Algeria’s crude oil output bumped up to 1,000,000Barrels Per Day (1MMBOPD) in August 2026.
It’s the country’s highest production in 18 months and it marks the summit of a gradual creep since May 2025, OPEC’s Monthly Oil Market Report shows.
The North African country is Africa’s second largest natural gas producer but it comes fourth among the continent’s top crude oil producers, after Nigeria, Libya and Angola, in that order.
Nigeria’s crude output slipped slightly by 5,000BOPD to 1.5MMBOPD and Libya’s inched up by 6,000BOPD to 1.397MMBOPD in August 2026, OPEC reports.
Angola’s figures don’t show up in OPEC’s publications anymore, but output reported by the country’s regulator have, in the last three months, placed Angola’s production at less than 40,000BOPD higher than Algeria’s.
The middle tier producers: Gabon and Congo Brazzaville, each remained stuck below 280,000BOPD. Fuller details…
Mozambique has effectively taken off. Namibia is waiting, hoping. Zimbawe is in a slow roll.
Nine months into lifting of the Force Majeure on the 13Million Tons Per Year Mozambique LNG project, TOTAL has reported construction to be 45% complete and first gas assured to be on stream by 2029. ExxonMobil has taken the most important logistics steps towards Final Investment Decision (FID) on the nearby 18.6MMTPA Rovuma LNG project and ENI is considering a third Floating LNG in the Coral complex.
As Mozambique eyes a set of large extraction facilities humming and spewing out liquified gas on the coast in Afungi, Namibia remains on the exploration spot.
TOTAL’s FID on the development of the Venus field, the country’s flagship hydrocarbon asset in Namibia is still in process. BW Energy’s Kharas-1, the highly anticipated appraisal well on the Kudu field drilled in 2025, encountered liquid hydrocarbons and de-risked reservoirs, but it neither advanced the prospects of Final Investment Decision by late 2026, nor moved the needle in the prospect for Namibian gas to power by 2027. ReconAfrica’s drilling of Kavango West-1 and testing, so far, of the Otavi carbonate reservoir, has not been convincing enough in terms of commerciality in an uncharted frontier basin. That reservoir is the primary target in the Damara Fold Belt in the onshore Okavango basin, straddling Namibia and Botswana.
In Zimbabwe, the last major physical drilling and discovery activity on the Mukuyu field was concluded in March 2024, when Australian firm, Invictus Energy, finished drilling and logging the Mukuyu-2 sidetrack well, onshore in the Cabora Bassa basin, in the north of the country.
The hydrocarbon opportunity grows dim In South Africa, the regional powerhouse. The Constitutional Court’s rejection of a proposal by Shell to acquire seismic data in the waters off the wild coast is part of a pattern of the ecosystem saying no to oil and gas exploration.
It’s a mixed bag. No regional bloc in Africa presents as compelling a story of hydrocarbon exploration, extraction or of rejection, as Southern Africa currently does.
The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. Published since November 2001, AOGR is a monthly, e-copy publication delivered to subscribers around the world. Its website remains www.africaoilgasreport.com and the contact email address is info@africaoilgasreport.com. Contact telephone numbers at the headquarters in Lagos are +2347062420127, +2348036525979 and +2348023902519.
Equinor has signed an agreement with Harmattan Energy Limited, a Chevron subsidiary in Namibia, to acquire a 17.4% participating interest in Petroleum Exploration Licence 90 (PEL 90) in the Orange Basin offshore Namibia.
The transaction marks the Norwegian player’s entry into the Southwest African country and the licence provides access to a drill-ready prospect scheduled for testing in 2026.
The licence relates to Block 2813B in the Orange Basin, offshore Namibia, and is operated by Chevron. Prior to the transaction, Chevron’s subsidiary owned an interest of 52.5% in PEL 90, with the other partners in the licence being QatarEnergy (27.5%), Trago Energy (10%) and the state-owned oil company NAMCOR (10%).
“This transaction aligns with our strategy to strengthen and replenish our international portfolio through focused and disciplined growth. Namibia is a promising basin that adds attractive option value to our portfolio and complements our broader Atlantic Margin position,” says Philippe Mathieu, executive vice president for Exploration & Production International.
The closing of the transaction is subject to regulatory approvals and completion processes.
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”.
Nigerian founded independents, Aradel Holdings and Seplat Energy, each averaged the same volume of Barrels of Oil Equivalent Per day (BOEPD) output in the first half of the year 2026, according to their respective reports.
Their working interest production each amounted to 139,000BOEPD in the period.
Seplat put it out directly: “Production averaged 139,509BOEPD in the first six months of 2026”, it said, “up four per cent from the first six months of 2025 (134,492BOEPD), within 2026 guidance (135,000 – 155,000BOEPD)”.
Aradel’s message was indirect. It reported “production of 25.2MillionBOE for the period.Divided by 181 (the number of days in the first half of the year) this amounts to 139,000BOEPD.The company reaffirmed its “full year production guidance of 110,000 – 140,000BOEPD”.
The reports reflect “Group activity outcomes”, from the two competitors, each of whom is responsible for more hydrocarbon production than any of the five International Oil Majors (Chevron, ENI, ExxonMobil, Shell and TOTAL) operating in Nigeria today.
Seplat Group consists of Seplat Producing Nigeria Unlimited (SEPNU), which operates the four south east offshore Oil Mining Leases (OMLs) acquired from Mobil Producing in December 2024; Seplat West Limited, which runs the base business: the oil and gas production activities in OMLs) 4, 38, and 41, acquired from Shell, TOTAL & ENI in 2010; Eland Oil and Gas Limited, which holds a significant stake in OML 40, also in the western Niger Delta onshore; Seplat East Onshore Limited which operates the OML 53, onshore eastern Niger Delta which delivers, among other products, the upstream part of the Assa North Ohaji South (ANOH) project. ANOH Gas Processing Company (AGPC) Limited, a midstream joint venture, which is 50/50 owned by Seplat and NGIC, the natural gas subsidiary of NNPC, etc.
Aradel operates through its subsidiaries, which include Aradel Energy Limited (100%), a wholly owned subsidiary of Aradel Holdings, as well as the Operator of the Ogbele (PML 14), Omerelu (PPL 247), Olo and Olo West Marginal Fields; Aradel Gas Limited (100%), the first Nigerian independent Non-JV Gas Supplier to Bonny LNG. Established to leverage investment opportunities in the gas sector, it has 100MMscf/d gas processing facility; Aradel Refineries Limited (95%), a 3-train 11,000BOPD independent operating midstream refinery. It produces AGO, DPK, MDO, HFO and Naphtha; ND Western Limited (81.67%), an independent Nigerian oil and gas exploration and production company comprising four leading industry players with four limited liability companies (being Aradel Energy, First Exploration & Petroleum Development Company, and Waltersmith Petroman Oil) as shareholders; Renaissance Africa Energy Company, a 53.3% total equity holding made up of a direct holding of 12.5% and through ND Western, an indirect holding of 40.8%.
Nigeria’s five consecutive monthly increase in crude oil output was halted in July 2026, with the country averaging 1.5052Milion Barrels Per Day in the month, compared with the June 2026 production of 1.5552MMBOPD.
The July figures represent 100% of OPEC quota (1.5MMBOPD) and the third best in 2026, but this 50,000BOPD Month-on –Month shortfall is a downer at this time of high optimism.
Nigeria’s highest producing oil fields, including Bonga, Agbami, and Anyala, came up with output that was relatively flat to their June 2026 production.
ExxonMobil’s deepwater Erha field stood out for its output plunge from 65,950BOPD in June to 31,980BOPD in July 2026.
President Bola Ahmed Tinubu’s signing of the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 (DOEO 2026) deserves neither an automatic applause nor an instinctive criticism. My reaction is mixed—but constructively so.
I welcome the principle of using fiscal incentives to unlock investment in Nigeria’s deep offshore petroleum resources. Deepwater projects are capital-intensive, technically complex, long-dated and exposed to substantial geological, cost and market risks. Where fiscal terms have become a binding constraint to investment, fiscal recalibration can be economically rational. The announcement that the new framework could unlock as much as $50 billion of investment, beginning with the approximately $10Billion Bonga Southwest project, is therefore significant.
But investment announcements alone do not constitute public value. The more important petroleum economics question is: How much incremental value will the tax remission create for Nigeria relative to the economic rent and government revenue forgone? That is the test that should guide our assessment of DOEO 2026. Incentives are not the problem
There is sometimes an unfortunate tendency to frame petroleum fiscal policy as a choice between government revenue and investor incentives. That is too simplistic. A petroleum fiscal regime has two legitimate stakeholders with mutually dependent interests. The investor provides capital, technology, project management and assumes commercial and geological risk. The resource owner provides access to an exhaustible natural resource and expects an appropriate share of the economic rent.
The objective should therefore not be to maximise government take at the expense of investment, nor to maximise investor returns through generous fiscal concessions. It should be to maximise the mutuality of interests.
This is particularly important in deep offshore petroleum development. A barrel that remains undeveloped generates no production revenue, no employment, no local economic activity and no government revenue. But an incentive that merely transfers rent from government to an investor on a project that would have proceeded anyway does not necessarily create additional public value. The distinction is fundamental.
I suggest that DOEO 2026 should be evaluated against what I call the PEWI Fiscal Regime Test. A good petroleum fiscal regime should:
Attract investment.
It must be competitive enough to attract risk capital into commercially viable opportunities that might otherwise remain undeveloped.
Capture economic rent.
Once a project generates substantial economic rent beyond normal returns to capital and risk, the resource owner should capture an appropriate share.
Share risk and reward fairly.
The fiscal system should recognise that government and investors face different but interconnected risks. When petroleum prices, costs, reserves or production outcomes change, the sharing of risk and reward should remain economically defensible.
The ultimate test is not government revenue in isolation. It is the net economic and social value generated for Nigeria over the life of the petroleum project. And importantly: Create winners on both sides. This is where the idea of fiscal neutrality becomes useful.
“The critical empirical question is therefore not: “How much investment does the incentive attract?” It is: “How much additional investment, production and economic rent does the incentive induce that would otherwise not occur? “That is the petroleum economics test.”
Fiscal neutrality should not mean that government must receive the same nominal tax revenue before and after a fiscal recalibration. That would defeat the purpose of an incentive. Rather, fiscal neutrality should mean that the incremental value created by the recalibration is sufficient to make both sides better off.
If a tax remission enables a project that otherwise would not have reached FID to proceed, Nigeria may receive additional production, exports, employment, domestic economic activity and government revenue. The investor earns an acceptable risk-adjusted return, while government captures part of the additional economic rent created. That is a genuine win-win fiscal recalibration.
Recalibration must create incremental value This distinction should be at the centre of the public debate about DOEO 2026.
Suppose a deep offshore project is economically marginal under the existing fiscal terms and therefore unlikely to reach FID. A targeted tax incentive changes the project’s economics sufficiently to make it investable. The investor wins because the project becomes commercially viable. Government wins because an otherwise undeveloped petroleum resource begins generating production and economic rent.
The economy wins because investment, production and associated economic activity increase. That is precisely what a well-designed incentive should accomplish. But consider the alternative.
If the project would have proceeded under the existing fiscal terms, and the tax remission merely increases investor returns without materially changing investment timing, production or development scope, then the remission may simply transfer economic rent from the resource owner to the investor. That is not necessarily fiscal reform. It may simply be rent redistribution.
The critical empirical question is therefore not: “How much investment does the incentive attract?” It is: “How much additional investment, production and economic rent does the incentive induce that would otherwise not occur? “That is the petroleum economics test.
The reference to Bonga Southwest makes this discussion especially important. Bonga Southwest is a legacy deepwater development with a long history within Nigeria’s petroleum fiscal framework. The precise fiscal treatment applicable to the project therefore matters greatly in assessing the effect of the new Order. It should not automatically be analysed as though every deepwater project sits under the same post-PIA fiscal architecture.
If, as appears to be the case, the project retains its legacy PPT-related fiscal context, then the analysis of the tax remission must begin with the applicable contractual and statutory terms governing that project. This is important because fiscal regimes are not simply collections of tax rates. They are economic contracts governing the sharing of petroleum rent over time.
The question is consequently not whether Nigeria should provide an incentive to Bonga Southwest. The question is whether the recalibrated terms improve the project’s investment economics sufficiently to generate incremental public value while preserving an appropriate government share of the rent.
The Petroleum Industry Act 2021 was conceived, among other things, to provide a more coherent and predictable petroleum fiscal and regulatory framework. Its philosophy should not be reduced to the maximisation of government take.
A sustainable fiscal system must balance investment attractiveness, competitiveness, government revenue risk allocation and long-term resource value. This is why I remain particularly interested in the concept of mutuality of interests. Government and investors do not have identical interests. They should not. But their interests are not mutually exclusive either.
Government wants petroleum resources developed efficiently and wants an appropriate share of the resulting rent. Investors want commercially competitive projects, reasonable risk-adjusted returns and fiscal certainty. A good fiscal regime brings these interests together. A bad fiscal regime maximises one side’s objective at the expense of the other.
This is also where the PEWI E-QUAD provides a useful lens for evaluating DOEO 2026. Fiscal policy should not be assessed through a single metric such as government take or investor rate of return.
The design principles should include:
Efficiency — Does the incentive unlock economically efficient investment?
Equity — Is the incremental petroleum rent shared fairly?
Competitiveness — Can Nigeria compete successfully for global deepwater capital?
Simplicity — Are the fiscal provisions transparent, predictable and administratively workable?
Stability — Can investors rely on the terms throughout the investment horizon?
Sustainability — Does the arrangement create durable economic and public value?
These objectives inevitably involve trade-offs. That is why the PEWI insight remains relevant. Balance is more important than maximising any one objective.
A regime that maximises government take but kills investment is not optimal. A regime that maximises investment but unnecessarily sacrifices economic rent is equally suboptimal. The objective should be value optimisation, not objective maximisation.
I therefore welcome the direction of DOEO 2026, particularly if its objective is to unlock deep offshore investments that have been commercially constrained by the prevailing fiscal economics. However, I would reserve a final judgment on its quality until the detailed fiscal mechanics are available and we can determine:
the tax liability being remitted;
the projects and contracts covered;
the investment and FID conditions attached to the incentive;
the duration of the benefit;
the incremental investment induced;
the expected incremental production;
the economic rent created; and
the government’s expected share of that incremental rent.
The proposed 31 December 2029 FID window for existing deep offshore leases is particularly interesting. A time-bound incentive linked to actual investment and FID can be economically superior to an open-ended concession because it connects the fiscal benefit to the behaviour the policy seeks to induce. That is good fiscal design—provided the conditions are sufficiently clear and enforceable.
Nigeria should resist the temptation to describe every fiscal concession as an incentive without asking what economic problem it is solving. An incentive is justified when it changes behaviour and creates additional value.
If DOEO 2026 brings otherwise marginal deepwater projects to FID, increases production, expands the economic rent available for sharing and ultimately leaves both investors and the Nigerian public better off, then it represents a sensible fiscal recalibration. If, however, it merely reduces government take on investments that would have occurred anyway, the policy would deserve much greater scrutiny.
“The objective should therefore not be to maximise government take at the expense of investment, nor to maximise investor returns through generous fiscal concessions. It should be to maximise the mutuality of interests.”
My position is therefore neither “tax incentives are bad” nor “investment attraction justifies any incentive.” It is simpler: A good fiscal regime must attract investment, capture economic rent, share risk and reward fairly, and create long-term public value. And a good recalibrated fiscal regime should create winners on both sides. That, ultimately, is the PEWI test for DOEO 2026: Does the remission enlarge the economic pie, or merely redistribute the existing pie?
If it enlarges the pie while preserving a fair share of the incremental rent for Nigeria, then the policy deserves support. If it merely redistributes existing rent, we should call it what it is—and ask whether that is consistent with the mutuality of interests intended by Nigeria’s petroleum fiscal framework.
Wumi Iledare is Professor Emeritus of Petroleum Economics.
Nigeria has spent decades proving that it can find and produce oil. Its harder problem has been persuading global capital to develop the oil it already knows is there.
That is why President Bola Ahmed Tinubu’s latest deep offshore investment framework deserves more attention than another headline about a potential $50Billion investment.
The Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 is intended to establish clearer and more predictable conditions for qualifying deep offshore projects. The Presidency says the framework could unlock up to $50Billion in new investment, with Bonga South West among the first major projects expected to benefit.
But I think the bigger story is not the $50Billion headline. It is the recognition that, in today’s energy market, certainty is one of the strategic assets on which jurisdictions compete for capital.
Nigeria has never had a shortage of hydrocarbons. What it has struggled with is converting petroleum resources into bankable projects at the speed required by increasingly selective global capital.
That is the problem this reform is attempting to solve.
From resources to investable assets
For years, Nigeria’s deepwater story has been something of a paradox. The country possesses world-class offshore resources and considerable technical expertise, yet some major development opportunities have remained stalled because their economics could not be made sufficiently attractive or predictable.
Bonga South West is perhaps the clearest illustration.
Earlier this year, the Nigerian government approved targeted incentives to help move the long-delayed project towards Final Investment Decision. Shell has indicated that the development could involve as much as $20Billion in investment with its partners, while the project is expected to have production capacity of about 150,000 barrels per day.
A project can have excellent geology and still fail to reach FID if investors cannot confidently model the fiscal, regulatory and contractual environment over the life of a multibillion-dollar development.
The new framework therefore represents an important shift in philosophy.
Rather than relying primarily on bespoke negotiations around individual projects, Nigeria is attempting to create a more predictable framework within which qualifying investments can be assessed.
That distinction matters.
Capital does not merely follow resources. It follows risk-adjusted returns and jurisdictions in which those returns can be calculated with reasonable confidence.
But certainty is only one part of the equation. Project costs, financing conditions, regulatory efficiency, infrastructure, execution risk and competing opportunities elsewhere all influence an investment decision.
The relevant benchmark, therefore, is not whether Nigeria’s new fiscal terms are better than Nigeria’s old terms.
It is whether the resulting project economics are competitive with the alternatives available to global capital.
But $50Billion is not $50Billion
There is a temptation to celebrate the $50Billion figure as though Nigeria has already secured the money.
It has not.
In fact, the Nigerian Upstream Petroleum Regulatory Commission had already identified 22 offshore projects expected between 2026 and 2030, with potential investment estimated at between $30Billion and $50Billion.
The significance of the new Order, therefore, is not that it creates a US$50 billion opportunity out of nowhere.
The opportunity was already visible.
Its significance is whether it can remove enough of the obstacles preventing that opportunity from becoming investable projects.
That distinction is important.
Investment potential is not investment commitment. Investment commitment is not capital deployed. And capital deployed is not production.
The real measure of success will therefore be considerably less glamorous: how many projects reach FID, how quickly capital is deployed, how much new production comes on stream and how much economic value remains in Nigeria.
Bonga South West will be an early test.
The Presidency says NNPC Limited, as the Federal Government’s nominated counterparty under the relevant Production Sharing Contracts, will work on the amendments required to implement the framework.
That is where policy becomes execution.
And execution is where Nigeria has historically struggled.
The framework can remove one significant obstacle to investment. It cannot, by itself, remove every obstacle.
Failure at any point can destroy much of the value created at the previous point.
If the new framework produces a faster and more predictable pathway from commercial negotiation to FID and project execution, it could become one of the more consequential upstream reforms of the current administration.
If it simply creates another layer of policy announcements without corresponding speed in implementation, the market will notice.
Investors always do.
Nigeria is competing with Africa
There is another dimension that deserves much greater attention.
Nigeria is not competing for offshore capital in isolation. It is competing with an increasingly attractive group of African jurisdictions.
Moore Global estimates that African upstream oil and gas capital expenditure could reach approximately $41Billion in 2026, up modestly from $40Billion in 2025. Its analysis puts African offshore investment at about $19Billion this year, with deepwater developments accounting for much of the growth.
That is a meaningful opportunity, but it is also a competitive market.
Nigeria is the established giant trying to revitalise a mature petroleum province.
Angola is working to sustain offshore investment and production.
Namibia is emerging as one of the continent’s most closely watched frontier offshore provinces.
Mozambique is trying to restart its enormous LNG opportunity.
Senegal and Côte d’Ivoire are demonstrating that newer African hydrocarbon provinces can attract international capital.
The significance of Nigeria’s reform is therefore partly continental.
Countries are no longer competing merely on the basis of reserves. They are competing on above-ground conditions: fiscal terms, regulatory certainty, project economics, infrastructure, political stability, local-content capability and speed of execution.
The race is increasingly between jurisdictions.
The Namibia question
Nigeria should be watching Namibia particularly closely.
The comparison is instructive because the two countries occupy very different positions in the petroleum lifecycle.
Nigeria has decades of production, established operators, sophisticated service companies, extensive technical expertise and enormous producing assets.
Namibia is approaching the industry as a new frontier.
Yet Namibia has captured enormous international attention because of its offshore discoveries and the possibility of building an entirely new petroleum province.
Nigeria should not see this as a threat.
It should see it as a warning.
Resource endowment is not a permanent competitive advantage.
A country can possess more reserves, more infrastructure and more industry experience and still lose investment to a jurisdiction that offers investors a more compelling combination of geological potential, fiscal terms and execution certainty.
Nigeria’s advantage is its accumulated capability.
The question is whether it can convert that capability into a competitive proposition for the next generation of African offshore investment.
From local participation to local capability
Perhaps the most interesting aspect of the new framework is its emphasis on Nigerian industrial capability.
The Presidency says qualifying projects should maximise execution in Nigeria wherever commercially and technically feasible, including engineering, fabrication, marine logistics, technical services and project management. It links the offshore opportunity to strengthening Nigerian supply chains and positioning the country as a regional hub for deep offshore project execution.
This is where the reform could become genuinely transformative.
The objective should not simply be to attract $50Billion into Nigerian offshore projects.
It should be to ensure that a significant proportion of that capital creates capability that survives the projects themselves.
There is a crucial distinction between local participation and local capability.
A company can receive a contract because it meets Nigerian Content requirements without becoming globally competitive.
The more ambitious question for Nigerian Content policy should therefore be:
What globally competitive Nigerian industrial capability will exist five or ten years from now because of the offshore investments made today?
A large offshore development creates demand across an enormous ecosystem: engineering, fabrication, subsea services, drilling, completion, marine logistics, inspection, maintenance, digital technology, HSE, project management, finance and professional services.
Nigeria should use this investment cycle to build companies capable of competing not only in Bonga but eventually in Luanda, Walvis Bay, Accra and Abidjan.
That is where an oil investment strategy becomes an industrial strategy.
And it raises a more provocative question:
Could Nigeria become Africa’s offshore services capital even if it cannot indefinitely remain Africa’s dominant oil producer?
The country already possesses something many emerging petroleum provinces do not: decades of accumulated technical, managerial and commercial experience.
That accumulated capability is an asset.
The strategic opportunity is to turn it into an export industry.
The real issue is value capture
There is, however, another question that Nigeria should not avoid.
How much of the economic value created by the next generation of offshore investment will actually accrue to Nigerians?
Attracting capital is only the first step.
The country must capture value through competitive local companies, skilled employment, technology transfer, engineering capability, fabrication, marine services, professional services, taxation and eventually the export of Nigerian expertise into other African markets.
This is a more demanding conception of Nigerian Content.
It moves the conversation from:
“How much of the contract was executed in Nigeria?”
to:
“What capability did Nigeria acquire because the contract existed?”
That distinction could determine whether the current offshore investment cycle becomes another period of production growth or the foundation of a broader industrial ecosystem.
Africa’s hydrocarbon window is narrowing, but it has not closed
There is also a broader African question.
The continent is under pressure to accelerate the energy transition while simultaneously needing enormous amounts of capital for infrastructure, industrialisation, electricity and development.
This creates an uncomfortable paradox.
Africa possesses substantial oil and gas resources at a time when global investors are becoming more selective about financing new hydrocarbon projects.
The rational response is neither to pretend the hydrocarbon opportunity does not exist nor to assume that oil will remain an endlessly rising source of wealth.
The more intelligent strategy is to monetise commercially viable resources efficiently while they remain economically valuable, and use the resulting capital to build the foundations of a more diversified economy.
For Nigeria, that means turning offshore investment into more than barrels.
It should produce infrastructure, skills, technology, local companies, exportable services and predictable government revenue.
In other words, Nigeria needs to improve its conversion rate:
Nigeria has historically been much better at the first half of that equation than the second.
That needs to change.
The test begins now
Nigeria’s latest deepwater reform deserves recognition because it addresses a genuine problem: uncertainty.
But the hard work starts after the announcement.
The success of this policy will not ultimately be measured by the size of the headline, nor by the number of press releases celebrating the reform.
It will be measured by FID decisions, contracts awarded, steel fabricated, vessels deployed, wells drilled, barrels produced, Nigerian companies strengthened and capital actually deployed.
And there is a larger African lesson here.
The next phase of Africa’s energy competition will not necessarily be won by the countries with the largest reserves.
It will be won by countries that can convert resources into investable projects, projects into production, production into industrial capability, and industrial capability into sustainable economic development.
Nigeria has just taken an important step in that direction.
But this is not the victory lap.
It is the starting gun.
The real question is not whether Nigeria can attract another US$50 billion.
It is whether Nigeria can use the next generation of offshore investment to build capabilities worth more than the oil itself.
If it can, the 2026 deep offshore reform may eventually be remembered not simply as an investment incentive, but as an industrial policy disguised as an oil policy.
If it cannot, Nigeria may once again succeed in attracting capital without capturing enough of the value that capital creates.
That is the real test of the offshore reset.
Sola Adebawo is an energy industry executive, strategic advisor and thought leader with nearly three decades of experience across Africa’s upstream petroleum sector. He is the Chief Executive Officer of Hyphen Partners Limited, a specialist advisory firm focused on policy and regulatory intelligence, market entry, stakeholder strategy, executive and institutional positioning in complex and highly regulated industries. A former executive at Chevron and Heritage Energy, he is an author, scholar and ordained minister. His writing explores energy policy, political economy, corporate governance, strategic communication, leadership, the relationship between institutions and public life, as well as the institutional forces shaping Africa’s development.
Nigeria President Bola Ahmed Tinubu has approved a new investment framework for deep offshore investment.
The framework will be effected through an executive order: The Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026.
The incentive is “designed to unlock up to $50Billion worth of investment in the terrain and restart Nigeria’s large, capital intensive offshore developments that have remained stalled for decades”, according to the office of the Special Adviser to President Tinubu on Energy.
“The reform replaces project by project negotiations with a transparent, rules based framework that provides clear eligibility criteria, defined implementation processes and greater investment certainty across qualifying deep offshore developments”, the office said.
“The framework will support the next generation of offshore projects, beginning with the approximately $10Billion Bonga South West project, while strengthening Nigeria’s competitiveness for globally mobile investment capital”.
President Tinubu himself declares on his X handle: “This Order marks the tenth major policy directive of my administration targeted specifically at the oil and gas sector. Each has dealt with a constraint holding back investment, production or value creation. Taken together, they represent a deliberate effort to make our oil and gas industry more competitive, attract capital back to Nigeria and ensure that more of the value created from our resources remains here at home”.
The President said that when he engaged Wael Sawan, the Chief Executive Officer of Shell plc, he directed his team “to look beyond a solution for one company or one project. We needed a framework that could unlock a wider pipeline of investment while protecting Nigeria’s long-term interests.
“That framework is now in place”.
The S.A. on Energy’s office says that the framework “was developed through an extensive inter agency process led from the Presidency, working with fiscal, legal, commercial and regulatory institutions, alongside industry”.
The statement contends that the new order “enables NNPC Limited, as Government’s nominated counterparty under the Production Sharing Contracts, to proceed with the necessary amendments to eligible Production Sharing Contracts”.
According to the office: “Qualifying projects will maximise execution within Nigeria wherever commercially and technically feasible, supporting domestic engineering, fabrication, marine logistics, technical services and project management, while creating skilled jobs and deepening local supply chains”.
The inaugural oil industry Host Community Summit, HostCommTM, is scheduled for August 09-10, 2027 in Lagos, Nigeria.
HostCommTM is a platform created by a consortium of three Oil & gas industry focused organisations comprising Caritas Communications, Africa Oil+Gas Report and Pedestal Africa.
HostCommTM as the forum is named is a decisive move to bridge the gap between regulatory mandates and ground-level execution.
Under the theme “Building Trust, Creating Shared Value and Sustaining Development,” the HostCommTM Summit will confront the critical operational, financial, and governance challenges of host community engagement head-on. The summit moves the narrative beyond theoretical discourse, focusing on actionable solutions, conflict resolution, and bankable community development models.
As Nigeria’s energy sector navigates the practical enforcement of the Petroleum Industry Act (PIA) 2021, the HostCommTM Summit serves as the definitive national platform to turn regulatory compliance into sustained operational harmony and shared prosperity.
The Host Communities Development Trust (HCDT) framework under the PIA 2021 is the bedrock of the industry’s social license to operate across upstream, midstream, and downstream assets.
“Sustainable energy production requires more than capital and hardware; it demands absolute alignment with host communities”, says Adedayo Ojo – Founder of Caritas Communications, speaking on behalf of the consortium of organizers. “The HostCommTM Summit is structured to de-risk investments, hold stakeholders accountable, and ensure the 3% OPEX capital allocated to trusts in the PIA yields measurable, long-term impact.”
Key Summit Focus Areas
Showcasing Operational Excellence: The HostCommTM Summit is a direct platform for oil, gas, and energy operators to benchmark success, highlight high-impact HCDT initiatives, and refine community engagement strategies.
Unlocking ESG & Development Capital: The summit brings together financial institutions, private equity, development finance institutions (DFIs), and ESG experts to build scalable funding models for community infrastructure.
Regulatory Clarity & Quadpartite Dialogue: It is a platform for direct, high-level engagement involving operators, regulators, traditional institutions, and host community leadership to streamline governance and mitigate dispute risks.
Supply Chain & Local Content Integration: Strategies for service companies, EPC contractors, and local vendors to integrate host community capacity into the broader energy value chain.
Who Must Attend
The HostCommTM Summit brings together decision-makers shaping the future of West Africa’s energy landscape:
Host Community Leaders, Trustees & Traditional Institutions
ESG Experts, Legal Practitioners & Energy Consultants
DFIs, Commercial Banks & Investment Managers
Engineering, Procurement, & Service Companies
Event Summary
Parameter Details
Event Maiden Host Community Summit (HostCommTM Summit)
Date August 09-10, 2027 (Exact dates TBA)
Location Lagos, Nigeria (Venue TBA)
Theme Building Trust, Creating Shared Value and Sustaining Development
Conveners: Caritas Communications Limited & Africa Oil+Gas Report (AOGR), and Pedestal Africa.
Position your organization at the forefront of Nigeria’s evolving energy landscape. Early engagement provides strategic visibility, speaker nomination opportunities, and premium partnership placement.
Take Action Today:
Sponsorship & Exhibition: Secure high-impact branding and dedicated exhibition space to showcase your community achievements.
Speaker & Panel Nominations: Contribute thought leadership to pivotal discussions on HCDT governance and compliance.
Strategic Partnerships: Join leading operators and institutions in steering the summit’s agenda.
Full registration details, delegate packages, and the official summit program will be released in due course.
For inquiries regarding partnership proposals and sponsorship requests please contact:
