory oversight. The Bill further provides for active encouragement of backward and forward linkages in the oil and gas Industry.
On February 9, 2024, the House of Representatives passed the bill for the second reading and has since referred it to the Committee on Nigerian Content Development and Monitoring Board for further review.
The Committee expects industry stakeholders to submit, by March 18, 2024, a Memorandum which should be fifteen (15) hard copies and a soft copy to: The Clerk, House Committee on Nigerian Content Development and Monitoring, Room 413, 4th Floor, White House, House of Representatives, National Assembly Complex, Three Arms Zone,
Abuja. A date for the Public Hearing shall is expected to be communicated in due course
The just concluded court battle between Cross River and Akwa Ibom States rewrites the Eritrean war of independence in small letters.
Cross River was praying Nigeria’s highest court to confer on it the status of a littoral state. It wanted to be defined-even if not by geography-as a state bounded by the Atlantic Ocean to the south. The verbal court arguments, in a democratic jurisdiction, echoed the claims of angry roar of Ethiopian fighter jets pounding Eritrean territory for thirty years: “the coastline is ours!”
The Ethiopians lost the red sea in spite of their mighty army. The Cross Riverians lost the Atlantic in spite of their sparkling brand name.
For, like it or not, Cross River is a bigger brand than Akwa Ibom.
Cross River State used to encompass what are now both Cross River and Akwa Ibom states.
Calabar, the state capital, is a niche town which, as far back as the 16th Century, has been a recognized international sea port, shipping out goods such as palm oil. Today it hosts one of the largest street carnivals on the continent. On the contrary, Uyo, the capital of oil rich Akwa Ibom State, stubbornly remains a small, sleepy town, while Calabar is its more boisterous neighbour across the river.
The trickster god of Geology probably helped in deceiving Cross River into believing it was entitled to some chunk of the proceeds that its neighbour was getting. The sediments that created the reservoirs in which the oil pools of Akwa Ibom State are trapped were deposited by the Cross River, for which the resource-poor state is named. The Cross River system is responsible for perhaps the most prolific segment of the Niger Delta basin; four companies, namely ExxonMobil, TOTAL, NPDC and Addax, produce over 1Million barrels of Oil per day in the south east offshore corner of the Niger Delta which is, really, roughly one tenth of the basin. That same south east corner, we must acknowledge, is where the main oil production in Equatorial Guinea and Cameroon comes from. The same petroleum system spawned what has so far been discovered in the Joint Development Zone (JDZ)between Nigeria and Sao Tome et Principe(STP).
But Geology is not a respecter of political boundaries. That is why countries which share boundaries with hydrocarbon rich countries are, quite often, resource poor themselves and they are always complaining they have been cheated.
Somali and Kenya never had a public spat over boundaries until recently, when Kenya became a magnet for exploration companies and encountered its first commercial pool of oil. Now the two sides are bickering.
The Somali government, ordinarily concerned with keeping terrorists at bay in its war weary cities, now has a new cause to fight. It accuses Kenya of awarding offshore oil and gas blocks illegally to TOTAL and ENI, French and Italian oil majors respectively, claiming that the blocks lie in Somali waters. Just a few days before the Supreme Court in Nigeria ruled that Cross River was not a littoral state, Somali deputy energy minister Abdullahi Dool claimed that L21, 22, 23, and 24, the four deepwater blocks awarded to TOTAL and Eni, were invalid and that his country would take the matter to the United Nations.
Kenya has so far rejected the Somali claims to the area. Although the two countries signed a memorandum of understanding in 2009, which stated that the border should run east along the line of latitude, Somalia rejected the agreement. The contention between Kenya and Somalia is about acreages in the Lamu Basin, right in the Indian Ocean, the vast seaway which bounds the African continent in the east. In these same waters, International Oil Companies have, within two years discovered-by their own submission-over 100Trillion Cubic feet of gas, more than half of Nigeria’s gas reserves, off Mozambique and Tanzania.
And, this is the point about “the trickster god of geology” again: the discoveries in Tanzania have been a fraction of the finds in Mozambique, even though the assets in question lie in the same Ruvuma Basin and the acreages are quite close to one another.
Tanzania has vowed to get as lucky as Mozambique and is planning a bid round to award acreages which has “similar geologic features to the richly endowed tracts of Mozambique”.
Democratic Republic of Congo is battling two oil rich neighbours to the east and west. Some of the most prospective, but undrilled structures in the DRC lie along the same trend in the Albertine basin as the reservoirs where Tullow Oil has reported estimates of a billion barrels of oil in several fields in Uganda. Congolese and Ugandan troops have clashed several times in this area. In Uganda’s Hoima district, Heritage, the London listed operator, constructed a school in memory of Carl Nedft, the British geologist who was slain in a pre-dawn raid on workers by Congolese troops in August 2007.
To the west, DRC has long accused Angola of “stealing” oil from offshore wells near its coast–thought to be a reference to operations in the Cabinda enclave, which is surrounded by DRCongo and Congo Brazaville. “In early 2010, Angola’s National Assembly agreed to open talks with the DRCongo on the extension of its border out to 350 nautical miles, rather than 200 miles, as a prelude to an application to the UN for recognition of that boundary. Relations between the countries deteriorated sharply in 2011 after a series of disputes” says the World Markets Research report. A report in a July 2012 edition of Journal De Angola notes that the Angolan Cabinet in Luanda “analysed a number of treaties between Angola and Congo on joint exploration of oil in the Lianzi development area concerning the share of revenues, customs and migratory matters”. It may be a way of saying that the issues were finally getting to resolution.
The clash between Sudan and South Sudan has shown that the more battle hardened the neighbours are, however, the more difficult it is to reach a solution around boundaries. In January 2012, Salva Kiir, the president of South Sudan, took the decision to shut down oil producing facilities and thus cut off revenue to both Sudan and his own government. It’s an unusual course of action for an African head of state. When South Sudan became independent of Sudan in July 2011, it inherited over 90% of the crude oil reserves and production which were, until 2005, entirely under the control of Khartoum. Even though most of the fields are located in South Sudan, the processing, storage and evacuation facilities are sited in Sudan and revenues from these resources had been shared equally in the seven years since the signing of the Comprehensive Peace Agreement that granted autonomy to the South. Now that South Sudan “owned” most of the oil, the major revenue accruable to Sudan was transport tariff charges. Sudan was demanding tariff as high as $35 per barrel, which South Sudan was unprepared to pay. Sudan was also making claim to some boundary areas that the South insists were part of its territory. In April 2012, Kirr sent forces to one such border town named Panthou(by the Dinkas of South Sudan) and Heglig(by Arab Sudanese).
Cote D’Ivoire had been producing more oil than Ghana had ever hoped to produce since the early 90s. But the discovery of the600Million barrel Jubilee field off Ghana in 2007, has sparked renewed exploration interest in the so-called “transform margin” of the Gulf Of Guinea, where offshore Ghana and Cote d’Ivoire are located. In 2011, the Ivorian authorities–at the time still under the helm of former president Laurent Gbagbo–published a map with a new border, taking in several Ghanaian oil blocks. The situation caused a stir in Ghana, as the proposed border came dangerously close to the Jubilee oilfield and recent oil and gas discoveries such as Tullow’s Tweneboa and Enyenra complex. However, the governments have enjoyed cordial relations for a long time and are keen to solve the matter peacefully.
The one African leader who has dealt upfront with the issue of hydrocarbon prone maritime boundaries has been Olusegun Obasanjo, former president of Nigeria. He “settled” disputes, which had long lingered before his tenure, with Equatorial Guinea, Sao Tome et Principe and Cameroon. And his solutions were such that Nigeria, playing the big brother, gave out more territory to these less endowed neighbours. In coming to a resolution with Equatorial Guinea, Nigeria surrendered a chunk of the Zafiro field, which currently produces 140,000Barrels of Oil Per Day. And it was in the process of giving up the Bakassi Peninsula that Cross River lost “its coastline”. But in going to court to get an alternative to its probable loss of oil revenue accruing from Bakassi, Cross River could have asked itself: how much oil, really is in that peninsula? The answer, really, is, not much, if any. Cameroon itself, in total, is producing just 60,000BOPD. And if indeed, there was some commercial pool of hydrocarbon in Bakassi, it would most likely have made Cross River the least endowed of the fringe Niger Delta states, like Edo, Ondo Imo and Abia.
This piece was originally published in the March 2012 edition Africa Oil+Gas Report. No, it has not been updated
In 1994, South Africa’s first year of fully democratic elections, the Africa Oil Week (AOW) began in Cape Town, the country’s widely acclaimed ‘mother city’.
Christened ‘Africa Upstream’, at the time, the Conference was inaugurated in Camps Bay, “a beautiful locale over the towering Cape peaks, facing the ever cold Atlantic”, reports Duncan Clarke, the AOW’s founder, in his memoir Three Decades in the Long Grass: The story of Global Pacific & Partners. “No facility existed and we used a huge marquee to accommodate the 300 delegates”, the Zimbabwe born Clarke notes in the book. Clarke enlisted Alec Erwin, “an old friend and minister in Mandela’s cabinet, who had gone to school in Umtali (Mutare), in [then] Rhodesia to give the opening address”.
The second edition of the conference was held in Johannesburg, “unwisely persuaded that this, the heart of sub-Saharan Africa’s economy, would prove a more fertile ground. It didn’t, and the location of the conference in Midrand was a near disaster of logistics and on-site management. Never again, we vowed, so we moved back to the Cape to find the IMAX BMW Centre as our next venue-and for the next 17 years to follow-initially taking a smaller room than the main theatre for the conference meeting”.
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By 2013, the conference had been renamed Africa Oil Week (AOW).
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I’d pause here to scan across the continent to focus on the emergence of NJ Ayuk, a gutsy, charismatic, Cameroonian born, US trained lawyer.
I met NJ Ayuk in 2015, in the company of Thabo Kgogo, then CEO of the JSE listed, South African independent SacOil, at the Cubana bar and restaurant, an upmarket lounge in Cape Town, which was a sundowner favourite hangout of the AOW crowd. At the time, I had watched Ayuk from a distance with a large dose of respect mixed with curiosity and a lot of questions. His Centurion Law firm seemed so unutterably successful for a company headquartered in Equatorial Guinea. It wasn’t lost on me that, even while located in such a back water part of the continent, it was loudly touting Pan African credentials.
How did the Africa Energy Week, created by Ayuk’s Energy Capital & Power and African Energy Chamber, manage to wrestle down the wrestle down the “gigantic” AOW, which no longer has Duncan Clarke at the helm, but being managed by the Hyve Group?
CHIKEZIE NWOSU will retire as Managing Director/Chief Executive Officer, Waltersmith Petroman in the next three months. Which makes this second part of Africa Oil+Gas Report’s interview with him a valedictory feature. He talks about the company’s upstream business; its asset in Equatorial Guinea, as well as host community, human capacity development and “the future” issues, including the planned investment in renewables.
Waltersmith is an influential player in the African Exploration & Production sector. EXCERPTS by Akpelu Paul Kelechi….
Waltersmith dropped its acquisition in Uganda and later took up assets in Equatorial Guinea. What’s the update on the award?
In 2019 we bid with many other international companies for the EG-Ronda 2019. We put in the most competitive bid for Block EG 23, which is an offshore block roughly about 70 metres of water depth and with significant oil and gas reserves. There are discoveries there, they just have never been developed to be put in production, but they’ve been tested so these are not exploration type blocks. We negotiated a production sharing contract (PSC) with the Government, and we have signed off on our own-in February 2020- and they told us it was going to go through their legal process. Unfortunately, both COVID and some internal processes within Equatorial Guinea meant that they have not yet signed. Now at the launching of the NNPC Limited, the (then) Minister for Mines and Hydrocarbons honorable Gabriel Obiang Lima was there and we again reminded him of the fact that we were still anxiously waiting. And they actually sent us a letter indicating that we are still on track and that once they go to the processes, they would sign the PSC and return it to us. We intend to set up an office, which would be our first International office, in Equatorial Guinea.
So, you see, these things take time. We earlier talked about negotiation with the Nigerian government for Assa and OML 20 taking about four and a half years. Now we are talking about Equatorial Guinea having taken three years or there about, and we’re still there.
Did you participate in this just completed 2020 marginal field bid round?
Yes we did.
Did you get any field?
No we didn’t.
You want to tell us your story behind it?
There is no story behind it. We put in what we think was one of the best technical bids as we usually do and we couldn’t have won block EG 23 in Equatorial Guinea against other international companies if we didn’t know what we’re doing, yeah? We put in the best Technical and Commercial bid that we thought there was and we’re not going to pay anybody any ridiculous signature bonuses because for us, the value from royalties and taxes to the Nigerian government for early development, if you don’t hamper people’s development through paying huge signature bonuses, is much more than any upfront signature bonus. I can almost tell you that in a field where you have about let’s say 20Million barrels of Reserves, even if you do a conservative $50 per barrel, if you do your calculations well, that’s a significant revenue. And then from there, you pay a significant amount up front of the revenue if you manage to sell it for royalty. Then you take away your costs; we are a very cost-efficient company and then you pay taxes which are significant as well. Those monies cumulated together are much more than any signature bonus. But if you hamper those assets with a huge signature bonus, then those companies will pay a signature bonus but will be unable to develop the field very quickly. Which means that the federal government will lose early revenue from the field. The logical thing to do is bring down the signature bonuses and go to people who are technically and commercially proficient and have the funding to quickly develop and deliver these Fields. That’s what we thought we were. That’s what they thought we weren’t.
Waltersmith now has three arms, your upstream arm, midstream arm and your downstream arm. Is there any point where all these arms coalesce in your host Community relationships? Or are they separate?
We have to deal with the different companies at arm’s length because they have different boards. But all the energy components report in to me and we keep our transactions at arm’s length. The refinery pays the commercial rate for the oil coming from the upstream part of the business. The gas-to-power pays for gas at the commercial rate and then delivers the power at a commercial rate to the refinery and flow station at this moment and we will continue to do that. How do we deal with the communities?
Whatever China has as a competitive advantage, Nigeria can provide it as well. We started working with some parties to see whether we can start solar PV manufacturing in the industrial park
At the moment, we have Global Memorandum of Understanding (GMoUs) tailored towards Waltersmith as a group not as individual companies. When we invested in the refinery, we adjusted the value of our GMoU along the principles we agreed with communities that for any new projects of XX size, we’re going to increase the GMoU funding by a certain amount of money and that’s what we keep doing. With the refinery we increased it, with the gas business that will also happen. In terms of what we do in the communities and what we’re also trying to change. Human Capital Development HCD is one of the most critical ones for me because it’s not about just building hospitals or building schools because everybody does that. The quality has to be right and then putting utilities in place, like water, electricity is still a challenge and we’re trying to address it together with the other companies in the same operational area and providing good roads. We want to provide good paying jobs and so we started a technical skills acquisition programme. Now using our HCD part of our project, we identified 200 graduates from the community who had graduated but were not industry ready. We have to prepare them for the industry. From the first batch, there were 50 applicants but only 47 attended. And out of that 47 we have hired 12 formally as staff of Waltersmith into our operations, both the refinery and the flow station and three more are there on a contract basis. So, 15 altogether. We expect that as our project grows, for example our trailer park, we want to hire a few more people from that programme into the trailer park and we also have certified them in such a way that other companies there can also look to hiring them for some of their operations. We’re trying to encourage all our other counterpart companies there to look at these communities and hire from them because the disadvantage these communities have is the fact that, if you open up the competition for those kind of positions to everybody in the country or even in the state, the communities will probably lose out. Okay, so we have a different programme that is for all Nigerians and that is our Graduate Intensive Programme and then we have a specific programme for the communities which is our technical skills, acquisition programme.
It is not about these artisanal skills, like welding and all those things. It’s about operations, maintenance and those kind of skill sets that we are hiring graduates into our operations for. And that to a large extent has brought a lot of better relationship between ourselves and the youth in the community. And as we expand into Assa field, we will continue with the same thing. We’re going to run the programme in 2023 as well with another batch of about 50.
And we’re going to deploy some of these people who we are training but who we cannot hire directly, into being the supervisors of the project we deliver. Because sometimes we are delivering projects in the communities and the supervision is poor, but if they have their own graduates who have come through our training programme and understand projects, civil engineering work projects and things like that, they can supervise Market store buildings, Hospital buildings and the like and hopefully going forward, as we build more hospitals and schools, we can then start training teachers, and medical personnel who would man some of these facilities as well. So human capital development is an integral part and a critical part of our delivering projects to the community.
Now things are going to change a little bit with the host community regulations. And Waltersmith is one of the first to try and get its entire documents ready and submitted to the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) for that purpose. We’ve already started identifying some of the people that will from the Committees from the community itself so that will transit from the GMoUs into this, host Community bill.
In terms of spend, are you necessarily spending more or less? You know, you can have this very robust programme but in terms of spend, it can be much lower than what the Host Community Fund in the Petroleum Industry Act mandates you to spend.
I think you said you know me by reputation.
Oh, yes I do.
Then you know that my business ethics are right at the top. So let me explain coming from Shell. Sometimes at Shell, 2% of the CAPEX, before the Nigerian Content started, 2% of the CAPEX of projects was supposed to be allocated to community projects. Any capital project that I was involved in, 2% was spent. Or more. Because sometimes the communities’ needs did not amount to the value of the 2%, I have to go and make the case that our rules internally are 2% and so let us go and ask them for more projects. The same thing here; I have had conversations internally where it has been pointed out to me that you can go and negotiate something lower to be spent. I don’t even know how that is done and I tell them, please do not do that. It’s not while I’m here. While I’m here, for our capital projects, we submit them to (National Content Development Monitoring Board(NCDMB), they calculate what the 3% is and that is what we use for human capital development. So it can be that or more not less.
Why NCDMB not NUPRC?
Oh later on it will become NUPRC. But at this point, for our human capital development, I don’t know how it’s going to transit under the PIA, the human capital development is 3% of the CAPEX of the projects; it is different from the Host Community Fund. The Host Community Fund is under the PIA at this time and it is 3% of your operating expenditure of the previous year.
You did say you trained 50 people?
Chike Nwosu: We brought in 50 but 47 showed up for the training.
AOGR: Was it last year?
Chike Nwosu: It was last year, yes.
AOGR: Okay, you did mention 200.
Chike Nwosu: We identified 200 and we are going through the entire 200. This is the first batch and we are doing it phase by phase. Because if you train 200 people, then you have to bring in a significant portion of that 200 and we have to tie it in with the progress of our projects. So the next batch will be targeted at the refinery expansion. Yeah, and the next batch will be targeted at the condensate expansion while the next batch will be targeted at the industrial park.
Because we also want to provide for the people that will come into the industrial park, the technical, operational, whatever competency, even supports competencies, administrative competence, that are required for them to run their factory, will be from the people in the community first.
Let’s examine this large elephant in the room. Waltersmith has not exported a drop of crude, out of the country since March 2022. The Trans Niger Pipeline, its evacuation route, a has been down for that long. There are people who believe that much of the stolen crude is actually being exported.
I believe that absolutely.
You don’t think that those artisanal refineries-there’s quite a large number of them-are largely responsible…
I’m looking at the logic going backwards because I’ve run a refinery. If for a 5,000 barrels per day refinery, 130,000 litre truck is less than 200 barrels, about 188 barrels. And it you take the dead stock away you would have let’s say 180 barrels. A 45,000 litre truck is less than 280 barrels so you can imagine that for a 5,000 barrel refinery, I need about 30 trucks. Now the crude that is supposedly stolen for illegal refining on the TNP is in excess of 150,000 barrels by the time crude oil theft got to 90%. That is 30 times the number of trucks that I need which is about 750 trucks. I don’t think you could have 750 trucks a day plying that axis without anybody seeing them. It is near impossible to imagine that scale of trucking and logistics happening and that was why I said illegal refineries do not go beyond 40-50,000 barrels per day. The rest of it is a major cartel; I borrow the words of one of my colleagues, I think it is the MD of ExxonMobil, who said that it is an international criminal cartel that are hugely moving away our crude in big tanks not the artisanal or what they call illegal refineries.
The question then is, is it that, once you have a significant volume of theft, you just basically stop producing, so that when the entire production in the country turns out to be just 1.2 million, it is not so much that 1.3Million has been stolen? Or that companies just scale back because you know, so much is being stolen?
There’s been a massive reduction from highs of over$ 20Billion investment per annum to as low as $6 Billion investment in the oil and gas industry. That has the most significant impact on our overall production
Let me tell you about to perspectives about OPEC’s quota and how low it has come. I think Austin Avuru and Osten Olorunshola have shown some work that has been done to indicate that even without crude thefts, because of the lack of investment, you know, these assets will decline. And the decline on the average is 10 to 15% per annum. And the only way you can actually increase production is through new investments, new developments, new production optimization, enhanced oil recovery and things like that. Now Austin, the two Austins, have shown that over the period of the last seven to ten years, I think more likely seven years, there’s been a massive reduction from highs of over 20Billion dollars investment per annum to as low as six Billion dollars investment in the oil and gas industry. That has the most significant impact on our overall production and you know, our OPEC production. So let nobody go away with the thought that it is because of crude thefts that we have gone from two point something Million barrels to 1.2Million. No; investments have not been there to sustain that level of production and to grow it because decline will happen. What you can do is go to 2Million barrels seven years ago and do a decline at 10 to 15 percent and you’ll see the impact of that. Okay? And they even showed the direct correlation between the trending down of Investments and the trending down of production.
Now, however, it doesn’t mean that crude theft is not a problem. It is a significant problem on the onshore assets and he talked about the figures and these are NUPRC’s/DPR figures.
The Waltermith Industrial Park will provide energy products to companies around Ibigwe. That’s the plan. These products are essentially gas and power. Before I ask you where you see Waltersmith in the next five years, there was a point you mentioned at the Nigerian International Energy Summit (NIES) about solar assembly. That was a data point that just leapt at me. I mean, solar, what’s that all about?
There’s something else in our blueprint beyond solar. I’ve got an intern here working on Blue Hydrogen. We recognize that there’s going to be a transition and that the transition will happen through gas as the transition fuel. Our gas business will start dominating the Upstream and we’re looking at the portfolio where that happens and Equatorial Guinea EG 23 is an example of where there’s a lot more in terms of gas reserves in BOE terms and then there’s oil. OML 20 has a lot of gas reserves as well and so we’ve continued to look at those assets. OML 21 as well, where you have the ANOH gas plant. If we start getting gas from there, the total quantum of energy that we are using for consumption will go more towards gas. However, we have to look at the fact that even gas has significant greenhouse gas emissions. We have to start replacing some of the gas to power and fossil fuels to power through refinery into more renewable sources.
That is why we started studying solar energy and these solar panels and we discovered that most of the manufacturing of photovoltaic cells, solar PV cells, were done in China. And we believe that whatever China has as a competitive advantage in Nigeria can provide it as well. We started working with some parties in the United States to see whether we can start solar PV manufacturing in the industrial park.
So part of the industrial park will have solar PV manufacturing so that slowly we can transit our gas business into a balance of gas and solar. Now we’ve also started doing some study communities solar assessments, so the power we want to deliver to the community could be a mix of solar and gas. But we’ve done the enumeration for solar first of all and we’ll take a look later on to see what it possibly means for gas.
But even in our facilities, with street light and things like that, we’ve started going away from using diesel power generators to using solar panels for electrification. So if you go to a facility, all the street lights are solar. So we’re testing this concepts as we move along because we know the transition will happen soon.
Crude oil producing companies operating in Nigeria used to report to the Department of Petroleum Resources (DPR) to obtain export permit for the commodity.
Until the Petroleum Industry Act (PIA).
The overarching law of the Nigeran hydrocarbon sector, enacted in September 2021, created two regulatory agencies out of the DPR: the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) and the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA).
The legislation inadvertently authorised both agencies to be in charge of regulating crude oil export terminals.
Section 7EE of the PIA empowers the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) to:
Issue certificates of quality and quantity to exporters of crude oil, natural gas or petroleum products from integrated operations and crude oil export terminals established prior to the effective date and the commission shall have the power to monitor and regulate the operations of crude oil export terminals and the responsibility of weights and measures at the crude oil export terminals shall cease to exist from the effective date.
And Section 32ii of the PIA empowers the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) to:
Issue certificates of quality and quantity to exporters of crude oil, LNG and Petroleum products.
These two clauses have created a conundrum. Which agency is the rightful authority to issue export permit?
“This issue was one among several that the PIA implementation team saw and pointed to both agencies in our interactions with them and they promised to resolve implementation via the presidential steering committee”, a ranking manager at an International Oil Company told Africa Oil+Gas Report.
The two agencies fought out the issue of export permit during the third quarter (Q3) 2022 permitting round as they both insisted on issuing the permits and actually did. “This points to serious implementation hiccups in the law than ever envisaged”, the manager said.
Operators had to apply to both agencies but after much haggling, paid the fees only to the downstream agency as operators refused to pay twice for same permit.
Some analysts have wondered how storage and export of crude which is produced through upstream operations be a midstream to downstream activity.
But the PIA also explicitly defined upstream operations as terminating at the crude oil production Platform, such that there is validity in the argument that the NMDPRA should be the agency to grant export permit to terminals.
Prior to the enactment of the PIA, permits were issued by the midstream and downstream divisions of the DPR, which constitute a significant part of the NMDPRA, but those permits were dependent on clearance by the upstream divisions of the DPR, where the technical allowable and proof of royalty payment were checked.
Even so, there are terminals and there are terminals. In the deepwater terrain, where about half of Nigeria’s crude oil output is delivered, the FPSO is both the production facility and the terminal. In several shallow water fields, the FSO or a Production Platform, is effectively the terminal. From most onshore (and swamp) fields however, the commodity is transported to terminals at the edge of the Atlantic.
Based on this geography of supply, the Minister of Petroleum and the deep divisions, the Minister of Petroleum has directed that the NUPRC will issue permits for export from deepwater as well as those shallow water assets for which their FSO or Production Platform sere as their terminals.
But some still kick against the Minister’s directive, in private, arguing that “dual regulatory powers” are not the intent of the PIA.
“Segregation clauses are meant to resolve the matter but segregation is not immediate”, a Nigerian owned operating company staff explained to Africa Oil+Gas Report. “From late 2021 to end of the 2nd Quarter 2022, operators were taking export permit from NUPRC but this was probably because NMDPRA was still finding its feet then as NUPRC was able to take off more effectively because it took over most of the structure and activities of DPR”.
The PIA is not a straight forward document the makers thought it is and so much unforeseen issues have come up and are coming up.
“Some of the segregation clauses were written by those who are not industry practitioners and operators seem to have paid more attention to the fiscal clauses in their advocacy such that there are several confusions in the operations clauses”, several analysts say.
So, what should be the way forward?
Everyone seems to agree that poor drafting is the big issue and this is clearly one area where some amendment will help.
“A literal reading of the provisions of section 7 of the PIA would suggest that the NUPRC remains responsible for any existing terminal”, says Adeoye Adefulu, Managing Partner at Odujinrin & Adefulu, a full service commercial law firm, “the NMDPRA would only be allowed to supervise the terminals which are established afterwards”.
In the long run, however “to address the conflict on regulations between the two regulators, the PIA needs to be amended to ensure that the full upstream value chain from acreage management to crude oil export is regulated by the upstream regulator while the midstream regulator is focused on midstream and downstream”, argues an asset manager at one of the International Oil Companies, who has had oversight function on regulatory permits. “In the interim until PIA is amended”, he argues, “the minister of petroleum/ President should issue a policy directive to effect the change”.
French major TOTALEnergies has announced the final investment decision for Begonia, the first development on block 17/06, located 150 kilometres off the Angolan coast, in agreement with concession holder Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG) and its partners on Block 17/06.
The Begonia development consists of five wells tied back to the Pazflor FPSO (floating production, storage and offloading unit), already in operation on Block 17. After commissioning, expected in late 2024, it will add 30,000 barrels a day to the FPSO’s production.
After CLOV Phase 3, another satellite project that produces 30,000 barrels a day and was launched on Block 17 in June 2022, Begonia is the second TOTALEnergies-operated project in Angola to use a standardized subsea production system, saving up to 20% on costs and shortening lead times for equipment delivery.
The project represents an investment of $850Million and 1.3Million man-hours of work, 70% of which will be carried out in Angola, the company says in a release.
Angola’s revenues rose from $1.4Billion in April 2022 to $2.1Billion in May 2022, the government data says, owing to the doubling of crude prices compared with 2021.
Payments to Chinese creditors began in the first quarter of the year, 18 months ahead of schedule, as the suspension of debt service meant that payments would only resume at the end of the first half of 2023.
Angola’s debt to China fell by $351Million in the first quarter, to $21.4Billion, according to data from REDD Intelligence.
Angola’s debt to China, estimated at 40% of registered external debt, is mostly derived from loans contracted with Chinese banks, especially Exim Bank and BDC, in the view of Africa Monitor Intelligence,
Angola ´s debt to Chinese creditors had threatened to reach $22Billion between 4th Quarter 2019 and 4th Quarter 2021, but the Angolan Government had vowed to start bringing it down and now it is doing so.
Chinese loans, which represent about a third of Beijing’s claims on all African countries, were essentially intended to finance infrastructure projects (construction or reconstruction) and others, of an industrial nature.
Under a mechanism called “Angola Mode”, Angolan oil supplies, carried out under special price conditions, are intended to pay off Chinese investments in these projects.
The Bank had been keen to be a part of the funding for the country’s basin wide oil development project
But, under pressure by activist shareholders and environmentalist groups to desist from funding fossil fuel development, the Johannesburg headquartered Bank has thrown its hands in the air, explaining that the project does not depend on its participation.
“While we are the biggest lender in Uganda, we are such a small player in the $10Billion project that if Standard Bank does not participate, the project can still be funded by more well-heeled financial firms”, the company’s management sources say.
TOTALEnergies, the project leader, declared in a release after the Final Investment Decision (FID) on the project in early February 2022, that the FID was in line with the company’s “strategy of only approving new projects if they are low-cost and low emissions”. In particular, TOTALEnergirs said, “the design of the facilities incorporates several measures to limit greenhouse gas emissions well below 20 kg CO2eq/boe, including the extraction of Liquefied Petroleum Gas for use in regional markets as a substitute for burning biomass, and the solarization of the EACOP pipeline”.
The French major’s emission numbers stand in stark contradiction to the figures thrown up by groups like Just Share, which says the pipeline would pump enough oil to generate up to 34.3Million tonnes of carbon dioxide – about seven times the emissions of Uganda and Tanzania combined. It’s not clear whose numbers are correct, but TOTALEnergies has not lamented scarcity of funding for the project and it continues to announce first oil in Uganda by 2026.
South African banks like ABSA, Nedbank and Investec have been scared away from oilfield development projects by the loud protestations of such groups.
