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
Liberia will feature its 2026 Offshore Direct Negotiation Licensing Round at Africa Energy Week (AEW) 2026 in Cape Town.
The process, led by Liberia Petroleum Regulatory Authority (LPRA), will present 29 offshore blocks with substantial subsurface data package comprising more than 50,000 line-kilometres of two dimensional (2D) seismic and over 31,000 square kilometres of 3D seismic data to international investors during Africa’s largest energy event to run from October 12-16, 2026.
The offering highlights the Liberia and Harper basins, with available acreage targeting a range of Cretaceous structures, deepwater basin-floor fans and structural closures, with the wider petroleum system sharing geological characteristics with prolific plays across the Atlantic margin.
TGS (for geophysical data) and Core Laboratories (for stratigraphic data) have supported the technical programme, while additional gravity, magnetic, well-log and multi-client datasets provide further information for companies evaluating the acreage
The LPRA’s formal presentation follows months of preparation led by Director General Marilyn T. Logan, including an August 19, 2026 investor day in Houston and the August 28, 2026 opening of prequalification. Companies are now able to establish their technical and financial eligibility ahead of expressions of interest and block-specific negotiations.
Liberia’s last formal competitive oil and gas bid round was conducted in August to December 2014 by the National Oil Company of Liberia (NOCAL), which ultimately concluded unsuccessfully due to political disagreements.
In the last five years, the country has replaced the traditional competitive bidding round with an alternative hybrid process called the Direct Negotiation Licencing Round. It was in this context that the 2024 Liberia Direct Negotiation Round was run through the LPRA.
The direct negotiation model allows qualified companies to advance individual technical and commercial prospects. The process operates under Liberia’s 2014 Petroleum Exploration and Production Act and its 2019 amendments, while resulting PSCs require signatures from both the LPRA and Ministry of Finance and Development Planning. Companies are assessed on technical capability, financial strength and offshore experience before progressing into negotiations over proposed exploration programmes.
TGS has reprocessed 12,000 kilometres of 2D seismic using Pre-Stack Depth Migration, alongside 5,100 square kilometres of reprocessed 3D data from a 26,000-square kilometre volume. The wider TGS library includes more than 24,000 kilometres of legacy 2D data, strengthening imaging across an offshore frontier where subsurface definition remains central to exploration decisions.
The available Liberia Basin acreage includes LB-1, LB-2, LB-3, LB-7, LB-12, LB-13 and LB-14, while Harper Basin opportunities include LB-18, LB-19, LB-20, LB-21, LB-23, LB-25 and LB-28. Other blocks within the wider 29-block grid are already covered by existing commitments and agreements.
TotalEnergies holds LB-6, LB-11, LB-17 and LB-29, covering approximately 12,700 km2, while Atlas Oranto Petroleum holds LB-15, LB-16, LB-22 and LB-24. PetroQuest holds interests connected to LB-32, while RL-003 covers LB-26, LB-30 and LB-31 and involves TotalEnergies and BluEnergies in a separate study and application arrangement.
Activity around LB-32 has provides a fresh indication of corporate interest ahead of the AEW launch. Australian independent Bounty Oil & Gas agreed on September 22 to acquire 100% of PetroQuest Liberia Deep Water, which holds an exclusive letter of engagement with the National Oil Company of Liberia to negotiate a PSC for the Harper Basin block.
The Harper Basin’s geological setting is also attracting attention because of its relationship to neighboring Ivory Coast’s offshore petroleum system. Eni’s Baleine and Calao discoveries have demonstrated the wider prospectivity of the regional margin, while companies including Petrobras and Murphy Oil are pursuing comparable Upper Cretaceous deepwater plays elsewhere in the region.
Liberia’s licensing process uses a direct negotiation model, allowing qualified companies to advance individual technical and commercial prospects. The process operates under Liberia’s 2014 Petroleum Exploration and Production Act and its 2019 amendments, while resulting PSCs require signatures from both the LPRA and Ministry of Finance and Development Planning. Companies are assessed on technical capability, financial strength and offshore experience before progressing into negotiations over proposed exploration programs.
With prequalification now open and valid for five years, companies can establish their eligibility ahead of the licensing round and be prepared to move quickly when new opportunities are launched.
The Jack up rig Natt, owned and operated by Borr Drilling, will continue to be on active duty for Shell Nigeria Exploration & Production Company (SNEPCo) until August 2027.
The rig is currently drilling on the HI field in Oil Mining Lease (OML) 11, offshore southwestern Niger Delta.
Borr Drilling reports that SNEPCo exercised the one-well option on the Natt in Nigeria. “Based on the current well programme, it is anticipated that the rig will remain contracted with the customer into early August 2027.”
SNEPCo and its partner Sunlink Energies and Resources Limited announced a $2Billion final investment decision regarding the shallow water HI offshore gas field development on October 14, 2025.
Production from HI will be processed onshore at Bonny Island, where gas will be fed to Nigeria LNG (NLNG), in which Shell holds a 25.6% interest. The project aligns with the ongoing Train 7 expansion, which aims to increase the terminal’s capacity by 35%. The added gas supply will bolster Nigeria’s LNG exports.
Discovered in 1985 and located about 50 kilometres off Nigeria’s coast in 100 metres of water, is expected to produce up to 350Million standard cubic feet of gas per day—equivalent to around 60,000 barrels of oil equivalent per day—by 2030. The project’s estimated recoverable resource stands at approximately 285Million barrels of oil equivalent (MMBOE).
In the last five years, the country has replaced the traditional competitive bidding round with an alternative hybrid process called the Direct Negotiation Licencing Round. It was in this context that the 2024 Liberia Direct Negotiation Round was run through the LPRA.