SLB, the company formerly known as Schlumberger, has announced the opening of a new fluids systems plant in Pemba, Mozambique.
With an initial storage capacity of 21,000 barrels, the plant, also known as a liquid mud plant, “strengthens in-country capacity to prepare, store and deliver drilling and completion fluids for offshore operations, reinforcing the infrastructure needed as Mozambique’s offshore activity grows and its role as a strategic energy hub for East Africa continues to expand”, SLB says in a statement.
Mozambique is currently playing host to two natural gas development projects which involve drilling. TOTAL, the French hydrocarbon major is constructing an onshore 13Million Tonnes Per Annum (MMTPA) Liquefied Natural Gas facility whose feedstock will be natural gas piped from development wells being/to be drilled in offshore Area 1 in deepwater Rovuma Basin. ENI is installing a 3.4MMTPA Floating LNG vessel to be supplied by similar wells from adjacent Area 4. Meanwhile, ExxonMobil is preparing to launch an onshore 18MMTPA project that will require several gas wells from Area 4.
SLB’s 21,000 barrels liquid mud plant, the company says “provides a scalable platform for future growth, supporting multiple customers and rising offshore activity while improving logistics and enhancing operational flexibility”.
Miguel Baptista, Central, East and Southern Africa, Managing Director, SLB adds that the new liquid mud plant “strengthens local energy infrastructure, expands opportunities for local content development, and enhances our ability to support customers as they deliver some of Africa’s most significant offshore energy resources.”
The proposed Dangote East Africa refinery in Lamu could strengthen Africa’s energy self-sufficiency if it is integrated into a functioning regional supply system. At the groundbreaking on 30 September 2026, the project was presented as a $16Billion investment with planned capacity of 700,000 barrels per day, a 1,000 MW power plant and completion targeted for 2030.[1] The central question is how this investment could help Africa process more of its resources and retain more of their value. Here, regional energy self-sufficiency means strengthening the collective capacity to produce, process and deliver energy, rather than eliminating all imports.
Africa’s resources have not consistently translated into energy security. In April 2025, Afreximbank put annual petroleum import costs associated with inadequate refining at approximately $30Billion.[2] The African Development Bank reported in 2026 that 43 of Africa’s 54 countries were net importers of crude oil and petroleum products.[3] Exporting crude while importing finished fuel leaves economies exposed to external supply disruptions and foreign-exchange pressures, with consequences for transport, agriculture and industry.
The Disparity Between Ambition and Capacity
Refinery projects show how difficult it can be to turn resource ownership into productive capacity. In April 2025, Sonangol was seeking to close a $4.8Billion funding gap for Angola’s planned 200,000-barrel-per-day Lobito refinery. In February 2026, it was pursuing a $4.8Billion loan from Chinese institutions.[4] Yet Angola also made progress; the first phase of the Cabinda refinery was inaugurated in September 2025, with initial processing capacity of 30,000 barrels per day and $335Million in financing from a consortium including Africa Finance Corporation (AFC) and Afreximbank.[5] Uganda’s proposed 60,000-barrel-per-day refinery provides another example of East Africa’s ambition to process crude domestically.[6]
These projects face construction risk, currency exposure and years of expenditure before revenue begins. A bank financing fuel imports may recover its money within months; a refinery investor takes a much longer view. The question for African capital is whether it can assume more of this industrial risk while continuing to support the trade and distribution on which markets depend.
Dangote’s Nigerian refinery illustrates the importance of committed sponsors working with lenders and development institutions. Dangote Industries secured a $3.3Billion syndicated loan in 2013, a decade before Nigeria announced the removal of petrol subsidies in May 2023.[7] AFC provided an early US$300 million senior loan and, in August 2026, led investors in a $2.5Billion private placement.[8] The lesson is the willingness to commit capital amid uncertainty, supported by institutions capable of carrying a project from development to operation.
Lamu’s Role in East Africa’s Energy System
Kenya’s import dependence gives the proposal a substantial domestic market. The Kenya National Bureau of Statistics (KNBS) 2026 Economic Survey records petroleum demand of approximately 5.7 million tonnes in 2025 and a petroleum import bill of KSh528.8Billion (Kenyan shillings).[9] The proposed refinery is intended to serve Kenya and wider East African markets. These domestic figures alone do not establish demand for the proposed capacity; regional demand and committed buyers must also be assessed. A refinery of the proposed scale in Lamu could significantly reshape this infrastructure landscape. Kenya could reduce its reliance on imported finished fuel and develop into a major hub for processing and distribution, provided it has competitive supply and viable regional connections.
Reconceptualising Energy Self-Sufficiency
Regional self-sufficiency need not require every country to build every part of the energy value chain. Uganda could contribute crude production, Kenya refining and port services, and neighbouring economies storage, distribution and demand, subject to viable supply agreements. Electricity trade through regional power pools could complement petroleum trade. This reframes the policy objective from national self-sufficiency to regional productive integration. The more relevant question becomes whether African economies can collectively expand their capacity to produce, process, transport, and trade a greater proportion of the energy products they require. In my view, this approach could offer a more economically viable and institutionally realistic model, provided supply agreements, infrastructure and cross-border arrangements are workable.
From Extraction to Value Addition
For decades, Africa’s economy has grappled with its position within global value chains. The continent exports significant quantities of crude oil, minerals, and agricultural products but often imports higher-value manufactured goods derived from these same resources. A domestic and regional refining strategy has the potential to alter this position in the value chain. The proposed investment could strengthen a value chain in which African crude is refined within Africa and supplied to African markets. The economic activities associated with a refinery extend far beyond its immediate operations, necessitating engineering, construction, logistics, storage, pipelines, ports, maintenance, technology, security, professional services, financing, insurance, and skilled labour. Additionally, it can supply products such as aviation fuels and support downstream industries, including petrochemicals, plastics, fertilisers and industrial manufacturing, where suitable feedstocks, processing facilities and additional investment are available. Thus, the true importance of Lamu should be assessed not solely by the volume of barrels processed but by the industrial ecosystem that could develop around it.
The AfCFTA Opportunity
The African Continental Free Trade Area (AfCFTA) offers a framework for expanding regional markets, but fuel trade also requires workable customs procedures, compatible product standards and dependable transport. Afreximbank’s $3Billion Revolving Intra-African Oil Trade Financing Programme, launched in April 2025, supports purchases from African refineries. The bank expected it to finance US$10Billion to $14Billion in intra-African petroleum imports.[2]
This facility is consequential because refinery construction alone does not ensure the development of an integrated regional fuel market. Additional components such as financing, shipping, storage, pipelines, rail and road infrastructure, compatible product standards, and commercial agreements are essential for ensuring the efficient movement of fuel across African borders. Infrastructure developed without corresponding trade arrangements, logistics networks, and market access risks becoming an isolated asset rather than part of a productive regional system. Lamu’s location is also noteworthy, as the port is part of the larger Lamu Port–South Sudan–Ethiopia Transport (LAPSSET) corridor, which aims to enhance connectivity between Kenya, Ethiopia and South Sudan.[10] The corridor’s planned connections should not be treated as infrastructure already available to the refinery. If the refinery can be successfully integrated with storage, port, pipeline, and transport infrastructure, its impact could extend well beyond Kenya’s borders.
Existing Supply Chains in East Africa
East Africa already has infrastructure and commercial relationships that Lamu could build on. Kenya Pipeline Company’s (KPC) network moves petroleum products from Mombasa to Nairobi and western depots, including Nakuru, Eldoret and Kisumu, serving Kenya and neighbouring markets. In October 2024, KPC reported that its Nairobi–Eldoret pipeline upgrade increased flow capacity from 330 to 515 cubic metres per hour.[11] This is evidence of an operating corridor being expanded to meet demand.
The Kisumu–Entebbe link shows how different transport modes can work together across borders. KPC says its Kisumu Oil Jetty became operational on December 29, 2022 after completion of the receiving facility at Entebbe, and estimates that the lake route is approximately $5 per cubic metre cheaper than road transport.[12] The combination of pipeline supply and lake shipping offers a practical example of how to improve access to an inland market.
The distinction between Mombasa and Lamu is central to the investment case. The existing network begins at Mombasa and cannot be assumed to serve a new refinery at Lamu. Sponsors must assess the commercial viability of coastal shipping, receiving terminals, and inland connections. The Kisumu–Entebbe experience supports the examination of a combination of transport modes; it does not establish that any particular route from Lamu will be economical.
Essential crude-receiving and product-dispatch arrangements must be ready when the refinery starts operating. Further distribution capacity can develop as buyers commit to volumes. Involving storage operators, transport providers, and regional customers early would help coordinate these investments and provide financiers with a clearer basis for assessing demand.
The Afreximbank programme provides a pragmatic complement to these efforts. Trade finance helps buyers convert African production into sales, addressing a different segment of the chain than construction finance.
Caveats Regarding Energy Independence
The groundbreaking does not guarantee completion or the expected economic benefits. A refinery of the proposed scale needs reliable crude supplies, and regional production cannot simply be assumed to meet that requirement. Dangote has described sourcing crude from regional and overseas producers.[13] Processing imported crude could reduce dependence on imported finished fuel, but it would still expose the country to international crude markets.
Local refining also does not guarantee cheaper fuel. Delivered prices will depend on crude costs, refinery efficiency, financing, taxes, exchange rates and transport. The investment case must therefore demonstrate how the plant can supply customers competitively over time.
Land rights, community participation and environmental compliance require early attention. On 29 September 2026, Reuters reported that a Kenyan court ruling on a land-rights claim could affect certain site activities. However, the Dangote Group said it would not halt the planned groundbreaking ceremony.[14] Investors must address these issues through transparent land processes and credible engagement. Dependable trade requires operating arrangements that respect the communities and environments along the corridor.
The Broader Implications for Africa
The broader significance of the Lamu announcement lies less in the identity of its principal sponsor than in the development model it represents. Africa’s longer-term development strategy cannot remain dependent on the extraction and export of raw materials followed by the importation of higher-value goods produced from those same resources. Achieving energy self-sufficiency will require African processing capabilities, infrastructure, capital, regional trade, and credible cross-border markets. Additionally, it will necessitate structuring projects to transcend national boundaries. A refinery in Kenya, partially supplied by African crude, financed through both African and international investments, linked to African transport networks, and distributing fuel across multiple African economies represents a significantly different economic model compared to the traditional extract-and-export paradigm.
This principle extends beyond petroleum; African lithium should ideally enhance African battery value chains, African copper should support electrical manufacturing on the continent, and Africa’s abundant solar and wind resources should increasingly empower local industries. Natural gas, where suitable, should facilitate regional power and industrial markets rather than being treated solely as an export commodity. The objective is not to isolate from global markets; Africa should remain deeply integrated within them. However, the goal is to engage with these markets from a position of enhanced productive capacity and resilience. This is the essential conversation that the Lamu refinery should inspire. A $16Billion refinery alone will not make Africa energy self-sufficient, nor should a single project be seen as a solution to a structural issue that has developed over decades. However, if Lamu becomes part of a broader network of African refineries, renewable energy initiatives, transmission systems, storage facilities, ports, pipelines, and regional trade frameworks, it would represent a change far more significant than merely another mega-project. It would signify a gradual shift from questioning how Africa will source its energy to exploring how much of Africa’s energy value chain can be developed, financed, operated, and retained within the continent. This shift may ultimately serve as a more meaningful benchmark for energy independence.
The question then also pertains to African capital: how much are African business owners, banks, and development institutions willing to invest in the industrial capacity we aspire to create? Dangote’s example underscores the importance of a sponsor taking on the initial substantial project risk, with institutions capable of guiding the project through construction and into operational success.
Connecting Investment to Regional Energy Self-Sufficiency
East Africa’s existing fuel corridors give Lamu a practical foundation. The Mombasa–Nairobi pipeline, the expanded Nairobi–Eldoret route, and the Kisumu–Entebbe Lake link demonstrate that the region already has infrastructure and commercial relationships that support cross-border fuel distribution. In my view, Lamu’s strongest opportunity lies in adding processing capacity to this established system. However, the Mombasa-based network cannot automatically serve a refinery at Lamu. Connecting the two will require commercially viable coastal movements, storage facilities and inland routes. For buyers in Uganda and other landlocked markets, the benefit will ultimately depend on reliable deliveries and the total cost of getting fuel to them. Building that hub will require capital and coordination beyond the refinery gate.
The refinery’s development creates opportunities for other investors to finance the terminals, storage and distribution services that connect production with customers. Afreximbank’s trade-finance programme can help turn African production into regional sales. Workable customs procedures and compatible standards will help these investments function as a regional system. There is a particular responsibility here towards the landlocked markets the refinery hopes to serve. Producing fuel closer to them will achieve little if transport costs, border delays or unreliable access absorb the benefit. Regional participation should therefore extend beyond political support for the project to commercial agreements and operating arrangements that make supply useful to buyers in Uganda and other inland markets. Community participation and environmental compliance must also be embedded in this development process. A corridor cannot provide dependable trade if the land and livelihoods it affects are treated as matters to resolve later.
The wider lesson is that African energy self-sufficiency requires both the willingness to build productive assets and the commitment to connect them to markets. Lamu could strengthen Kenya’s role in regional energy supply while creating opportunities for neighbouring economies to participate in a larger African value chain. Its contribution should therefore be judged by how effectively it builds on existing infrastructure, serves regional customers and retains value within Africa. The refinery may serve as an anchor investment, while the wider industrial hub will depend on coordinated investment in the associated logistics, storage, transport, and service infrastructure.
Italian major ENI has signed off on a contract amendment with Yinson Production for a major Non-Associated Gas (NAG) modification project on the FPSO John Agyekum Kufuor (FPSO JAK), operating offshore Ghana.
Under the contract amendment, Yinson Production will undertake the topside modification works to substantially expand the gas handling and processing capabilities of FPSO JAK, reinforcing Ghana’s domestic gas supply.
The primary objective of the NAG modification project is to install gas compression to address expected decreasing reservoir pressures and increase the vessel’s gas export capacity from approximately 210–220Million standard cubic feet per day (MMscf/d) to 355MMscf/d.
As part of the contract amendment, the firm lease period for FPSO JAK will be extended by four years and will now run until 2036.
Following completion of the modification works, the contract amendment will generate an incremental day rate through 2036. This incremental day rate and the 4-year extension to the contract increases Yinson Production’s firm contract backlog by approximately $600Million.
The NAG modification project, expected to be completed by the first quarter of 2028, will involve the fabrication and integration of two key topside modules designed to expand FPSO JAK’s gas-handling capacity. These include the MG2 module, equipped with two gas turbine-driven compressors, and the MC4 module, an auxiliary gas treatment module designed to manage higher gas volumes.
Engineering, procurement, and fabrication activities for the MG2 and MC4 modules will be carried out in compliance with stringent offshore safety and quality standards, ensuring operational continuity and asset integrity throughout execution.
FPSO JAK is owned by a joint venture led by Yinson Production, which holds a 74% controlling equity stake. The remaining 26% stake is held by a Japanese consortium comprising Sumitomo Corporation, Kawasaki Kisen Kaisha, Ltd. (“K” LINE), JGC Holdings Corporation, and Development Bank of Japan Inc. (DBJ).
US major Chevron Corp. has announced the promotion of Jeff Gustavson, currently president, New Energies, to the role of Chief Financial Officer (CFO).
Eimear Bonner, the company’s current CFO, will become the president, Oil, Products & Gas.
As CFO, Gustavson will be responsible for audit, controller, investor relations, tax, treasury and business planning activities worldwide, according to a statement by Chevron Corp.
Bonner, who was named CFO only two years ago, will now be in charge of “reliable operations across the entire value chain, as president, Oil, Products & Gas”. She will also “oversee disciplined capital allocation, asset class excellence and value chain optimization to drive stronger performance”.
These are the most consequential appointments made in the Senior Leadership Changes announced by the company on October 5, 2026.
Brent Gros, currently president of Offshore, will become president of New Energies, leading Chevron’s lower carbon businesses, including hydrogen, power, carbon capture, offsets, and biofuels. He will also oversee the company’s AI strategy, focused on value creation, operational excellence, cost efficiency, and innovation.
Mark Nelson, who is currently vice chairman and executive vice president of Oil, Products & Gas, will remain vice chairman of Oil, Products & Gas, with responsibility for Strategy and Business Development. In addition to his corporate duties, Nelson will be responsible for identifying and advancing opportunities that strengthen the company’s portfolio, enhance competitiveness, and support long-term growth.
Angolan crude oil supplied to the local refinery in Luanda ramped up to its highest volume in 12 months in August 2026.
The 49,013Barrels of Oil Per Day supplied by Sonangol and the National Oil, Gas and Biofuels Agency (ANPG) in the month topped the July 2026 supply by ~13,000BOPD.
Deliveries to the 65,000 barrels per stream day (BPSD) plant have been less than half of the facility’s nameplate capacity. Supplies in February, March, April and May 2026 hovered between 12,000 and 24,000BOPD.
The year-to-date average supply of crude to the refinery, as of August 31, 2026, was 28,522BOPD, according to ANPG data.
Crude deliveries to Luanda in 2026 are a significant drop from 2025 supplies, which averaged 47,993BOPD. Indeed, February, April and May 2025, average supplies were 64,193BOPD, 60, 214BOPD and 57,814BOPD respectively. The lowest monthly average for that year was October, with 35,878BOPD.
The Luanda refinery has been extensively revamped in the last five years with the support of ENI, the Italian upstream explorer. The upgrade quadrupled the capacity for gasoline production, added highly advanced naphtha hydrotreater and platforming units and rehabilitated the combined cycle plant to be powered by hydrogen generated directly by the new platforming unit. Power is now produced by recycling gas, which achieved a 70% reduction in fuel oil furnace dependence and significantly cut pollutant emissions. Total nominal crude processing capacity however remained at 65,000BOPD.
ANPG’s monthly reports don’t include the supplies to the newly inaugurated, 30,000 barrel-per-day Cabinda refinery. The facility’s operators, Gemcorp, have never publicly disclosed where they obtained feedstock, four months after the refinery was commissioned. Angola’s downstream petroleum regulator, the Institute for the Regulation of Petroleum Derivatives (IRDP), reported operational milestones for the Cabinda Refinery rather than detailed daily crude supply breakdowns, noting it commenced operations at 15,750BOPD following its launch. Local offshore fields in the oil-rich Cabinda province are naturally expected to provide the crude stream for the plant.
South African state-owned Transnet Pipelines (TPL) is inviting suitably qualified companies, consortiums and joint ventures to participate in a series of Requests for Proposals (RFPs) for the leasing, operation and maintenance of five strategic fuel storage facilities across the Free State, KwaZulu-Natal and Mpumalanga.
Proposal Closing Date is December 4, 2026.
The infrastructure company, which operates over 3,114 kilometres of high-pressure petroleum and gas pipelines as a subsidiary of Transnet SOC Ltd in South Africa, says that this s initiative forms part of its asset optimisation strategy to unlock value from underutilised infrastructure, strengthen South Africa’s energy security, stimulate economic growth and expand private sector participation in the fuel logistics value chain.
The opportunities include the Bethlehem, Kroonstad and Magdala Liquid Petroleum Depots in the Free State, the Ladysmith Fuel Storage Facility in KwaZulu-Natal, and the Standerton Petroleum Depot in Mpumalanga. Positioned within key inland markets, these facilities offer investors a unique opportunity to enhance fuel storage, distribution and related logistics services while contributing to the development of a more resilient and efficient energy supply network.
Mandatory site briefing sessions are planned between October 19 and 28, 2026, with the Ladysmith depot to take the lead on October 19, followed by the Kroonstad and Magdala depots both on October 26, the Bethlehem depot on October 27, and the Standerton depot making up the rear on October 28, 2026.
The bid documents state that successful bidders will be expected to ensure compliance with all applicable legislative and regulatory requirements, and operate the facilities in accordance with the requisite safety, environmental and operational standards.
Successful bidders would also be expected to invest in infrastructure improvements.
Prospective bidders are encouraged to participate in the mandatory site briefing sessions at the respective facilities and to familiarise themselves with the requirements outlined in the RFP documents here.
French President Emmanuel Macron is the latest high-profile figure among a growing number of stakeholders calling for a pause in the implementation of the Article 28 of the European Union (EU) Methane Regulation, joining the United States and a group of EU member states that have already backed a delay.
Barring any postponement, the requirement under Article 28 of the EU Methane Regulation for importers of crude oil, natural gas, and coal sourced from outside the EU to demonstrate and report Monitoring, Reporting and Verification (MRV) equivalence will take effect on January 1, 2027.
The provision seeks to ensure that imported fossil fuels meet the same methane MRV standards as those required of producers within the EU.
Under Article 28, effective January 1, 2027, importers of crude oil, natural gas, and coal from outside the bloc whose “contracts concluded or renewed on or after 4 August 2024” will be required to demonstrate and report MRV measures equivalent to those required within the EU. In contrast, for contracts signed before August 4, 2024, importers are only required to “undertake all reasonable efforts” to ensure the imports are subject to MRV measures established under the regulation.
There are two paths to demonstrating MRV equivalence under the regulation. Producer level and the exporting country level. Regardless of the route chosen, certain conditions need to be met for equivalence to be recognised. Under the producer level route, methane emissions measurement is required at source and site level, and must be verified by a third party. For crude oil and natural gas, monitoring and reporting established at the Oil & Gas Methane Partnership (OGMP) 2.0 level 5 reporting is also considered sufficient to meet the equivalence requirement. OGMP is a United Nations Environment Programme (UNEP) led initiative for methane emissions disclosure and mitigation in the oil and gas industry through a global reporting framework based on direct measurements.
At the country level, equivalence requirement can be met where an exporting country has an MRV regulatory framework that applies to producers and exporters supplying crude oil, natural gas or coal to the EU market and that is at least equivalent to the EU requirement. Such a framework must provide for source and site level quantification, regular reporting, independent verification, effective regulatory oversight, and compliance mechanism.
While the onus is on the importer to provide the required documentation to the competent authority in an EU member state, the underlying information would originate from the producer.
The regulation does not prohibit imports that are not compliant with its requirements. However, such volumes may become subject to fines and penalties.
Whether or not the pause for implementation materialises, African hydrocarbon producers exporting to the EU cannot construe it as a green light for inaction.
For many African producers, the Article 28 requirement and its January 2027 implementation date are not merely an academic exercise. They could become a market access issue, given the substantial exposure of some of the major continent’s major hydrocarbon exporters to the EU market. Any disruption to these trade flows could have implications beyond individual producers, particularly for countries where oil and gas revenues make a significant contribution to government finances.
The degree of exposure, however, varies from country to country. Data from the National Oil Corporation (NOC) of Libya’s 2025 Annual Report Technical and Statistical shows that about 79% of the NOC share of production exports, which reached 342Million barrels in 2025, went to the European market. Of this volume, EU member states received the majority. Italy accounted for 137.6Million barrels (40.2%), France 26.482Million barrels (7.7%), and the Netherlands 22.742Million barrels (6.6%), while Greece, Germany, Romania, Croatia, Sweden, Bulgaria and Poland account for the remainder.
Data from the United Sates Energy Information Administration (EIA) shows that Algeria exported 402,000 barrels per day of crude oil in 2024, of which 73% was shipped to Europe. France accounted for 21% of exports, Spain 12%, and Germany and Portugal 7% each, while the remainder went to other European destination. Algeria exported 1.9Trillion cubic feet (Tcf) of natural gas in 2023, out of which 90% went to Europe. Of this, 672Billion cubic feet was exported as LNG and 1.2Tcf through pipeline. According to the data from the Energy Institute, France received 30% of exports, Italy 12%, Turkey 32%, and the remained was shipped to other European markets.
Data from the Vanderbilt Terminal for Angola’s Oil & Gas Industry shows that EU member states accounted for about 14% of Angola’s 1.05Million barrels per day (BOPD) of crude oil export destination in 2024. Spain led the pack with 45,000BOPD (4.3%), followed by France with 38,000BPD (3.6%), Italy with 35,000BOPD (3.3%), the Netherlands with 18,000BOPD (1.7%) and Portugal with 12,000BOPD (1.1%).
EIA data also shows that Nigeria, Africa’s largest oil producer exported 1.3MillionBPD (1.3MMBPD) of crude oil and condensate in 2024. Of this volume, 622,000BPD (48%) went to Europe. France received 128,000BPD (10%), Spain 153,000BPD (12%), the Netherlands 7%, while 20% was exported to other destinations across Europe.
It can be deduced from the data above that Algeria, Libya, and Nigeria are particularly exposed to the implementation of Article 28, given the share of their hydrocarbon exports that flows to the EU market.
Given the current state of the oil market, particularly in the aftermath of the Russia-Ukraine conflict, and the ongoing tensions between the USA and Iran, it is understandable why some countries and stakeholders are calling for a delay. Perhaps it is not lost on those calling for a pause that the implementation of Article 28 could leave European buyers facing limited supply alternatives, particularly if a significant share of the current import is unable to meet the equivalence requirements. The pertinent question now, is what becomes of the exposure risk to the EU market once the supply constraints created by current geopolitical disruptions begin to ease and there is no postponement of the MRV compliance implementation.
Understandably, the implications of the implementation cut both ways, affecting exporting countries as well as the importing market. This is illustrated by Wood Mackenzie’s research conducted in mid-2025, which found that none of the countries “exporting gas/LNG or crude oil to the EU” currently meets the “country-level equivalence requirements” under the EU Methane regulation. Wood Mackenzie study assumes the producer level equivalence “and the ability of importers to identify the upstream producers” will likely determine the volumes of hydrocarbon that meet the requirements of the EU market. The Wood Mackenzie study further indicates that, under its Default Scenario, the non-compliant volume to the EU market could hit about 43% (4Trillion cubic feet) for natural gas, and 87% (9.8MMBPD) of crude oil by 2027. According to the study, the resulting supply constraints could significantly affect the EU refining industry, tighten fuel markets, and contribute to higher gasoline and diesel prices.
The implications for producers in African countries may not be uniform. However, International Oil Companies (IOCs) are better positioned to meet the MRV requirements, owing to their deeper technical capabilities and the reputational expectations of investors and stakeholders in their home countries. National oil companies and indigenous independent producers may face greater compliance challenge, particularly where in-country regulatory frameworks, technical capacity, and MRV systems are not well developed. Although companies such as Shell, bp, Chevron, ENI, ExxonMobil, Equinor, Azule Energy, NNPC Ltd, Libyan National Oil Corporation, Asharami Energy, and Renaissance Africa Energy Company, all of which operate in Africa, are already members of OGMP 2.0, level 5 compliance remains limited. As the Wood Mackenzie study notes, the “availability of fully verified Level 5 [of the OGMP 2.0] supply remains far below what is needed to meet EU demand” despite OGMP 2.0 being one pathway to meet producer level compliance under the EU methane regulation.
African producers and exporters therefore cannot afford to base their strategy solely on the prospect of a postponement from Brussels. Producing countries need to act. Developing equivalent methane regulations at the national level would create the policy framework needed to drive producer compliance. This, in turn would improve the prospects of achieving both country level and producer level equivalence, provided implementation and enforcement are effectively managed.
Whether Article 28 takes effect as scheduled or temporarily delayed, the direction of its travel is clear. It extends beyond regulatory compliance to one of market access. For African producers and exporters, the challenge is no longer whether to prepare for stringent MRV requirements. Rather, it is how urgently domestic regulatory frameworks, institutional capacity, and compliance systems can be developed and strengthened to remain competitive in a market where methane performance is of growing commercial importance.
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.
Are Mozambique’s largest LNG project about to get a green light in 2026?
The Mozambique LNG (Area 1) project, operated by TotalEnergies, is expected to produce approximately 13Million tonnes per annum (MMTPA) of liquefied natural gas.
France’s energy giant TotalEnergies has hit the reset button for the construction of a multibillion-dollar liquefied natural gas (LNG) development off the coast of Mozambique. The reignition comes almost five years after the project was put on ice, with force majeure declared in April 2021. Production is expected to begin in 2029.
ExxonMobil’s Rovuma LNG project -which is even larger-is expected to announce a Final Investment Decision (FID) by year’s end. The facility is expected to include two LNG trains comprising 12 modular liquefaction modules, with total production capacity of approximately18.6 MMTPA total capacity and a targeted startup in 2031. The overall Rovuma LNG development is estimated at roughly $30-32Billion.
Why the sudden urgency to now move ahead? The swift move forward by both TotalEnergies and ExxonMobil is pure market-based. They realize that there is a sharp disconnect between future demand and supply of LNG: future demand is shrinking dramatically and supply capacity is increasing at an alarming rate. Both companies realize that if their projects are not producing LNG sooner rather than later both LNG projects could have their economic value down-graded considerably or their worst fear—vast stranded assets!
Yet both Shell and Bloomberg are predicting that future demand is assured—be it with a few hiccups.
There is strong evidence that demand is shrinking—in particular Asia: China had purchased a large number of LNG contracts and is now re-selling them to various global markets …this is much more than Asian countries re-selling LNG to other Asian countries…no it turning the LNG marketplace into a free-for-all bargain play also involving Europe and North America.
A demand in LNG Growth?
Both Shell and Bloomberg NEF are predicting that global LNG growth will continue—be it with mixed messages.
Shell’s LNG Outlook 2026 is predicting that by 2050 global LNG growth will be nearly 700Million tonnes per year, an increase of 65% from 2025. Demand in 2025 was 422MMTPA.
According to Bloomberg NEF…” Global LNG demand continues to expand through 2035, with growth increasingly shifting from Northeast Asia toward South and Southeast Asia after 2030 … Industrial fuel switching, rising power demand and declining domestic gas imports remain resilient despite falling gas demand”.
For 2035 Bloomberg NEF Global Outlook is predicting a global demand of 600 mtpa.
Institute for Energy Economics and Financial Analysis (IEEFA) has provided an in-depth analysis of the various Asian markets.
China
China, for example, has transformed itself from the world’s largest liquefied natural gas (LNG) buyer into a major global reseller.
According to a September 2026 IEEFA report, authored by Christopher Doleman and Sam Reynolds… “Plateauing domestic demand, a ballooning portfolio of long-term contracts, and a structural pivot by state-owned enterprises into LNG shipping and trading are positioning Chinese companies as significant competitors to traditional suppliers as the market enters a period of historic oversupply.”
The authors continue:
China’s LNG imports have fallen from a peak of 79Million tonnes (Mt) in 2021 to 66Mt in 2025 and are expected to decline further to 63Mt in 2026.
Extensive contracting between 2021 and 2023, during which Chinese buyers signed nearly 60Mt of new supply agreements, has generated a growing surplus of contracted volumes. Total Chinese LNG resales … were likely to be between 17Mt and 19Mt, with South Korea, Japan, and the Netherlands as the leading destinations.
According to the authors, this has provided a surge in flexible long-term contracts, particularly from Australia and the United States Growing flexible volumes from Australia have enabled China to optimize its LNG portfolio across the Pacific region, while US supply has largely been leveraged to capitalize on arbitrage opportunities in the Atlantic region.
IEEFA estimates that Chinese buyers have profited $4.6Billion from Australian and US LNG resales since 2021.
China’s surplus is likely to persist and even grow. With LNG contracts expected to reach 114Mt by 2028 and demand constrained by cheaper alternatives, the country is likely to remain over contracted in the medium term.
IEEFA also points out that— the China National Offshore Oil Corporation (CNOOC) and PetroChina Company Limited (PetroChina), together responsible for most Chinese charterer resales in 2025 —are investing heavily in LNG carrier fleets.
The authors conclude “China’s emergence as a reseller of surplus LNG exposes the fragile assumptions underlying the current wave of LNG export investment. For suppliers, portfolio traders, and aspiring merchant LNG players, the largest LNG demand driver is becoming a competing supplier.”
Domestically LNG in China must cope with rising domestic gas production, pipeline gas imports, coal, and renewable power capacity.
Japan/South Korea /Europe
LNG imports in Japan, South Korea and Europe – which account for more than half of the world’s demand – fell in 2023 and will likely continue falling.
“40 percent of all LNG volumes handled by Japanese companies are sold elsewhere,” according to Sam Reynolds from the Institute for Energy Economics and Financial Analysis (IEEFA). This is up from 16 percent in 2018.
In 2024, Japanese LNG resales were approximately 1.7 times Japan’s total direct imports from Australia, its largest LNG supplier. Resales amounted to around four times the volumes purchased from Malaysia, Japan’s second-largest LNG supplier.
Other countries are also taking steps to curb their imported of LNG: since March 2026 Vietnam, the Philippines, Taiwan and South Korea have cancelled a total of 16Million tonnes of LNG shipments.
LNG Supply
IEEFA expects global LNG supply capacity to rise to 666.5MMTPA by the end of 2028, which exceeds International Energy Agency (IEA) demand scenarios through 2050.
According to IEEFA, global supply of LNG will probably increase by about 40% in the next five years. Robust supply growth will likely lead to lower prices, encouraging an uptick in short-term buying, posing ongoing fiscal challenges and lengthy delays for new gas and LNG infrastructure.
“By the end of 2028, the world’s total nameplate liquefaction capacity could reach 666.5 MTPA. For perspective, the IEA(International Energy Agency) projects total LNG trade in 2050 to reach 482MMTPA under its stated policies scenario. In other words, LNG liquefaction capacity coming online through 2028 exceeds IEA long-term demand scenarios.”
According to the IEA between 2019 and October 2026, more than 15.2Trillion cubic feet of LNG export capacity reached FID, averaging over 2Tcf per year of new capacity annually. This is more than double the average annual rate of capacity approvals during the 2014–2018 period. The United States has been the dominant driver of LNG liquefaction project FIDs, accounting for nearly 55% of the total since 2019. Qatar is a distant second, with around 15%.
Some Concluding Remarks
The marketplace is now gearing up for an LNG turf war in which LNG must try and maintain that it is a fuel of guaranteed security and supply.
Qatar’s LNG production is severely constrained due to the closure of the Strait of Hormuz following the outbreak of the US-Iran war. Normally 77Million tonnes per annum (MTPA) are produced. The current crisis has not only dented Qatar’s reputation, but certainly does not enhance LNG’s reputation as a reliable fuel.
In China LNG must compete with rising domestic gas production, pipeline gas imports, and renewable power capacity.
Japan and South Korea are both starting up their nuclear capacity and using more renewables.
In the past Asia and in particular China was an LNG buyer and has now become an LNG seller.
Closer to home Eni has proven to be a deft operator in Mozambique with its two FLNG projects while TotalEnergies and ExxonMobil are still finalizing their Mozambique strategy.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.He writes on a regular basis for Africa Oil + Gas Report, and is a guest contributor to the Institute for Energy Economics and Financial Analysis (IEEFA). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition
…near-field and potential infrastructure-led exploration opportunities have been identified
Tullow Oil has signed a rig contract for up to 10 wells in the 2027-28 Ghana drilling programme.
The rig expected to arrive around the middle of 2027 and target identification being supported by the high-quality four dimensional (4D) seismic data and incremental support from the incorporation of the Ocean Bottom Node (OBN) survey data.
The 2025-26 drilling campaign is now complete with six Jubilee producers onstream and the final well, a water injector, onstream in September 2026.
Gross oil production from the Jubilee field averaged 70,800Barrels of Oil Per Day (BOPD (net: 27,600BOPD) in the first half of the year, outperforming expectations. “The 4D seismic data interpretation has been shown in this drilling campaign to deliver key reservoir insights that have enabled successful target selection and high production performance”, Tullow highlights in the first half 2026 report. “A number of existing wells drilled in the previous campaign have seen the benefit of production optimisation activities in the first half of 2026 and a number of key wells have outperformed decline expectations whilst being supported by dual riser operations.”
Full year water injection performance remains in line with expectations, despite unexpected downtime in the second quarter. Voidage replacement remains above 100% in the first six months and showing an increasing trend on an annual basis. Gross oil production from the TEN fields averaged 14,800BOPD (net: 8,100BOPD) in the first half of the year, above expectations.
Tangible near-term projects such as subsea pumps, further development drilling, monetisation of gas resources and an intervention campaign are being progressed to mature material Jubilee and TEN resources into reserves. Furthermore, tangible longer-term near-field and potential infrastructure-led exploration opportunities have been identified and are being matured in deeper horizons beneath Jubilee and TEN, supported by the high-quality 4D seismic and in due course by the OBN survey data.
The 2025 Annual Financial Report of NNPC Limited deserves to be examined as more than a financial scorecard. From a petroleum-economics perspective, it raises a much broader question: is the transformation of NNPC into a commercial company producing the sustainable economic value envisaged by the Petroleum Industry Act (PIA)? This press commentary draws on my attendance at NNPC Limited’s dinner press briefing hosted by the Financial Comptroller on October 2, 2027. The company reported ₦7.2Trillion in net income, a ₦5.8Trillion dividend, crude and condensate production of 565.8Million barrels, and gas transmission of 473.3Billion cubic feet (Bcf). These are significant results and should be acknowledged. But they do not, on their own, establish sustainable commerciality. The more fundamental questions are: What assets does NNPC Limited actually own? How productive are those assets? How much of the reported earnings has been converted into cash? How transparent is the flow of value? And who is ultimately accountable for the decisions that determine that value?
Beyond Profit: Assets, Resources and Commerciality
The debate over NNPC Limited’s asset base is sometimes framed as though vesting assets in the company would amount to transferring Nigeria’s petroleum resources to it. That is not the issue. Petroleum in the ground remains a national resource, while government can vest NNPC Limited with commercially identifiable interests—joint-venture equity, production-sharing-contract interests, producing assets, infrastructure and associated contractual rights and cash flows—without surrendering sovereign ownership of the resources. These are corporate assets: they can be valued, financed, developed, managed and used to support partnerships and capital formation. We wanted NNPC to own assets, not resources. The PIA provides the basis for this distinction: petroleum and mineral resources remain vested in the Government of the Federation, while NNPC Limited is established as a commercially oriented company and the former NNPC’s assets, interests and liabilities are to be transferred to NNPC Limited or its subsidiaries. The critical issue, therefore, is whether NNPC Limited’s JV equity, PSC interests, infrastructure, contractual rights and related obligations have been clearly identified, valued and legally documented as a coherent corporate portfolio.
That distinction is fundamental to commerciality. NNPC Limited may operate on a commercial basis, but commerciality cannot be established by accounting profit alone. The real test is whether the assets generate adequate economic returns, production is sustained efficiently, capital is allocated prudently, reserves are replaced and investments remain resilient to changing oil and gas prices. A profitable petroleum company can still face declining production, inadequate reinvestment, weak asset productivity or deteriorating cash flow. The appropriate measures must therefore include asset productivity, capital efficiency, production sustainability, reserves replacement and operating cash flow, alongside conventional profitability. The question is not simply how much NNPC earned in 2025, but whether the assets and capital employed are generating sustainable economic value.
The ownership question must also be distinguished from the strategic-management question. Government ownership does not necessarily prevent commercial operation, just as private ownership does not automatically guarantee sound strategic management. What matters is a clear mandate, professional management, appropriate incentives, disciplined capital allocation, arm’s-length transactions and enforceable accountability. This is also why an eventual IPO should not be confused with commercial transformation. An IPO could strengthen disclosure, provide external valuation, broaden ownership and introduce minority-shareholder scrutiny, but the capital market should test a commercially mature institution rather than be expected to create one. Before investors are invited to buy shares, they need clarity about the assets, contractual rights, liabilities, capital requirements, cash-generating capacity, government obligations, related-party transactions and dividend policy.
Transparency, Cash Sustainability and the Accountability Test
The most revealing issue in the 2025 report, in my view, is the reported ₦11.2Trillion receivable associated with energy-security expenditure. The expenditure may have contributed to increased production and broader economic benefits, and those benefits should be recognised. But the outstanding receivable exposes a critical distinction between accounting performance and commercial sustainability: profit can be recognised before cash is collected. A commercial company ultimately requires cash to operate its assets, meet obligations, fund capital expenditure, pay dividends and reinvest. Until there is a credible mechanism for recovering such a material receivable, questions remain about the liquidity supporting reported commercial gains. The appropriate response is therefore neither to dismiss the production gains nor to overlook the financial exposure. Commercial discipline requires clearly defined obligations, transparent reporting of receivables and their ageing, credible recovery arrangements, enforceable payment terms and accountability for both those who incur obligations and those responsible for collection.
This brings transparency and accountability to the centre of the commerciality debate. The 2025 consolidated and separate financial statements, supported by PwC’s independent audit, represent welcome progress. But transparency in a national petroleum company must go beyond audited financial statements. The public should be able to follow the economic chain from resources and contractual rights, to assets, production, lifting, sales, revenue, costs, earnings, government payments and reinvestment. This does not mean publishing every commercially sensitive contract. It means providing sufficient information to establish how value is created, how much is converted into cash, what NNPC Limited retains, what is paid to government, what remains outstanding and what is reinvested. That is particularly important where government remains the shareholder and where commercial transactions can intersect with public-policy obligations.
The 2025 report therefore provides evidence of progress, but also highlights the work required to demonstrate genuine commercial transformation. Profitability is important, but profitability alone is not commerciality. Audited accounts are important, but audited accounts alone are not full transparency. Ownership is important, but ownership alone is not strategic management. And an IPO may strengthen commercial discipline, but an IPO is not a substitute for commercial discipline. The more meaningful test is whether NNPC Limited has clearly vested and productive assets, dependable cash generation, disciplined capital allocation, transparent reporting and enforceable accountability. Ultimately, Nigeria needs more than a profitable NNPC Limited. It needs an NNPC Limited capable of converting petroleum resources and productive assets into sustainable economic value while remaining transparently accountable for the national wealth entrusted to it. That, in my view, is the real test of commerciality under the PIA.
Wumi Iledare, PhD, FNAEE, is Professor Emeritus of Petroleum Economics, LSU Energy Institute and Chair, Nigeria Oil, Gas, and Energy Policy Forum, EEF Abuja
