Oil majors are responding to Ghana’s encouraging invitation to invest in the upstream”, Shell Ghana’s chief executive, Brian Mariuki, told Africa Oil+Gas Report.
“But the time that Ghana has is short”.
On September 1, 2026, the UK major, along with its American counterpart, Chevron, signed a non-binding preliminary agreement to acquire production rights for the South Deepwater Tano Cape Three Points (SDTCTP) block, a large tract covering approximately 3,482 square in 2,000 to 3,500 metre water depth. The SDTCTP houses an existing discovery, Nyankom, and was relinquished by AGM Petroleum in 2023.
The two companies are currently negotiating final license terms with the government, after which the operator will be decided.
Mr Mariuki is hoping that the timeline for reaching Petroleum Agreement can be fast tracked to below six months.
Mariuki acknowledged Africa Oil+Gas Report’searlierstory that Shell had shown some interest in Tullow Oil’s assets (Jubilee and TEN fields in the Deepwater Tano and West Cape Three Points), but he indicated that “the materiality” of the property was not worth the UK major’s time.
Shell cannot yet get on board the development of the Pecan field in Deepwater Tano Cape Three Points (DWT/CTP) block, operated by Pecan Energies (50%), as long as (the Russian player) Lukoil was involved, because of US sanctions. But Mariuki indicated that the government was looking for a way to handle the issue. The impression is that Final Investment Decision may be on hold for a little while more.
The Kenyan national, who has been with Shell for about 20 years, credits the current Ghanaian government for the renewed interest being shown by investors. “This didn’t happen for a long time”.
The Ghanaian government has proposed reducing state hydrocarbon company GNPC’s free carried state stake from 15% to 10% for new upstream projects. This policy shift requires a parliamentary amendment to Act 919.
This Geoscience & Technology themed edition addresses the subject in two ways. One is a return to our old haunt; describing some of the most functional tools currently in use in the subsurface evaluation toolbox. The other is an invited case study of a new discovery in one of Africa’s most consequential exploration basins.
When integrated, Petrel and Paleoscan, developed by SLB and Eliis respectively, provide a powerful end-to-end subsurface evaluation workflow, the Kickstarter reports. “Paleoscan rapidly extracts detailed stratigraphic information and high-resolution seismic surfaces, while Petrel transforms these outputs into robust geological and reservoir models for volumetric estimation, well planning, and production forecasting”.
Now let us go out to the field.
“Infrastructure-Led Exploration requires more than a new strategy”, JohnBosco Uche writes in a column in this edition. “It demands new ways of seeing and understanding the subsurface. To accelerate opportunity maturation and improve drilling success, Renaissance Energy identified technology as a critical enabler of the exploration transformation”.
Uche is the Vice President Exploration at Renaissance Energy, Nigeria’s largest hydrocarbon producing company. He is retailing the company’s strategy and success in the JK-P (JK-004) discovery well in Oil Mining Lease (OML) 74 in shallow water offshore central Niger Delta basin. “Modern exploration is increasingly a data and technology business. Renaissance therefore prioritises seismic acquisition, advanced processing and AI-enabled workflows to improve subsurface imaging, reduce uncertainty and accelerate decision-making”.
The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid subscription, monthly e-copy publication delivered around the world. Its website remains www.africaoilgasreport.com, and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.
Ghana’s update of its 2019 Renewable Energy Master Plan (REMP) to the Renewable Energy Master Plan 2026 – 2030 demonstrates a renewed commitment to expanding renewable energy deployment, particularly as the successful implementation would move Ghana closer to achieving its energy and climate goals.
The 2019 plan aimed to “increase the proportion of renewable energy in the national energy generation mix from 42.5 MW in 2015 to 1,363.63 MW (with grid connected systems totalling 1,094.63 MW)”. It also sought to “reduce the dependence on biomass as main fuel for thermal energy applications”. It also set out to “provide renewable energy-based decentralised electrification options in 1,000 off-grid communities” and “promote local content and local participation in the renewable energy industry”.
The 2019 plan was designed for implementation over a 12-year period, beginning in 2019 and ending in 2030, through three implementation cycles. The first cycle, intended to serve as the transition phase, was to run between 2019 and 2020, while the remaining two cycles covered the periods 2021 – 2025 and 2026 – 2030, respectively.
Under the 2019 plan, renewable energy deployment spanned solar, wind, biomass and hydropower technologies in different use cases, such as lighting, irrigation, and other industrial and residential applications.
The overarching goal of the updated plan remains the same.
The implementation record of the 2019 plan provides a useful basis for assessing how attainable the new plan is. The question, then, is what has changed since 2019, and how much of the targets in the updated plan can realistically be achieved by its 2030 end date?
The update is not an afterthought. The 2019 REMP made it clear that each execution cycle would be “reviewed in the last year of implementation and the outcome used to improve the implementation of the next cycle”.
The REMP 2026 – 2030 plan is informed by the 2019 REMP “and reflects lessons learned, evolving national priorities, and emerging global trends”.
The test case for the 2019 plan in this piece is limited to solar and wind deployment. Given the two technologies are at the core of the REMP’s ambition to scale the contribution of renewables to the grid.
The updated plan provides a scorecard of the implementation so far. The first two-implementation cycles of the 2019 plan recorded relative success in interventions targeted at household levels, such as biomass cook stoves, but the same cannot be said for utility-scale solar and wind systems. By the end of second implementation cycle, the target was for utility-scale solar deployment to reach 347.5MWp (Mega Watt-peak). However, actual deployment stood at 183.1MWp representing 53% of the target.
While progress in utility-scale solar is behind, the plan has recorded stronger performance in distributed solar photovoltaic (solar power systems installed on rooftops of homes, commercial, industrial, and institutional buildings at or near the point where the electricity is consumed). Deployment in this case reached 86MWp against a target of 100MWp capacity, marking an 86% progress.
The target of 275MWp for utility-scale wind at the end of 2025 implementation cycle recorded no progress with actual deployment at 0%.
The updated plan has a new target for utility-scale solar and wind. With utility-scale solar and wind targets of 852MWp and 709MWp respectively for the 2026 – 2030 implementation cycle requiring estimated investments of $631Million and $999Million, the updated plan without doubt is ambitious. The question now is whether the updated plan is yet another exercise where ambitious targets will outpace actual deployment, or whether the lessons learned from the first seven years of implementation can provide the springboard to achieve these new targets. The investment required to achieve the 2026 -2030 targets makes this highly unlikely.
For instance, the 2019 REMP projected a total investment requirement of $5.6Billion over its entire implementation period. The updated plan now estimates an investment requirement of $10.8Billion for the 2026 -2030 implementation cycle alone. With the investment requirement for the final implementation cycle now almost double the amount envisaged for the entire plan in 2019, what is the likelihood of mobilising this additional capital, when financing was already a constraint during earlier implementation cycles?
While financing and technical constraints was identified as impediments to the implementation of the 2019 plan, because of its dependency on private capital and donor support over which Ghana has limited control, the country has not made much progress on areas that are firmly within its control – the establishment and operationalization of necessary institutions. The promise of the establishment of the Renewable Energy Authority from the 2019 plan is still a work in progress. The absence of this agency has been attributed to the non-operationalisation of the Renewable Energy Fund. The goal of the Fund “is to provide financial resources for the promotion, development, and sustainable management and utilisation of renewable energy sources”. Similarly, a REMP Coordinating Unit is still yet to be created. The updated plan attributes this “to lack of clarity on its positioning and leadership — whether it was to be situated within the MoEn> [Ministry of Energy and Green Transition] or the Energy Commission”. This in turn hindered the operationalisation of the monitoring, evaluation, and learning framework, thereby creating gaps in data gathering and reporting during the preparation of the updated plan, as noted in REMP 2026 – 2030.
The evidence from Ghana’s updated REMP 2026 -2030 presents a mixed picture. Success has been recorded in distributed solar, while utility-scale scale solar has made measurable progress. In contrast, utility-scale wind is yet to take flight, raising questions about the feasibility of achieving the new target of 709MWp during the final implementation cycle spanning 2026 – 2030. Progress on establishing institutions required to drive the implementation has also been slow, underscoring the urgency attached to achieving the plan’s objectives.
The updated plan will therefore be tested by whether the lessons learned translate to accelerated deployment of planned technologies, or whether the targets will again outpace implementation. Ultimately, the final implementation cycle will reveal whether the story of the Renewable Energy Master Plan 2026 – 2030 is one of failing forward, or repeating old promises.
Adeniyi Adeoloye, a petroleum geoscientist based in Calgary, is in a postgraduate course on Energy Management at the University of Calgary. An editorial associate of Africa Oil+Gas Report, Adeoloye writes from time to time for this platform and can be reached at adeniyi@africaoilgasreport.com.
The General Public, International Lender Banks, Energy Sector Regulators, and Joint Venture Partners
RE: FRAUDULENT PUBLIC NOTICE AND SUB JUDICE MEDIA MISREPRESENTATION REGARDING THE OWNERSHIP AND SHAREHOLDING OF CHAPPAL ENERGIES MAURITIUS LIMITED / CHAPPAL ENERGIES
TAKE NOTICE that TUNJI BRAITHWAITE LAW PARTNERS acts as Legal Representatives to MR. UFOMA JOSEPH IMMANUEL and INTERMEDIATE INVESTMENTS HOLDINGS LIMITED (IIHL) in respect of the ongoing corporate shareholding, governance, and equity disputes involving CHAPPAL ENERGIES MAURITIUS LIMITED.
Our attention has been drawn to a malicious, false, and deeply misleading publication featured on your online news platform, Africa Oil + Gas Report, dated 24th September 2026, under the caption:
“Adebisi Adebutu is Now the Owner of Chappal Energies”
We hereby issue this formal PUBLIC NOTICE, LEGAL DISCLAIMER, AND CEASE & DESIST DIRECTIVE to set the record straight and protect the international market, financial institutions, and industry stakeholders from being deceived by calculated corporate propaganda.
ABSOLUTE DISCLAIMER OF OWNERSHIP CLAIM
The claim that “Adebisi Adebutu is now the owner of Chappal Energies” is FALSE, FRAUDULENT, UNLAWFUL, AND TOTALLY DESTITUTE OF ANY LEGAL EFFECT.
Neither Mr. Adebisi Adebutu nor R28 Limited possesses sole or majority lawful ownership of Chappal Energies Mauritius Limited. The purported rights issue, share dilution, and corporate restructuring referenced in your article are the subject of intense, unresolved legal challenge and are entirely VOID AB INITIO under extant corporate laws and international arbitration rules.
2. NOTICE OF PENDING LITIGATION AND ARBITRATION (SUB JUDICE)
The public, international financial institutions, compliance officers, and industry operators are hereby formally notified that the equity structure, management control, and beneficial ownership of Chappal Energies Mauritius Limited are currently the subject of active, binding, and contested legal proceedings across multiple judicial and arbitral forums, including but not limited to:
LCIA ARBITRATION (LONDON): International arbitration proceedings formally commenced under the Rules of the London Court of International Arbitration (LCIA) challenging the illicit dilution, breach of fiduciary duties, and fraudulent equity expropriation.
REGULATORY COMPLAINTS (MAURITIUS FSC): Pending formal investigations before the Financial Services Commission (FSC) of Mauritius regarding corporate governance infractions, unauthorized share allotments, and regulatory misrepresentations.
FEDERAL HIGH COURT OF NIGERIA AND NATIONAL INDUSTRIAL COURT OF NIGERIA: Active, subsisting lawsuits including Suit No: FHC/LAG/CS/87/2026 and SUIT NO: NICN/LA/107/2026, related commercial actions wherein the courts have issued binding interlocutory mandates to preserve the status quo.
Under the doctrine of sub judice, any attempt by Mr. Adebisi Adebutu, R28 Limited, or media proxies to unilaterally declare a change in corporate ownership while these courts and tribunals are actively seized of the matter constitutes an unlawful interference with the administration of justice and an act of contempt.
3. WARNING TO INTERNATIONAL LENDER BANKS & REGULATORS
All international lender syndicates, trade finance banks, institutional investors, and regulatory agencies (including NUPRC and NNPC Limited) are strongly advised to exercise extreme due diligence:
No Reliance: Any financial facility, asset pledge, farm-in/farm-out transaction, or commercial agreement executed on the reliance of Mr. Adebisi Adebutu’s claim of sole ownership or control of Chappal Energies is executed at the third party’s sole peril and remains subject to immediate legal set-aside and clawback.
Status Quo: The legitimate equity, board representation, and executive authority of MR. UFOMA JOSEPH IMMANUEL remain protected under active judicial and arbitral scrutiny.
DEMAND FOR IMMEDIATE RETRACTION AND CEASE & DESIST In view of the foregoing, TUNJI BRAITHWAITE LAW PARTNERS hereby demands that the Editorial Board of Africa Oil + Gas Report immediately:
PULL DOWN & RETRACT: Permanently remove the defamatory, false, and sub judice publication titled “Adebisi Adebutu is now the owner of Chappal Energies” from your website and all affiliated social media handles within TWENTY-FOUR (24) HOURS of receiving this notice.
PUBLISH AN EQUAL UNQUALIFIED RETRACTION: Issue a prominent public disclaimer on your platform acknowledging that the ownership and equity structure of Chappal Energies Mauritius Limited remain sub judice and subject to active LCIA arbitration and Federal High Court litigation.
CEASE AND DESIST: Cease and desist from publishing further unverified, biased, or sponsored narrative leaks designed to prejudice ongoing judicial proceedings and mislead the international energy market.
TAKE FURTHER NOTICE that should you fail, refuse, or neglect to comply with these demands within the stipulated 24-hour window, our clients have given us strict instructions to join Africa Oil + Gas Report, its publishers, and editors as co-defendants/respondents in pending court actions for libel, commercial disparagement, and intentional interference with contractual relations, seeking exemplary damages and punitive costs.
DATED THIS 24TH DAY OF SEPTEMBER 2026.
FOR AND ON BEHALF OF:
TUNJI BRAITHWAITE LAW PARTNERS
Plot 34 Kudirat Abiola Way, Ikeja, Lagos, Nigeria
Email: legal@tblp.ng / info@tblp.ng
OLAOLUWA BRAITHWAITE, ESQ.
Principal Partner
The Financial Services Commission (FSC), Mauritius
The Registrar of Companies, Corporate Affairs Commission (CAC), Nigeria
Africa’s energy investment gap is increasingly being addressed through a broader pool of African financial institutions, regional lenders and private investors. With the continent’s energy finance gap estimated at between $31 billion and $50 billion, the ability to turn available capital into bankable projects is becoming a central issue for governments and developers.
African Energy Week (AEW) 2026, taking place October 12–16 in Cape Town, will put that challenge at the heart of its Energy Finance Forum.
The growing role of African institutions is reflected in AEW 2026’s partner lineup. The Africa Finance Corporation (AFC) joins as a Gold Partner after deploying capital across refining, transport, power and upstream projects. Its assets have surpassed $19 billion, while its 2026 transactions include a $2.5 billion private placement for the Dangote Petroleum Refinery and financial close on the $753 million Lobito Corridor Railway Project. AFC has also raised $2 billion through a syndicated loan this year, demonstrating the scale of financing now being mobilized by African institutions themselves.
Afreximbank is similarly expanding its role in energy financing, including through the Africa Energy Bank, which was established with the African Petroleum Producers’ Organization to help address the funding constraints facing African oil and gas projects. AEW 2026 will provide a platform for African financial institutions to engage directly with developers seeking capital for upstream, midstream, power and industrial projects.
The agenda moves from the question of who can provide capital to how that capital can be structured. “Financing Energy at Scale: How Developers, DFIs, and Private Capital Are Funding Africa’s Landmark Infrastructure Projects” will examine domestic capital pools, private and institutional investment, public-private partnerships and financing across borders. The session features the World Bank alongside White & Case and Premier Invest, bringing together development finance, legal structuring and investment perspectives.
For frontier oil and gas developments, “De-risking Petroleum Exploration & Production” will examine financing structures and fiscal reforms aimed at improving project economics and unlocking early-stage exploration. The “Investment Case for African Gas: Risk, Returns and Financing Structures” will address another critical challenge: how developers can make gas projects sufficiently bankable to attract new sources of funding as traditional Western lenders become more selective
Infrastructure finance will extend beyond individual projects. The session “The Path Towards Establishing Bankable and Interconnected Electricity Markets Across Africa” will examine reforms needed to attract investment into power systems while addressing cross-border electricity trade and regional integration. Meanwhile, “PSP in Transmission & Digitalizing Africa’s Power Grids” will focus on innovative financing models for private investment in transmission infrastructure.
The financial agenda reflects a wider shift in Africa’s investment landscape, with development institutions, domestic capital pools and regional investors increasingly positioned alongside international banks and funds. As the continent seeks to finance everything from frontier exploration and gas infrastructure to interconnected power markets, AEW 2026 will focus on the structures, partnerships and institutions capable of moving projects from opportunity to financial close.
“Africa’s energy ambitions require capital that can move beyond balance sheets and into bankable, transformative projects,” said NJ Ayuk, Executive Chairman of the African Energy Chamber. “Bringing leading finance professionals to AEW 2026 will help connect investors, institutions and energy opportunities while ensuring African resources generate greater value for African economies.”
Men with guns have returned to determine how much of Libyan crude gets to the market.
The action of the last 60 hours has been the most disruptive in 18 months.
On September 15, 2026, protesting Petroleum Facilities Guards (PFG) guards closed a pipeline valve in the Hamada region, forcing a complete halt at the Hamada, Tahara, and NC5 fields.
Six days later, September 21, 2026, they closed the valve No 7 on the pipeline from the major (~300,000Barrels of Oil Per Day (BOPD)) Al-Sharara oilfield to Zawiya port, cutting output by about half.
One consequence of this was the shutdown of the country’s main oil refinery, which put Tripoli’s primary fuel supply at risk and threatened roughly one-quarter of the country’s total oil production of around 1.4Million barrels per day.
Libya’s National Oil Corporation (NOC). said that the Sharara-Zawiya crude loading pipeline closure has led to daily losses of about 130,000BOPD.
Despite the closure of the Zawiya oil refinery, the country’s second-largest, access to the Brega Petroleum Marketing Company, which runs the refinery, was partially granted, the NOC said.
It is often the case that these shut downs happen at the behest of warlords, but the official statement says that the guards carried out the shutdown in protest, over financial demands.
The year 2026 in Libya has been worse than the previous year in terms of challenges to hydrocarbon production. In 2025 the country achieved its highest annual oil output in 12 years, averaging 1.37MillionBOPD. It has improved on that in 2026, but fitfully so, as September 2026 incidents indicate. In contrast, 2025 was marked by a relative de-escalation of hostilities.
The NOC said the current shutdown could lead to “a complete paralysis of operations at the complex,” affecting fuel supplies and public revenues.
French major TotalEnergies (40%, operator), together with its partner AMNI (60%), have taken the Final Investment Decision (FID) for the development of the Ima gas field, straddling the Oil Mining Leases(OMLs) 112 and 117 offshore licenses in Nigeria.
Located in shallow waters close to Bonny Island, the Ima gas field will be developed with a single platform, connected through a 22 kilometre pipeline to Nigeria LNG (15%, TotalEnergies).
Production start-up is expected in 2028, with a plateau of 350Million cubic feet per day (representing over 60,000 barrels of oil equivalent per day). Once on stream, the Ima field will supply about one-third of the gas required for the ongoing Nigeria LNG Train 7 expansion project, which will increase the liquefaction plant capacity from 22Mllion tons per annum (MMTPA) to 30MMTPA
“Ima is a low-cost and low-emissions development, with a simplified platform design, electric power supply from shore, no flaring, and permanent methane detection and monitoring”, TotalEnergies says in the statement.
The company explains that the project, developed in partnership with the Nigerian company AMNI, “is characterized by strong Nigerian content, with all key contractors being local companies”, with around 60% of the workforce expected to be sourced from host communities during the project development.
“After the Ubeta project, sanctioned in 2024 and expected to start-up next year, Ima demonstrates again our ability to unlock new low-cost and low-emissions gas resources, following the incentives introduced by the Nigerian Government for non-associated gas developments”, saidNicolas Terraz, President Exploration & Production at TotalEnergies.
Ghana’s upstream industry is back in the spotlight. So far in September 2026, the country has signed three upstream Memoranda of Understanding (MoUs) with international oil companies (IOCs): Shell and Chevron, and ENI. This is particularly important because, in Ghana’s upstream landscape, an MoU mostly precedes a Petroleum Agreement (PA), subsequent work programmes and, ultimately, barrels.
For a country whose oil production has been declining for some time, the appeal of the MoUs is obvious. Total oil production in 2025 stood at 37.3Million barrels (MMbbls), a 22.67% plunge from 48.24MMbbls in 2024, while gas production slipped 2.4% to 273.78Bcf from 280.51Bcf over the same period, according to data from Ghana Upstream Petroleum Chamber.
Against this backdrop, there is no doubt about the belief that this new wave of MOUs holds the key for production revival, if the signed understandings translate into PAs, work programmes encompassing data acquisition and drilling, commercial discoveries, and eventually first oil. The optimism is understandable, given the deep pockets and technical credentials of the majors involved. Then again, this would not be Ghana’s first rodeo with MoUs.
Since Ghana upstream sector emerged with the start of production from the Jubilee field in 2010, MoUs have featured in the entry of oil and gas companies into the country’s upstream industry. The record of these understandings since then provides a basis to assess how previous MoUs have translated into Petroleum Agreements (PAs), exploration activity, discoveries and barrels, and whether the enthusiasm surrounding the current wave can go beyond expectations and materialise into production.
Ghana’s Petroleum (Exploration and Production) Act, 2016 (Act 919), provides the legal basis for the award of a PA. Under the Act, a PA can be awarded through “an open, transparent and competitive public tender process” or by “direct negotiations”. Regardless of the mechanism, it is mandatory that a PA is ratified by Ghana’s parliament to become effective.
This distinction is important because an MoU is not a PA, and does confer the same rights under the law. Unlike a PA which grants the holder the right to “engage in the exploration, development and production of petroleum”, an MOU is only a step in a much longer journey that may lead to petroleum agreement, exploration activity, and eventual first oil.
September 2026’s MoU signings covers three blocks across Ghana offshore basins. Shell and Chevron signed an MoU with Ghana National Petroleum Corporation (GNPC) in the South Deepwater Tano block. ENI, in partnership with Vitol Upstream Tano Ltd, also inked two MoUs for GH WB_3 and GH_W8 blocks, offshore Tano basin. The Shell-Chevron MoU relates to an acreage previously held by AGM Petroleum and is distinguished by an existing discovery, Nyankom, rather than being a pure frontier block. The block was relinquished in 2023.
While the three MoUs signed in September 2026 leave room for confidence, particularly given the credentials of the companies involved, recent experience suggests caution. One of the two blocks in the ENI – Vitol signed MoU, GH-WB3, was previously awarded to the same partners in 2019 following Ghana’s 2018 licensing round. An MoU for block GH_WB_3 was signed in 2019, but it never progressed into a PA and eventually lapsed in 2023. The expiration of ENI’s 2019 MOU is particularly noteworthy given that ENI is already an established producer in Ghana, with net equity production of 40,000Barrels of Oil Equivalent per day (BOEPD). Yet the operational record and in-country presence did not prevent the 2019 MoU from expiring without progressing into a PA. Perhaps ENI could not reach an amicable understanding with authorities in Ghana then?
Even more telling is the case of ExxonMobil. In 2015, Ghana signed an MOU with the American major for the Deepwater Cape Three Points block. Unlike companies seeking to accumulate paper barrels or warehouse acreage, ExxonMobil’s operational record and global portfolio gave credibility that the MoU could lead to significant upstream activity. The Exxon MOU morphed to a PA in 2018, and secured parliamentary ratification in 2019. It is important to note that the ExxonMobil MoU was signed before the Petroleum (Exploration and Production) Act 2016 came into force. According to the Petroleum Agreement, this complicated the negotiations before all parties eventually reached a compromise.
Under the terms of agreement, ExxonMobil committed to undertake a minimum work programme which include to “acquire, process and interpret 2,222 square kilometres of three dimensional (3D) seismic data; drill one (1) exploration well (optional)” in the initial exploration period (two and half years from the date of the agreement). Alongside a minimum capital expense of $20Million. Yet the PA did not live to see the subsequent commitments beyond the initial phase as the block was relinquished in 2021. No exploration well was drilled nor subsequent programmes attained. Exxon held 80% interest in the block, with GNPC holding 15%, and Ghana Oil Company Limited the remaining 5%. In other words, despite progressing from MoU to PA, the acreage did not translate to barrels or production.
The above cases have shown that neither financially and technically heeled companies such as ExxonMobil and ENI, nor an independent player like Norway AGM Petroleum, were able to beat the odds. AGM Petroleum’s case is particularly interesting given that it had made a discovery. The question, perhaps best answered by industry insiders or parties to the agreement, is what could have led to AGM Petroleum and ExxonMobil to walk away? Because in ENI’s case, the issue was different, as the MoU it signed in 2019 simply expired without progressing into PA.
If there is anything to learn from the past, it is that these MoUs represent opportunities rather than guaranteed barrels or production. Their real significance would be determined on what follows, that is: the signing of Petroleum Agreements, execution of work programmes, exploration activity, appraisal, and ultimately first oil.
Expectedly, the current wave of MoUs offers room for hope. However, recent records suggests that eventual barrels would come from work commitments and execution that follows the MOU, and not from the announcement itself.
In the oil business, price can make almost everyone look better than they really are. Rising prices strengthen cash flow, flatter margins and return previously marginal projects to corporate presentations. Governments see stronger revenues. Operators rediscover confidence.
But price can also conceal weakness. It can disguise declining reservoirs, unreliable infrastructure, delayed approvals and projects whose economics survive only while the market remains unusually tight. Oil’s return above US$100 should therefore be treated not simply as good news for Africa, but as an execution test.
The immediate cause is clear. Conflict and infrastructure disruption in the Middle East have constrained one of the world’s most important energy corridors. In its September 2026 assessment, the International Energy Agency reported that oil flows through the Strait of Hormuz averaged 7.6Million barrels per day in August, 13.1Million barrels per day below pre-conflict levels. Global inventories had fallen by 507Million barrels since the conflict began, despite the release of 400Million barrels of emergency stocks by IEA member countries.
Yet scarcity is only one side of the market. The IEA also estimates that global oil demand over the past six months averaged 5.8Million barrels per day below its February level as high prices, shortages and weaker economic activity suppressed consumption. It expects demand to contract by 2.5Million barrels per day this year. The cure for high prices may therefore be high prices themselves.
“Africa does not need to argue that the energy transition has ended. It has not. The stronger case is that a changing energy system still requires secure oil and gas supply, and that African projects capable of meeting competitive cost, governance and emissions standards deserve capital.”
That is why African producers must not confuse a moment with a cycle. An offshore project sanctioned today may not deliver first oil for several years. By then, supply routes may have reopened, demand may have weakened further and financing conditions may have changed. $100 oil improves project economics, but it does not remove project risk.
The disruption nevertheless creates strategic space for geographically diversified supply. Africa possesses material reserves, underexplored basins and established petroleum systems. The opportunity, however, is not uniform. Mature producers must arrest decline and improve reliability. Emerging producers must convert discoveries into bankable developments. Frontier jurisdictions must establish regulatory and geological credibility before capital will arrive at scale.
There are encouraging signals. Nigeria added about 200,000 barrels per day of supply between February and August, according to the IEA. The Nigerian Upstream Petroleum Regulatory Commission also reported that 31 companies emerged as winners of 37 oil and gas blocks after 143 companies submitted 200 bids. In Côte d’Ivoire, Petrobras has signed production-sharing contracts for eight offshore blocks, taking a 90 percent operating interest alongside Petroci, while examining opportunities elsewhere in Africa.
These decisions largely pre-date the latest price surge, but the supply shock increases their strategic significance. It also raises the standard by which they should be judged. The prize is not acreage awarded or agreements signed. It is hydrocarbons discovered, financed, developed and reliably produced.
That distinction matters particularly in Nigeria. A licensing round is successful only when credible financing becomes seismic acquisition, wells, development approvals and production. NUPRC’s drill-or-drop warning is therefore important. It signals that acreage should be governed by performance rather than possession. But regulatory firmness must be matched by regulatory speed. Approval delays defer cash flow, inflate costs and consume licence terms without adding a barrel.
Investors will look beyond the headline price. They will test break-even costs against conservative price assumptions and scrutinise decline rates, infrastructure uptime, evacuation reliability, fiscal stability, decommissioning liabilities and access to finance. They will ask how quickly reserves can be converted and whether the operator can absorb delay, cost escalation and community disruption.
Strong markets create their own pressures. Rigs, vessels, equipment and specialist personnel become more expensive. Consumers demand insulation from rising pump prices. Governments may feel entitled to capture more of the windfall, while operators may postpone difficult restructuring because price has temporarily repaired the income statement.
Governments should avoid opportunistic fiscal changes during an upswing. Where terms genuinely require revision, changes should be transparent, prospective and designed to preserve investor confidence. Regulators should enforce work programmes while ensuring that commercially sound projects do not become stranded in administrative queues.
Operators also face a choice. Stronger cash flow can fund distributions, or it can reinforce the foundations of production through well interventions, asset integrity, debottlenecking, pipeline reliability, reserves replacement and security. Shareholder returns matter, but cash flow is not the same as operating capacity.
For indigenous companies holding larger portfolios as international companies reshape their African positions, ownership must now be matched by capital, governance and technical depth. High prices can carry weak structures for a time. Lower prices reveal them.
The crisis carries a parallel gas lesson. The IEA estimates that about one-fifth of global LNG trade passed through the Strait of Hormuz in 2025. This strengthens the strategic case for gas projects from Nigeria and Senegal to Mozambique and Mauritania. But Africa will need more than resources and announcements. It needs bankable commercial frameworks, processing capacity, pipelines, creditworthy buyers and a balance between exports and domestic industrial demand.
The quality of Africa’s response can be measured. What conservative price deck are boards using to sanction projects? How long does it take to move from award or discovery to final investment decision? What proportion of committed capital becomes seismic work, wells and facilities? How much production is lost to infrastructure failure and avoidable deferment?
Those measures will reveal whether the present windfall is building productive capacity or merely improving short-term accounts.
Africa does not need to argue that the energy transition has ended. It has not. The stronger case is that a changing energy system still requires secure oil and gas supply, and that African projects capable of meeting competitive cost, governance and emissions standards deserve capital.
The current shock has reminded the world that energy security cannot be assumed. It has given Africa an opening, but not an entitlement. Oil above $100 can deliver a windfall. Lasting value will depend on whether the continent converts price into performance before the market turns again.
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.
The Ugandan geologist and banker, Fred Kabanda has been appointed as the Executive Director of the Petroleum Authority of Uganda.
He succeeds longtime chief Ernest Rubondo, who retires at 75 after 10 years of two five year terms. Mr. Rubondo’s name has been synonymous with the country’s sole oilfield development, the largest onshore greenfield upstream project in Africa, in its pivotal years between 2016 and 2026.
Otonga Ochan will serve in the interim until Mr. Kabanda fully takes over on December 1, 2026, following the successful conclusion of the recruitment and onboarding process.
A trained geologist who has been the Division Manager in charge of extractive resources at the African Development Commission in Abidjan, since 2016, Kabanda is expected to superintend, from the regulatory point of view, the inauguration of the Lake Albert basinwide development, expected to reach first oil in June 2027.
“Mr. Kabanda brings extensive experience in Uganda’s petroleum sector, having served in both technical and leadership roles in the Ministry of Energy and Mineral Development and the African Development Bank over the last thirty (30) years”, a statement by the board of directors of the Petroleum Authority of Uganda, said.
