Italian contractor Saipem has been awarded a $350Million contract by Azule Energy Angola S.p.A., relating to the West Hub Tails project, part of the wider Agogo Integrated West Hub Development, located 180 kilometre offshore Angola at water depths up to 1,750 metres.
The scope of work covers the engineering, fabrication, transportation and installation of subsea infrastructures, including approximately 62 kilometres of flowlines, risers and umbilicals, to be tied-in to the Agogo Floating Production, Storage, and Offloading unit (FPSO), with an expected duration of approximately two and half years.
Fabrication activities will be carried out at Saipem’s Ambriz yard in Angola, with the involvement of local companies and workforce. For the offshore campaign, Saipem will deploy the construction vessels FDS and Normand Maximus.
Upstream asset divestment by International Oil Companies (IOCs) in Nigeria is now a norm.
But what about the time between the familiar phrase “the transaction is subject to obtaining all required regulatory approvals” in divestment announcements and when the approval is actually granted?
“The transaction is subject to obtaining all required regulatory approvals” is more than a routine caveat – it is a substantive regulatory condition for the transfer of interests. Approval requires the transaction to be assessed against the buyer’s technical and financial capacity, the asset’s end of life obligations, the agreement of the parties, and other relevant considerations. Yet recent IOC divestments show that the process behind this condition can be uncertain, with timelines extending well beyond those anticipated at the point of the announcement.
“The real litmus test of the implementation of the regulatory divestment framework would be the ongoing NNPC Ltd Project Delta divestment, where the legal frameworks can be tested against its own promises of predictability vis-à-vis established timelines, procedural steps, the due diligence elements, and even the deemed approval clause. Expectedly, the complexity of individual transactions will differ, and the time it takes parties to furnish NUPRC with updated or additional information will vary, as such, some reviews might extend beyond the established timelines. But this is precisely where NUPRC may rethink its current communication approach around transaction approvals. “
As upstream divestment by the IOCs intensified in the first five years of the 2020s, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) has had to build on the legal foundation established by the Petroleum Industry Act 2021 (PIA) for the transfer of interests in upstream assets. This foundation is been operationalised through the Nigeria Upstream Petroleum (Assignment of Interest) Regulations, 2024, and NUPRC’s seven pillar regulatory divestment framework.
Section 95 of the PIA establishes the statutory basis for upstream asset transfer. The section prohibits the transfer of interest by a party to another without approval. The section establishes that the first step after submission of an application for approval by a party is for NUPRC to evaluate and recommend the application to the minister of petroleum for ministerial consent. The expectation of section 95 is for NUPRC to make the recommendation within 60 days and another 60 days for ministerial approval consideration. Notwithstanding these timelines, approval is not a given. Section 95 of the PIA also establish deemed consent as section 95(7b) states that where “no response on the application has been received within 60 working days from the receipt of the recommendation of the Commission, the consent of the Minister … shall be deemed to have been granted”.
The Nigeria Upstream Petroleum (Assignment of Interest) Regulations 2024 further provides procedural guidance for implementing section 95 of the PIA. It highlights details for asset transfer, including mandatory eligibility stage before commercial negotiation. The regulation requires the holder of the asset to inform NUPRC of the transaction and the candidates it has penciled down for the ownership transfer after technical evaluation. Under this regulation, NUPRC is obligated to, within 15 working days of receiving the shortlisted candidates to inform the asset owner of the candidates deemed acceptable to the federal government. Bypassing this stage and going ahead to commercial negotiation is considered by NUPRC that the transaction has “failed the eligibility criteria for the grant of consent by the Minister”.
The regulation establish that NUPRC will undertake “due diligence on application for transaction at any stage of such transaction before making any recommendation to the Minister in respect of the application”. The due diligence include “technical capacity, financial capacity, legal requirements, decommissioning and abandonment, host community trust and environmental remediation fund arrangements, industrial relations and labour related issues; and data repatriation”. The regulation also sets out what happens when the due diligence checks are not met or met, and maintains the same timeline as section 95 of the PIA.
The NUPRC regulatory divestment framework outlines the substantive elements that regulatory approval assessment is based on. It covers technical capacity, financial capacity, legal requirements, decommissioning and abandonment, host community trust and environmental remediation, industrial relations and labour issues, and data repatriation. This framework offers clarity on what is assessed during a divestment regulatory approval.
Benchmarking recent divestment approval timelines against the statutory timeframes in the PIA and the Assignment of Interest regulation reveals approval cycles contrary from what the framework envisages. Seplat announced its acquisition of Mobil Producing Nigeria Unlimited assets in February 2022. Despite an initial presidential assent in August of the same year, followed by a regulatory veto from NUPRC, the transaction did not reach completion until December 2024. Almost three years from announcement to close. The acquisition of Shell Petroleum Development Company by the Renaissance consortium (ND Western, Aradel Energy, First E&P, Waltersmith Petroman, and Petrolin Group), followed a different trajectory. Announced in January 2024, and completed in March 2025, about 14 months to regulatory clearance. Italian ENI and Oando transaction stands out as the fastest of the three deals. First announced in September 2023, it received regulatory approval and closed by August 2024. Taking less than a year from announcement to completion. Notably, both the Seplat and Oando deal faced pre-emption right claims from NNPC Ltd, which added an extra layer to the approval process.
These transactions provide a useful context for assessing the regulatory approval journey of divestment transactions, but they cannot be treated as a direct test of the established regulatory framework. The Seplat and Oando transactions were already underway before the Assignment of Interest regulation was issued, while the NUPRC regulatory divestment framework emerged much later in the life of the three transactions. Instead, it can be inferred that the complexity and lessons learned from these transactions must have informed the development of the regulation and divestment framework.
The real litmus test would be the ongoing NNPC Ltd Project Delta divestment, where the legal frameworks can be tested against its own promises of predictability vis-à-vis established timelines, procedural steps, the due diligence elements, and even the deemed approval clause. Expectedly, the complexity of individual transactions will differ, and the time it takes parties to furnish NUPRC with updated or additional information will vary, as such, some reviews might extend beyond the established timelines. But this is precisely where NUPRC may rethink its current communication approach around transaction approvals.
While communications between NUPRC and transaction parties are generally private correspondence, formalizing periodic updates on the status and progress of a transaction could provide greater clarity to the parties involved. Such updates could indicate the stage reached in the regulatory approval process, outstanding matters, and the likely next steps. This in turn would give stakeholders and even the wider public a better sense of how a transaction is progressing and help reduce perceptions of regulatory inaction.
It is equally important for NUPRC to clarify whether the 60 days regulatory clock pauses or restarts upon request of additional information from the parties to the transaction. The language in section 8(4) of the Assignment of Interest Regulation – “The regularisation of an existing application or an amendment thereto or submission of a new application, shall be deemed to be an application for consent under Regulations” is consequential. The implication of this is that every amendment or regularisation is considered as a fresh application, effectively restarting the 60 days timeline. While it is understandable that this approach ensures that NUPRC evaluates a complete application, it also means that the statutory window can extend well beyond what the framework envisages. A clearer distinction between minor updates or substantial amendments required to establish application completeness, or to undertake due diligence, and how each affects the regulatory clock would be reasonable. This would prevent unnecessary timeline resets and help keep approval periods well within the established window.
Publication of aggregated data on divestment transactions that have undergone regulatory approval, including: review durations relative to established legal timelines, instances where applications were deemed incomplete, the frequency of additional information requests, and the number of regulatory clock restarts would enhance predictability by giving transacting companies clearer data to benchmark their expectations. Because this sort of disclosure is process focused, it would not compromise proprietary or commercially sensitive information.
“The regulation requires the holder of the asset to inform NUPRC of the transaction and the candidates it has penciled down for the ownership transfer after technical evaluation. Under this regulation, NUPRC is obligated to, within 15 working days of receiving the shortlisted candidates to inform the asset owner of the candidates deemed acceptable to the federal government. Bypassing this stage and going ahead to commercial negotiation is considered by NUPRC that the transaction has “failed the eligibility criteria for the grant of consent by the Minister”.
Divestment approval is a consequential element of Nigeria’s petroleum governance framework, with real implications for indigenous capacity building, oil and gas production outcomes, employment, taxes and other revenues accruable to the government. As such, NUPRC must close the gap in its framework to reduce uncertainty around approval timelines for future divestment transactions. This aligns with the position of Mrs. Eyesan Oritsemeyiwa, NUPRC’s Chief Executive, who noted in her inaugural address to the industry that “execution and implementation – predictable regulation, faster decisions, stronger governance, and measurable outcomes that restore confidence, unlock investment, and maximize value for Nigerians and investors” is what the industry should expect following the legal foundation provided by the PIA.
Adeniyi Adeoloye, a petroleum geoscientist based in Calgary, is in a postgraduate course on Energy Management at the University of Calgary. An editorial associate at Africa Oil+Gas Report, Adeoloye writes from time to time for this platform and can be reached at adeniyi@africaoilgasreport.com.
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…
ExxonMobil and TotalEnergies have announced a discovery each in two separate Angolan Blocks in the last 24 hours.
The encounters were made, incidentally, in the country’s two most prolific acreages, which are also described as “mature”.
ExxonMobil’s discovery in the Vicango Este-01 exploration well was made in Block 15, the company’s sole producing block (July 2026 output 139,617Barrels of Oil Per Day BOPD and 447Million standard cubic feet of gas per day MMscf/d). The well was drilled to a depth of 940 metres (3,085 feet) “and encountered around 25 metres of high-quality sandstone containing hydrocarbons”, the operator and its partners said in a joint statement. Vicango Este-01 is ExxonMobil’s 20th discovery in Block 15, which has produced more than 2.7Billion barrels of oil over the past 30 years, the statement said.
TotalEnergies’ discovery was in the Acacia-5 on Block 17, a well that was drilled both for testing a new fault block and appraising existing accumulation. Patrick Pouyanné, Chairman and CEO of TotalEnergies, announced the result of drilling on the occasion of the Angola Oil & Gas Conference, TOTAL said in a statement. “First Oil will be achieved only three months after the discovery made in June 2026, through a fast-track development leveraging the available capacity on the Pazflor FPSO. Acacia-5 shall increase Block 17 production by 6,000 barrels per day”.
Block 17 is Angola’s most productive hydrocarbon upstream asset, delivering 309,872BOPD and 420MMscf/d in July 2026.
The announcements of Vicango Este-01 and Acacia-5, follow Chevron’s confirmation of an oil and gas condensate discovery at the 105-4X exploration well in shallow water Block 0 and Sonangol’s successful appraisal of the Katambi discovery in Block 24 in the Benguela Basin
Both announcements were made between July and August 2026.
Chevron’s 105-4X encountered an oil and gas condensate column of more than 600 metres (2,000 feet) in the primary Pinda reservoir, with more than 90 metres (300 feet) of net pay in excellent reservoir quality.
Test results from Katambi-2, “indicated that the well has the potential to produce more than 100MMscf/d, a release from the Angolan National Agency for Petroleum, Gas and Biofuels (ANPG), noted. “Initial tests recorded a stabilized production of 41 MMscf/d of gas and 1,160 barrels per day of condensate, with no presence of water or H₂S (hydrogen sulfide), in the Katambi-2.
Aradel Holdings is planning to commission the Gasoline Production Train in its Refinery by middle of 2027.
Adebola Adesina, the company’s Chief Financial Officer, spoke of the likely coming on stream of the 3,000Barrels of Oil Per day unit at the AOW Energy conference in Accra, Ghana on September 2, 2026.
“We are hoping we could deliver in the first half of 2027″, the company officially told Africa Oil+Gas Report yesterday, September 8, 2026.
Aradel’s Gasoline Unit is small in the context of the Nigerian gasoline ecosystem, but it will be the only gasoline producing plant in Nigeria outside the mammoth Dangote refinery, which produced 26Million Litres per day of the product in July 2026.
Work on the plant, located within Aradel’s 11,000Barrel Per Stream Day Refinery in Ogbele in eastern Nigeria, had been mechanically completed as far back as mid-2025. There have been issues around human expertise, sourcing sweet naptha and hydrogen for the plant, as well as upgrading the power plant in the facility to double down on guarantees of constant power supply.
Gbite Falade, CEO of Aradel spoke of the challenges of the installing the plant in a 2024 interview with Africa Oil+Gas Report. “PMS Train is a very delicate process plant. There are very few commissioning engineers worldwide that have the capacity to commission that, one of the storms we’ve run into in the recent past is finding people who have the skill but are not tied up to some other projects. It’s only recently that we’ve been able to identify the right commissioning engineers. We believe that commissioning is going to take quite a while. It’s not a commission where someone comes and turns on a switch because you have a reactor, you have different complicated chemical systems that must be properly put into service. And so, we strongly believe that it’s only when they’ve started that we’ll be able to reasonably advise when we think it will be coming on stream”.
TotalEnergies has signed an agreement to commit $10Million more to fund employment promotion and income-generation programmes in the districts of Palma and Mocímboa da Praia, in Mozambique’s gas rich Cabo Delgado province, under a partnership with the Northern Integrated Development Agency (ADIN).
The French major’s memorandum of understanding with ADIN expands on programmes and projects that TotalEnergies and its Mozambique Liquefied Natural Gas (LNG) partners established under the auspices of the Mozambique LNG Foundation with a $200Million endowment budget. That foundation was established in 2022, after an independent human rights and security review, following the Islamic insurgent attacks on Palma, the largest town in Cabo Delgado, in 2021.
TOTAL is leading the development of 13Million Tons Per Annum LNG facility in Afungi Peninsula, which sits along the coast within Palma, close to the town of Palma and the offshore Rovuma Basin. The French major is the operator of Area 1 acreage, the deepwater block from which gas molecules will be extracted to feed the liquefaction plant under construction at Afungi.
“The new funding plan aims at supporting improvement of living conditions for local communities and stimulating economic activity across both districts”, ADIN says in a statement.
The Mozambique LNG foundation has earlier reportedly created more than 8,000 local jobs and granted direct economic support to over 7,000 farmers and fishermen. The programme has funded local paving projects, a 1.7kilometer connector road in Palma, and is rolling out 28,000 solar kits alongside electric mobility solutions to empower local youth micro-entrepreneurs. It has focused heavily on the socio-economic recovery and development of local communities across the conflict-affected Cabo Delgado province, particularly the districts of Palma and Mocímboa da Praia.
ADIN says that its own new $10Million partnership programme will cover sectors including agriculture, livestock, fisheries, agro-processing, infrastructure development, biodiversity conservation, and cultural promotion, alongside measures to strengthen community resilience. Within the agricultural component, support is planned for cooperatives to boost production, improve processing, and facilitate market access, with particular focus on creating employment opportunities for young people.
The programme also envisages the construction and rehabilitation of tertiary roads, with the objective of improving population mobility and facilitating the transport and distribution of produce to local markets. Minister of Planning and Development Salim Valá said the initiative could help drive economic and social development in Cabo Delgado and unlock the region’s productive potential.
Jacinto Loureiro, ADIN Executive Commission President said the memorandum is aligned with national development policies and should contribute to the creation of new economic and employment opportunities for the populations concerned.
Network E&P, operator of the Qua Ibo field, onshore south east Niger Delta, was rattled by its encounter of only gas in Qua Ibo-5, the well it drilled and finalised in July 2026.
“We found gas and not the oil intended”, company sources say.
The company is not immediately drilling another well, as the drilling was only meant to be a one well-for-infill project. “We have to carefully interpret the result we just had”.
Network started production on the field in 2016, after drilling Qua Ibo -3 and Qua Ibo-4. Output had dropped from a peak of 2,000Barrels of Oil Per Day (BOPD) to below 1,000BOPD. The drilling of Qua Ibo-5 was intended to shore up the output.
Network won the Ebiya field (PPL 2A40) in Nigeria’s just concluded Bid Round 2025.
The Egyptian government has increased its target for refining and petrochemical projects by 30% to $5.2Billion.
The aim is to revamp and debottleneck existing refineries with new units for diesel and higher-value products, reducing import bill on diesel and Liquefied Petroleum gas (butane) from a crippling $6.2Billion in FY 2025/26, EnterpriseAM reports, quoting government sources.
Although Egypt holds one of the largest crude oil refining capacities in Africa, at around 700,000Barrels of Oil Per Day, many state-owned refineries historically operated below capacity due to technical bottlenecks and aging infrastructure.
The country’s Ministry of Oil anticipates $2.1Billion for plants that would convert fuel oil into diesel, gasoline, naphtha, and other products.
The Egyptian General Petroleum Corporation (EGPC) plans to set up a separate investment company with private investors to build them and has fielded preliminary approaches from Arab and international companies.
The Nigerian Electricity Regulatory Commission (NERC)’s dissolution of the Kaduna Electricity Distribution Company’s (KAEDC) board on August 10, 2026, is a stark reminder that privatisation is no silver bullet to service improvement when the underlying structural weaknesses of a utility remain unaddressed.
NERC attributed its action to “severe financial insolvency, with KAEDC accumulating over ₦118.6Billion [$88.77Million] in additional market debt under ASI Engineering Limited by May 2026, bringing total market obligations to approximately ₦456.5Billion [$341.69Million].”
The financial challenges at the heart of this insolvency translate into real world outcomes, given that distribution companies are customer facing, and responsible for recovering the revenue used to settle every participant in the electricity value chain.
The depth of KAEDC operational and financial freefall is significant. The DISCO, whose operations cover four states in Nigeria: Kaduna, Kebbi, Sokoto, and Zamfara, “remitted only 41.93% of its adjusted market invoices in 2025, recorded ATC&C losses of 71.88%, invested only ₦2.48Billion [$1.856illion] against a capital requirement of ₦24.51Billion [$18.35Million], and maintained customer metering coverage of less than 36%,” according to NERC. These numbers not only paint a picture of a utility in crisis, but also one buckling under its own weight.
ATC&C (Aggregate Technical Commercial and Collection) losses are the most consequential metric for assessing a utility’s health, because they capture the utility technical inefficiency, billing gap, billing collection failure and overall system performance. With ATC&C losses at 71.88%, KAEDC effectively earns ₦28.12 ($0.021) for every ₦100 ($0.075) worth of electricity delivered to its network. The severity of this is that, without public financials, it is clear the utility must be struggling to cover overheads, with little room for the capital investment needed to improve its operational and financial state.
Can the change of the board stop this hemorrhaging? Unlikely. A new board may steady the ship, but it cannot turn the corner without deep operational reform and infrastructure investment well beyond the meagre tenth of required capital KAEDC spent per NERC.
While KAEDC is in NERC’s crosshairs today, its operational and financial distress is far from unique. Across the industry, several DisCos exhibit similar troubling fundamentals: high ATC&C losses and persistently low metering coverage.
NERC data shows that ATC&C losses in the year 2025 stood at 61.19% for Yola DisCo, 62.15% for Jos, 44.63% for Kano, 44.29% for Benin, 42.93% for Ibadan, 40.55% for Enugu, 39.60% for Port Harcourt and 33.96% for Abuja. The outliers are Eko and Ikeja with significantly lower losses of 16.13% and 20.22% respectively.
Federal subsidy masks much of the remittance weakness across the DisCos, with the notable exception of KAEDC, where even subsidy cannot conceal the scale of the shortfall, according to NERC data. Eko, Ikeja and Port Harcourt DisCos are often adjudged top performers with perfect remittance. However, the gap between NBET (Nigerian Bulk Electricity Trading plc) invoices and actual payments remains substantial even among the better‑performing DisCos.
Ikeja Electric received ₦511.45Billion ($382.82Million) in NBET invoices and remitted ₦244.09Billion ($182.7Million) – 48%, leaving a ₦267.37 Billion ($200.13Million) shortfall covered by federal subsidy. Eko DisCo remitted ₦218.73 Billion ($163.72Million) against ₦450.65 Billion ($337.31Million) invoiced – 49%, with ₦231.91Billion ($173.59Million) subsidised. Port Harcourt DisCo paid ₦95.18Billion ($71.24Million) out of ₦243.55Billion ($182.30Million) billed – 39%, requiring ₦148.36Billion ($111.05Million) in subsidy.
Abuja DisCo received a total invoice of ₦519.06Billion ($388.52Million), remitting ₦240.69Billion ($180.16Million) – 46%, while the federal government covered the short fall of ₦278.37Billion ($208.36Million). Benin Disco paid ₦137.28Billion ($102.75Million) of its invoice of ₦316.02Billion ($236.54Million) – 43%, and the government covering the shortfall of ₦178.74Billion ($133.79Million).
Ibadan DisCo remitted ₦162.11 Billion ($121.34Million) out of ₦402.05 Billion ($300.94Million) billed – 40%, leaving ₦239.94 Billion ($179.60Million) unpaid. Enugu DisCo paid ₦117.14 Billion ($87.66Million) out of ₦283.55 Billion ($212.29Million) billed – 41%, leaving ₦166.42 Billion ($124.57Million) outstanding. Kano DisCo remitted ₦70.24Billion ($52.57Million) out of ₦188.76Billion ($141.29Million) billed – 37%, leaving ₦118.52Billion ($88.67Million) unpaid. Jos DisCo paid ₦65.71Billion ($49.18Million) of its ₦168.29Billion ($125.94Million) invoice, – 39% with ₦102.58 Billion ($76.77Million) subsidised. Yola DisCo paid only ₦15.49 Billion ($11.60Million) of its ₦88.89 Billion ($66.54Million) invoice – 17%, leaving a ₦73.40Billion ($54.95Million) shortfall.
The federal government subsidised the sector to the tune of ₦1.928Trillion ($1.44Billion), translating to about 57% of total invoices in 2025. These figures reveal the depth of structural insolvency across the DisCos, where actual remittances routinely fall below 50% of NBET billing without federal backstop, indicating how exposed the market is if subsidy is removed.
Metering across the DisCos remains a structural weakness. NERC data shows only Eko and Ikeja DisCos have achieved meaningful progress, at 85.87% and 86.40%, leaving gaps of about 13 – 14%. Abuja and Port Harcourt DisCos sit in the mid tier with gaps between 22 – 36%, while Benin, Enugu and Ibadan hover around a 46 – 48% gap. Jos, Kano and Yola recorded metering gaps above 64%. The implication is far reaching – the sector still struggles to determine consumption accurately, a foundational metric that drives ATC&C losses and undermines revenue recovery, despite the various existing metering framework by introduced by NERC.
The bottom line is clear: nearly 13 years after privatisation, the DisCos still struggle to deliver the service improvements the reform envisioned. While KAEDC’s board is the one that has recently faced the regulator’s hammer, the operational and financial performance of other DisCos is not materially better, as the remittance and metering data show.
This industry wide distress now intersects with a new regulatory landscape created by the Electricity Act 2023, which ends the era of NERC as the sole regulator and introduces a multi-tiered system where subnational governments now hold full authority over licensing, tariff setting and enforcement within their boundaries, while NERC retains overriding authority in certain jurisdiction.
In a market where DisCos were incorporated as natural monopolies under a single federal regulator, this decentralised framework raises critical questions: does the current corporate structure still make sense in a decentralised, state driven regulatory environment or should utilities be reorganised along state lines? If performance of DisCos remain weak across board, how long should existing investors hold these assets before the privatisation is revisited and more capable investors brought in?
With subsidy removal back on the table and the attendant sunset of federal backstopping, decision makers must now confront the old but unavoidable question over whether electricity in the country can continue to be treated as a social good or must now be priced as a commercial one.
The conversations, partnerships and investments shaping Africa’s energy future are coming to Cape Town from 12–16 October 2026 for African Energy Week (AEW) 2026.
Bringing together 300+ Ministers & VIPs, 400+ industry speakers, 1,500+ companies and delegates from 100+ countries, AEW 2026 will provide a platform for the continent’s energy leaders, investors and dealmakers to connect, collaborate and do business.
Delegates can expect:
High-level B2B & G2B matchmaking
Landmark deal signings and investment opportunities
Insights into licensing rounds, regulations and emerging energy markets
Exclusive networking receptions, power lunches and fireside chats
Direct engagement with Africa’s leading energy decisionmakers
Under the theme “Invest in African Energies: Affordable and Abundant Energy Additions,” AEW 2026 will focus on turning Africa’s vast energy potential into bankable projects, investment and tangible progress.
Will you be in the room where Africa’s next energy deals are made?
