India's three biggest energy groups have just reported bumper quarterly profits, but the fuel margins behind the largest slice of the windfall are already easing.

Libya, Ghana, Nigeria, Kenya and Angola are pushing billions into new refineries, but funding gaps, scarce crude and fading margins threaten Africa’s plans.

Abu Dhabi’s ADNOC has signed a multi-year partnership with OpenAI and G42 to become the first energy major to deploy advanced AI agent networks across its entire production chain.

Nigeria’s NMDPRA launched Revision 2 of its gas network code as it sees a $30bn-$50bn investment need by 2030 and pipeline capacity rising to about 4.2 bcfd.

Nigeria has launched a second revision of its gas transportation network code as the country’s midstream and downstream regulator estimates that $30bn-$50bn in fresh oil and gas investment will be needed through 2030, including for gas processing, fertiliser production, liquefied petroleum gas (LPG), flare-gas commercialisation and supporting infrastructure. The Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) unveiled Revision 2 of the Nigerian Gas Transportation Network Code at OTL Africa Downstream Energy Week in Lagos on October 26. NMDPRA Authority Chief Executive Rabiu Abdullahi Umar said the framework establishes transparent, non-discriminatory access to gas transportation infrastructure, with rules governing capacity booking, gas nominations, balancing, measurement and gas quality. The latest revision incorporates 28 amendments, including four principal changes covering Daily Reserved Pipeline Capacity Variation, Communication Protocol, Measurement Loss Factor and Balancing Neutrality Charges, according to conference reporting by Business Insight. The changes are intended to give network users greater flexibility in reserved pipeline capacity, improve coordination during disruptions, standardise the treatment of measurement losses and clarify the allocation of balancing charges. Introduced in 2020 and first revised in 2024, the code governs how producers, shippers and other users access shared gas transportation infrastructure. The regulator says clearer capacity-allocation procedures, cost-reflective tariffs and more consistent measurement should make network operations more predictable. The revised code addresses transportation rules rather than the wider commercial constraints on gas development. Investment requirements, insufficient processing and transport infrastructure, domestic gas pricing and the availability of creditworthy customers remain obstacles to new projects, as IntelliNews reported in September. Umar said major pipeline projects would substantially increase Nigeria’s gas transportation capacity. Figures presented at the conference put existing capacity at approximately 2.2bn cubic feet per day (bcfd), with new projects including the Ajaokuta-Kaduna-Kano (AKK) and Obiafu-Obrikom-Oben (OB3) pipelines expected to add about 2.0 bcfd, bringing total capacity to approximately 4.2 bcfd. However, ThisDay separately reported Umar as projecting 4.4 bcfd following completion of the projects. The available accounts do not reconcile the 200mn-cubic-feet-per-day difference. Pipeline completion figures also differ between government statements. NMDPRA’s September 2026 figures put AKK at 84% complete, OB3 at 96% and the Escravos-Lagos Pipeline System (ELPS) midline compressor project at approximately 97%. On October 2, however, Minister of State for Petroleum Resources (Gas) Ekperikpe Ekpo told Reuters that OB3 had reached full completion and was being prepared for first gas, while AKK was approximately 95% complete. State oil company NNPC’s July monthly report, published in early September, had already listed OB3 as 100% complete, with pre-commissioning finished ahead of first gas planned for August, and AKK at 95%. NNPC put OB3’s capacity at up to 2bn standard cubic feet per day along its 130km route. The different figures have not been publicly reconciled, and the official accounts do not establish whether they use identical measures of construction progress. Completion of construction or pre-commissioning also does not necessarily mean a pipeline has entered commercial service. Separately, the presidency said on October 22 that Lee Engineering was developing two midline compressor stations in Edo State intended to enable the expanded ELPS to operate at its design capacity of 2.3 bcfd. That system-specific capacity figure is not directly comparable with the regulator’s wider network projections. Nigeria’s gas reserves and production have increased, although transportation and processing capacity remain constraints. Ekpo told Reuters earlier in October that proven natural gas reserves had reached 215.19 trillion cubic feet, while production had risen to approximately 7.5 bcfd from 6.8 bcfd in 2023. Ekpo also said four gas projects worth about $3.5bn combined had reached final investment decisions, led by the roughly $2bn HI project, against a government target of $30bn in gas investment by 2030, Leadership reported. Separately, Nigeria LNG aims to start up its Train 7 expansion by the end of 2027, raising capacity from 22mn to 30mn tonnes per annum, Reuters reported in September. Umar said more shippers had joined the transportation network since Revision 1 was introduced in 2024. NMDPRA also reported a reduction of approximately 30% in gas imbalances on the Western Network following reconciliation work covering the first half of 2026. The regulator has not established how much of the improvement was attributable to the earlier code revision, and the reported figure does not identify a sufficiently clear comparison baseline. Revision 2 includes initial provisions intended to support cross-border gas transportation. Their application to regional pipelines would require coordination with other countries’ regulators and network operators. Nigeria already supplies Benin, Togo and Ghana through the West African Gas Pipeline, while two larger regional projects remain under development. On July 19, heads of state from the Economic Community of West African States (ECOWAS) meeting in Freetown signed an intergovernmental agreement supporting the proposed African Atlantic Gas Pipeline, intended to connect Nigeria with markets along the West African coast and Morocco. Morocco’s hydrocarbons agency ONHYM said the agreement opened the way for a project company based in Casablanca and a Pipeline Higher Authority headquartered in Abuja. Morocco and Mauritania were expected to complete a separate signing subsequently. The project remains at a pre-construction stage, with no publicly announced construction-financing package or final investment decision, as IntelliNews reported in September. In a separate development, Algeria’s state-owned Sonatrach said on June 4 that Algerian Energy Minister Mohamed Arkab, alongside officials from Nigeria and Niger, had formally launched construction work on the Algerian segment of the proposed Trans-Saharan Gas Pipeline. The wider project is intended to connect Nigerian gas supplies through Niger to Algeria’s transportation network and export infrastructure. Alongside the network-code revision, Umar said NMDPRA was reviewing its licensing arrangements to reduce administrative delays. Licences currently requiring annual renewal could be extended to five-year terms where appropriate, while eligible applicants may eventually be able to obtain licences remotely. Neither proposal was presented as a system-wide change already in force. See IntelliNews: Nigeria targets October launch for 2026 oil, gas licensing round as output drive accelerates See IntelliNews: ECOWAS members renew commitment to advance $26bn African Atlantic Gas Pipeline See IntelliNews: Africa drives 96% of Eni’s net oil and gas production growth in Q3

The NERC CIP-003-9 standard introduces new vendor remote access rules for low-impact BES cyber systems, creating significant audit and compliance risks for...

State-owned refinery TOR reports 28,000 bpd throughput and plans to expand capacity, while foreign-exchange gains underpin its financial turnaround.

Africa accounted for approximately 96% of Italian energy major Eni’s (BIT:ENI; NYSE:E) net global oil and gas production increase in the third quarter of 2026, as the Italian energy major works to expand offshore developments and liquefied natural gas (LNG) capacity while divesting mature assets. Eni produced 939,000 barrels of oil equivalent per day (boepd) across North and sub-Saharan Africa during the quarter, equivalent to 51.3% of its global output of 1.829mn boepd, according to its third-quarter results published on October 23. African production increased 8.1% from 869,000 boepd a year earlier, contributing 70,000 boepd of the 73,000-boepd net increase in group output, which rose from 1.756mn boepd. Output elsewhere rose by just 3,000 boepd on a net basis as regional gains and declines largely offset one another. Sub-Saharan African production rose 18.5% to 403,000 boepd, accounting for most of the continent’s increase, while North African output grew 1.3% to 536,000 boepd. The figures include Eni’s attributable production from equity-accounted joint ventures and 81,000 boepd associated with certain sanctioned JV partners. They represent reported production growth rather than the company’s adjusted underlying measure, on which Eni said group output rose 7% year on year, against reported growth of 4.2%. The company raised its 2026 underlying growth guidance to 6%–7% from 3%–4%. The expansion has been supported by offshore project ramp-ups, particularly in West Africa. Alongside this growth, Eni is selling selected assets and minority interests in producing developments to release capital and rebalance its upstream portfolio. West African projects drive expansion Côte d’Ivoire has emerged as a major production centre following the rapid development of the offshore Baleine field, which began producing in 2023. Baleine’s first two phases currently produce more than 57,000 barrels of oil per day (bpd) and 78mn cubic feet of gas daily, according to Eni’s September update. Eni and its partners approved a final investment decision for Phase 3 in May 2026, targeting total field production of 150,000 bpd and 0.2bn cubic feet per day (bcfd) of gas. The gas is intended primarily for the domestic market. These targets represent gross field production rather than Eni’s attributable share. In Ghana, Eni operates the Offshore Cape Three Points project, which produces oil and natural gas for domestic consumption, particularly electricity generation. Eni and its partners, Vitol and Ghana National Petroleum Corporation, are assessing further development opportunities using existing infrastructure. The Republic of Congo is another important production and gas development centre. In February, the second phase of the Congo LNG project shipped its first cargo, bringing combined installed liquefaction capacity to approximately 3mn tonnes per annum (mtpa). The project uses floating LNG facilities supplied by the offshore Marine XII licence. Its 3-mtpa capacity represents potential annual production rather than actual exports. In Angola, Eni operates through Azule Energy, its equally owned joint venture with BP (LSE:BP; NYSE:BP). Azule is ramping up production from the Agogo Integrated West Hub, where the Agogo floating production, storage and offloading vessel began operations in August 2025 and the Ndungu full-field development started production in February 2026. Together, Agogo and Ndungu are expected to reach gross peak output of approximately 175,000 bpd. Azule holds a 36.84% interest in the development, alongside Sonangol E&P and Sinopec International. The peak figure represents total field output, not production attributable to Azule or Eni. New investments target further production growth Eni is also investing in projects intended to extend African production growth beyond the current development cycle. In Angola, a June final investment decision cleared the $5.1bn Greater PAJ development, which will connect five offshore fields to a floating production, storage and offloading vessel with gross nameplate capacity of 95,000 bpd. First oil is expected in the first half of 2029. In Mozambique, Eni is advancing the $7.2bn Coral North project after reaching a final investment decision in October 2025. The project’s hull was launched in South Korea in January 2026, with completion targeted for 2028. Coral North is designed to provide 3.6 mtpa of liquefaction capacity, potentially increasing Mozambique’s combined LNG capacity to approximately 7 mtpa alongside Coral South, which began production in 2022. The facilities are expected to strengthen Mozambique’s role as an LNG exporter, although actual volumes will depend on commissioning, operating performance and plant utilisation. North Africa remains an established production base North Africa accounted for 29.3% of Eni’s global production in the third quarter. Egypt and Libya remain major operating centres alongside Algeria and Tunisia, with current investments focused on maintaining production, expanding gas-processing infrastructure and recovering associated gas. On October 20, Eni announced the start-up process for the Meleiha Phase 2 project in Egypt’s Western Desert. The development includes facilities designed to process up to 0.1 bcfd of gas, supporting additional domestic supplies. The figure represents processing capacity rather than a confirmed production increase. Egypt’s petroleum ministry has said completion of Meleiha’s second phase should support about 80mn cubic feet per day of additional gas production. Petroleum Minister Karim Badawi pressed Eni in September to accelerate development of the Denise West discovery in the Mediterranean, estimated at about 2 trillion cubic feet of gas in place, as Egyptian gas output fell to a multi-decade low. In Libya, Eni and state-owned National Oil Corporation completed the Bouri Gas Utilisation Project on October 19, with commissioning under way. The project is expected to recover approximately 700mn cubic metres a year, or about 1.9mn cubic metres per day, of associated gas previously flared, supporting domestic consumption and potentially increasing supplies available for export through the GreenStream pipeline to Europe. Eni estimates the development could reduce annual carbon dioxide emissions by approximately 1.5mn tonnes once operational. Disposals reshape African portfolio Alongside production growth and new investment, Eni is reducing its exposure to selected mature African assets. On October 26, the company completed the sale of its Nigerian subsidiary Agip Energy and Natural Resources (AENR) to Apex Global Energy, wholly owned by Sterling Oil Exploration and Energy Production. AENR held a 5% interest in the Renaissance joint venture, which operates onshore and shallow-water oil and gas assets in Nigeria. The other shareholders are Renaissance Africa Energy, with 30%, TotalEnergies (EPA:TTE; NYSE:TTE), with 10%, and Nigerian National Petroleum Company Limited (NNPCL), with 55%. The transaction’s value was not disclosed. Completed after the September 30 reporting period, it did not contribute to Eni’s third-quarter production growth. The disposal follows Eni’s August 2024 sale of Nigerian Agip Oil Company to Nigerian energy producer Oando (NGX:OANDO; JSE:OAO). The 5% interest in the former Shell-operated SPDC joint venture, subsequently renamed Renaissance, had been excluded from that transaction and retained by Eni. The latest sale therefore completes the disposal of a residual interest rather than representing an unrelated withdrawal from Nigeria. Eni retains Nigerian interests in deepwater exploration and production and Nigeria LNG. In Côte d’Ivoire, the company completed the sale of a 10% stake in Baleine to Azerbaijan’s state-owned SOCAR in September, marking SOCAR’s entry into Africa’s upstream sector, reducing its interest to 37.25%. Vitol holds 30%, Petroci 22.75% and SOCAR 10%. The transaction forms part of Eni’s dual exploration model, under which the company develops discoveries while selling minority stakes to recover capital, reduce financial exposure and fund additional investments. African concentration raises strategic stakes Africa’s contribution to almost all of Eni’s net reported production growth in the third quarter highlights the continent’s importance to its upstream expansion. The company is combining increased output from producing offshore assets with investment in new oil and LNG projects. However, Africa’s growing share of production also makes Eni’s future upstream performance increasingly dependent on the execution of developments across the continent, as well as regulatory stability, security conditions and commodity prices. The continent’s 51.3% share of reported production does not necessarily translate into an equivalent contribution to group earnings or cash flow, which depend on ownership structures, production costs, fiscal terms and realised prices. See IntelliNews: Italian-led consortium wins five-year services contract for Angola’s Greater PAJ oil development See IntelliNews: Eni seeks EPC contractors for proposed $130mn Mozambique power plant See IntelliNews: Egypt urges Eni to accelerate development of Denise gas field See IntelliNews: Azerbaijan’s SOCAR enters African upstream with 10% stake in Côte d’Ivoire’s Baleine project

The article discusses the rebranding of SPNEC (Solar Power and Energy Corporation) to MVP (MVP Energy), a move by Leandro Leviste's company. The rebranding is part of a strategic shift to align with Leviste's broader energy initiatives. The company has secured a P5 billion deal, which is a significant investment in the renewable energy sector. The article also touches on Leviste's recent sale of P3 billion in SPNEC shares as solar controversies mount. The rebranding and new deal are seen as steps to strengthen the company's position in the energy market. The article mentions that Leviste's private companies remain at the table, indicating ongoing involvement in the energy sector. The rebranding is likely to be part of a larger strategy to position MVP as a key player in the renewable energy landscape. The P5 billion deal is expected to fund further expansion and development of solar projects. The article also references other energy-related news, including Meralco's electricity rate increases and the DOE's warnings about power crises in Visayas. However, the main focus is on Leviste's solar firm and its strategic moves. The rebranding to MVP Energy is a clear signal of the company's intent to move forward with a new identity and focus. The P5 billion deal is a major step in securing the company's future in the competitive energy market. The article highlights the importance of strategic rebranding and securing large deals in the renewable energy sector. It also underscores the challenges faced by companies in the energy sector, including controversies and the need for strong financial backing. The rebranding and new deal are part of a broader trend in the energy industry to consolidate and strengthen positions in the face of increasing competition and regulatory challenges.

Ghana’s state-owned Tema Oil Refinery (TOR) has received more than 5mn barrels of crude oil since May 2026, compared with no crude deliveries in 2024, as the company restores refining operations following years of equipment failures and financial difficulties. Managing director Edmond Kombat said the renewed supply reflected improving confidence among crude suppliers and trading partners, according to Joy News reporting on October 26. “TOR has maintained steady supply of crude oil for refinery operations reflecting the renewed confidence among suppliers and business partners, who are once again willing to do business with the refinery,” Kombat said during the government’s accountability briefing in Accra. Deliveries since May have included Nigeria’s Bonga and Bonny Light crude, Côte d’Ivoire’s Baleine grade and Ghana’s Jubilee Medium Sweet crude, which arrived aboard the MT Apache on July 15. Kombat said TOR paid for the Jubilee shipment in full, its first purchase of Jubilee crude in a decade. The refinery also received approximately 950,000 barrels of Sankofa crude from the Ghana National Petroleum Corporation (GNPC) on September 25, strengthening links between Ghana’s offshore petroleum production and domestic refining. The shipment, transported aboard the Sonangol Cazenga, was confirmed in a GNPC statement. GNPC said the cargo was supplied under a commercial arrangement between the two state institutions. Accounts of the total number and size of crude shipments differ, although TOR management reported cumulative receipts exceeding 5mn barrels. The figure represents crude delivered rather than necessarily processed, and an independently reconciled total for refinery throughput was not available. Refining resumes after prolonged shutdown TOR restarted crude processing on December 19, 2025, following turnaround maintenance of its Crude Distillation Unit (CDU) and regulatory clearance from the National Petroleum Authority (NPA). According to Ghana’s Information Services Department, the CDU had been idle since April 2021, while the Residue Fluid Catalytic Cracking Unit (RFCC) had remained shut since 2019. The rehabilitation programme ran from August to October 2025 and was financed from the refinery’s internally generated funds, with engineering work undertaken by TOR personnel. President John Dramani Mahama formally commissioned the refurbished CDU on August 1, 2026, following the earlier operational restart. Kombat said the refinery was processing approximately 28,000 barrels per stream day, below the existing CDU’s capacity range of 45,000–55,000 barrels per stream day. Engineers from Verga Engineering are working with TOR’s technical team on the F-61 crude heater project, intended to restore higher utilisation of the existing processing capacity. The work was expected to be completed around the end of October. Management has also outlined plans to expand refining capacity to 100,000 barrels per day (bpd) in the medium term and eventually 200,000 bpd through further investment and additional processing facilities. The proposed expansion programme remains subject to engineering, financing and implementation arrangements. The government aims to meet 70% of Ghana’s petroleum-product demand through domestic refining by 2028. Fitch Solutions said in April that TOR’s restart would leave Ghana broadly oil-trade neutral or a modest net exporter in 2026, limiting the direct impact of global oil-price spikes on its trade balance. Foreign-exchange gains support financial recovery TOR’s recovery programme has also focused on restructuring debts, strengthening financial controls and restoring commercial relationships. When the current management took office in 2025, the refinery had accumulated losses of approximately GHS10bn ($858mn at the October 26 exchange rate), debts of about $517mn and six years of outstanding audited accounts, Kombat said. The company subsequently completed its financial audits for 2019–2024 and submitted its 2025 accounts, which showed a return to profitability after years of losses. The State Interests and Governance Authority (SIGA) reported that TOR recorded a pre-tax profit of GHS1.24bn ($106mn) in 2025, its first in a decade. However, the earnings recovery was substantially supported by financial and accounting gains rather than renewed crude processing alone. According to SIGA’s assessment, TOR recorded foreign-exchange gains of approximately GHS1.3bn ($112mn) and GHS155mn ($13.3mn) in income from associates during 2025. The foreign-exchange gains exceeded the reported pre-tax profit, while crude processing resumed only in December, limiting the contribution of renewed refining operations to the year’s financial results. TOR’s commercial-operations revenue increased by more than 36% in 2025 compared with 2024, according to management, although the company’s activities also include petroleum storage and related services. Kombat said efforts to reduce legacy obligations had strengthened TOR’s financial position. Separately, he reported that debt had declined from approximately $650mn to $300mn under a restructuring programme, although that comparison has not been reconciled with the $517mn historical debt figure disclosed for the start of the current management’s tenure. The revival of domestic refining could help Ghana retain more value from offshore crude production and reduce reliance on imported petroleum products. TOR says about 40% of Burkina Faso’s fuel consumption is now supplied through Ghana, up from roughly 15% in January 2025. Crude pricing remains a constraint for domestic refiners. In August, Mahama directed energy and finance officials to examine whether TOR and the privately owned Sentuo Oil Refinery could buy Ghanaian crude in cedis rather than dollars, after Sentuo complained that dollar-linked purchases were squeezing its margins. No change to the payment framework has been confirmed. However, the refinery’s longer-term recovery will depend on sustained crude supplies, higher processing rates, commercial profitability from refining itself and the financing of planned capacity expansion. See IntelliNews: Ghana targets doubling capacity at Tema Oil Refinery to 100,000 bpd See IntelliNews: Ghana’s TOR pursues deeper GOIL ties as refinery recovery gathers pace See IntelliNews: Ghana handles 40% of Burkina Faso fuel amid Sahel supply squeeze See IntelliNews: Ghana’s dollar-pricing dispute complicates Tullow crude sale to Sentuo refinery See IntelliNews: Ghana insulated from oil shocks as refinery restart steadies energy outlook, says Fitch

US-traded oil companies have seen their share prices jump by 55% this year as the Iran war has driven energy prices higher. Adam Phillips of EP Wealth Advisors says this is still a good time to buy energy shares. Here's why: #News #Reuters #Newsfeed #OilMajors #Exxon #Chevron #Shell #BP #Total #IranWar #EnergyPrices #OilStocks #EnergyMarkets #BusinessNews #MarketsNews #CrudeOil #SP500 #EnergySector #2026…

Kenya is seeking a trading name for Turkana crude as Gulf Energy targets December 1 first oil, but export dates diverge and compensation disputes persist.

Mozambique’s parliament approved a MZN3.5746bn ($55.9mn) increase to the 2026 state budget on October 24, allocating previously collected natural gas revenues to roads, flood recovery, damaged public buildings and a parliamentary complex amid opposition concerns over spending priorities and implementation deadlines. The amendment to the Economic and Social Plan and State Budget (PESOE) passed by 164 votes to 62 during an extraordinary session in Maputo attended by 226 of the 250 deputies. The governing Frelimo party supported the measure, while Podemos, Renamo and the Democratic Movement of Mozambique (MDM) opposed it, Diário Económico reported on October 25, citing Portuguese news agency Lusa. The revision incorporates unspent Rovuma Basin gas revenues carried forward from the previous financial year and held in the transitional account of Mozambique’s sovereign wealth fund. It does not represent additional gas revenue collected in 2026. The amendment more than doubles the oil and gas revenue allocated to the 2026 budget, to MZN6.518bn from MZN2.9434bn, according to details released by parliament’s standing committee and reported by Notícias. Under the sovereign wealth fund framework approved by parliament in December 2023, 60% of revenue from the first 15 years of gas production in the Rovuma Basin’s Areas 1 and 4 goes to the state budget and 40% to the fund. Louveira said in May that Mozambique expected $76.8mn in gas revenue in 2026, down from $79.2mn in 2025. Most current output comes from the Coral South floating LNG platform operated by Eni (BIT:ENI), and the $7.2bn Coral North platform is due to double production from 2028. Finance Minister Carla Louveira said MZN1.2bn would finance road and bridge rehabilitation, MZN1.1746bn reconstruction following the 2026 floods, and MZN700mn the restoration of public buildings damaged during the 2024–2025 post-election unrest. A further MZN500mn, approximately 14% of the additional allocation, is earmarked for the planned parliamentary complex in Mocuba, Zambézia province, according to O País. Construction is expected to take about two years, with the foundation stone due to be laid in the coming days, state news agency AIM reported. The project was already included in government planning, and the allocation does not represent its total construction cost. Louveira said the additional spending would be financed from available domestic resources without new borrowing. Total budgeted expenditure rises from MZN520.6342bn to MZN524.2088bn, equivalent to 32.1% of GDP, while domestic resources increase from MZN442.9527bn to MZN446.5273bn, or 27.3% of GDP. The revision adds approximately 0.7% to previously planned expenditure. Because domestic resources and spending increase by the same amount, their nominal difference remains unchanged, although that calculation does not by itself establish the government’s fiscal deficit. The government initially approved the proposed amendment on May 26 to support public investment and reconstruction following floods and post-election disturbances. Opposition lawmakers questioned whether the additional allocations could be contracted and spent effectively before year-end. MDM deputy Judite Macuácua argued that the remaining two months were insufficient for procurement procedures, while Renamo deputy Glória Salvador said outstanding payments to teachers, contractors and suppliers should take priority. Podemos, the largest opposition party, said its position was not one of automatic rejection but called for the funds to be distributed according to transparent criteria, AIM reported. The concerns follow weak execution of previously approved gas-funded investments. Mozambique spent MZN1.0999bn, or 37.37%, of the MZN2.9434bn allocated to strategic projects financed by Rovuma gas revenues during the first half of 2026, according to government figures reported by Carta de Moçambique. That execution rate concerns earlier allocations, not the spending authorised on October 24. Parliamentary approval permits the revised expenditure, but does not establish that the projects have been contracted or the funds disbursed. Parliament’s final ordinary session of the year opens on October 28 and runs until December, with the proposed 2027 budget and the government’s 2025 financial accounts also on the agenda. See IntelliNews: Technip Energies wins €1bn Coral Norte FLNG contract in Mozambique in partnership with JGC, Samsung See IntelliNews: ExxonMobil lifts force majeure on $30bn Rovuma LNG in Mozambique as security outlook improves

Kenya has invited proposals for a commercial trading name for crude oil from the South Lokichar Basin in Turkana County as Nairobi-based Gulf Energy targets December 1 for the start of production, more than 14 years after the resource was discovered. The State Department for Petroleum opened the naming exercise on October 23, with submissions due by 5pm on October 29, according to a notice published by the Energy and Petroleum Regulatory Authority (EPRA). The name is intended to identify Kenyan crude in international trading, shipping and price reporting, following established grades such as Brent and Nigeria’s Bonny Light. Proposals must be distinctly Kenyan and easy to pronounce, represent the whole country rather than a single county, community or company, be free of political, religious or divisive associations and be available for trademark registration in Kenya and internationally. Gulf Energy plans to begin drilling on November 1, with first oil targeted for December 1, Business Daily reported on October 24. Production from Blocks T6 and T7, formerly 10BB and 13T, is expected to reach 20,000 barrels per day (bpd) during the first phase, covering 2026–2032, before increasing to 50,000 bpd from 2033. These are development targets, not confirmed start-up volumes. Initial production will focus on the Ngamia and Amosing fields, with crude transported by insulated road tankers to the Kenya Petroleum Refineries Limited facility at Changamwe, Mombasa, for export through the Kipevu Oil Terminal II. The arrangement avoids waiting for an export pipeline but requires temperature-controlled transport and heated storage because of the crude’s high wax content. The Changamwe facility has belonged to Kenya Pipeline Company (NSE:KPC) since a 2023 share transfer, and Nigeria’s Dangote group confirmed this month that it had bought a 24.76% stake in KPC for $327mn. See IntelliNews: Nigeria’s Dangote confirms $327mn purchase of 24.76% stake in Kenya Pipeline Company The export timetable remains uncertain. EPRA petroleum and gas director Edward Kinyua said in September that the first export cargo was expected in the first quarter of 2027, in line with the field development plan, according to the Kenya News Agency. President William Ruto said on October 20 that sales to foreign buyers would begin in December. Energy Cabinet Secretary Opiyo Wandayi said on October 23 that crude should begin moving from South Lokichar to Mombasa for export from the beginning of December, while Senate energy committee chairman William Kisang said Kenya was on course to export its first crude on December 1, The Star reported. No confirmed shipment date has reconciled the statements. See IntelliNews: Kenyan president targets December oil exports, ahead of regulator EPRA’s 2027 timetable The project also faces community grievances. Turkana elders warned earlier in October that they could obstruct extraction and transportation over alleged unpaid compensation. Kenya’s National Gender and Equality Commission separately reported complaints about land acquisition, consultation and possible displacement near Amosing. Chairwoman Rehema Jaldesa said approximately 3,600 people faced compulsory land acquisition and called for fair compensation and greater local economic participation. Gulf Energy’s social performance manager, John Eris Lothike, said the company was committed to supporting host communities. The status of disputed compensation claims remains unclear. Gulf Energy acquired the project from Tullow Oil (LSE:TLW; GSE:TLW) through affiliate Auron Energy E&P Limited in September 2025 for minimum consideration of $120mn, partly deferred. Tullow subsequently received an additional $9mn for relinquishing its royalty and future participation rights. See IntelliNews: Tullow Oil to exit Kenya with $120mn Gulf Energy deal Parliament ratified the revised field development plan in February 2026, although parliamentary disclosures identified requirements to transfer the environmental and social impact assessment licence from Tullow and conduct supplementary assessments for the revised development and transport arrangements. Their completion status has not been confirmed. A drilling rig leased from the UAE’s Great Wall Drilling Company arrived at Mombasa on September 25, and Kisang said it had since been delivered to South Lokichar, according to The Star. Oil was discovered in South Lokichar in 2012, and Kenya exported a pilot shipment of about 200,000 barrels in August 2019 under its Early Oil Pilot Scheme, but sustained commercial production did not follow. See IntelliNews: Kenya allocates $12.90mn to revive stalled Turkana oil project The government has not announced when the trading name will be selected or whether a binding export sales contract has been concluded. The naming exercise does not itself establish regulatory clearance, production readiness or a confirmed buyer.

Senegal’s state-owned oil company Petrosen is seeking investment partners for the Yakaar-Teranga offshore gas project, targeting a final investment decision (FID) by the end of 2027, the African Energy Chamber (AEC) said in a media release. Mouhamadou Diop, chief executive of Petrosen Trading & Services, outlined the timeline at African Energy Week 2026 in Cape Town last week. The project is central to Senegal’s plans to expand domestic gas supplies, support power generation and develop gas-intensive industries. “Yakaar-Teranga has the potential to be truly transformative for Senegal. The main question surrounding the project is economic competitiveness and sovereignty,” Diop was quoted by the AEC as saying. Located in the Cayar Offshore Profond block north of Dakar, the Yakaar-Teranga discoveries hold an estimated 25 trillion cubic feet (tcf), equivalent to about 707.9bn cubic metres (bcm), of gas in place, according to US independent oil and gas exploration and production company Kosmos Energy (NYSE/LSE: KOS). Under an agreement with the Senegalese government, Kosmos Energy formally withdrew from the project in April 2026, leaving Petrosen with full control of the licence. “Deep offshore projects are complex and require a lot of capital,” Diop said. “Therefore, the government of Senegal has made it a national priority to make the country more attractive to investment in order for us to fully maximize the true potential of our offshore resources.” The proposed first phase requires about $2.5bn and targets production of 150mn–300mn cubic feet (mmcf) per day, or about 4.25mn–8.50mn cubic metres (mcm) per day. A second phase, estimated to cost $5bn, would support downstream industries, including fertiliser manufacturing and petrochemicals. The development concept prioritises domestic gas supply, while an earlier plan also envisaged exports. Dominique Gadelle, vice-president for front-end, markets and solutions at Technip Energies (Euronext Paris: TE), noted that commercial agreements would be important to advancing the project. “We need commercial and contractual arrangements before reaching FID,” Gadelle said. “We are seeing positive signs and are very optimistic about the future of the MSGBC basin.” Senegal’s government has identified domestic gas development as a priority to reduce reliance on imported fuels and support power generation and industry. State control gives Senegal greater influence over how the resource is developed, but meeting the FID target will depend on credible financing, commercial viability and an executable project design, says NewsBase Horizon, a dedicated advisory division of NewsBase.

Nigerian industrialist Aliko Dangote has outlined plans for fuel pipelines, storage depots and distribution corridors across East, Central and Southern Africa, with Namibia, Djibouti and Cameroon among the proposed hubs under his group’s wider $50bn investment programme through 2030. Speaking at the Financial Times Africa Summit in London on October 21, Dangote said the group was expanding infrastructure to distribute refined petroleum products from Nigeria to regional markets. “We are very aggressive with that,” Dangote said during an interview with Financial Times Africa editor David Pilling. Dangote, Africa’s richest man, also cited the group’s purchase of a 24.76% stake in Kenya Pipeline Company (NSE:KPC), the operator of Kenya’s main refined-products pipeline network, which was disclosed at the same event. See IntelliNews: Nigeria’s Dangote confirms $327mn purchase of 24.76% stake in Kenya Pipeline Company Djibouti corridor to serve Ethiopia In East Africa, Dangote outlined a distribution corridor linking Djibouti with Addis Ababa through pipelines and storage facilities. The group and Ethiopian Investment Holdings announced a $660mn project in September involving a 120-kilometre pipeline from Damerjog in Djibouti to Dewele in Ethiopia, supported by storage terminals at both ends, according to Bloomberg. Operations are expected to begin within 18 months. Dangote and Ethiopian Investment Holdings are also developing a separate $160mn petroleum terminal at Damerjog, planned to have 375,000 cubic metres of storage and transit capacity of up to 5mn tonnes of petroleum products a year. Djibouti handles more than 90% of landlocked Ethiopia’s maritime trade, and fuel deliveries along the corridor still depend largely on road tankers, with about 350 trucks a day moving fuel towards Ethiopia earlier this year. See IntelliNews: Dangote, Ethiopian Investment Holdings launch $660mn Djibouti fuel pipeline project See IntelliNews: Djibouti expands fuel corridor with rail-linked terminal for direct shipments to Ethiopia Namibia as Southern Africa gateway Namibia would serve as a gateway to Southern Africa, with refined products shipped from Dangote’s Lagos refinery for onward distribution to Botswana, South Africa and other markets. “From our refinery to Namibia is just about four days of steaming,” Dangote said. The group previously outlined a proposed fuel pipeline network extending approximately 2,650 kilometres across Southern Africa, at an estimated cost of more than $3.5bn. The routes would run from Namibia through Botswana towards South Africa, with another corridor extending through Zimbabwe and Zambia towards the Democratic Republic of Congo. “Right now, the budget is over $3.5 billion, but it’s not the only pipeline we are doing,” Dangote told Bloomberg television in September, adding that the wider African network could eventually total almost 4,000 kilometres. Dangote shipped 158,000 tonnes of fuel to Southern Africa in 2025 and a record 30,000 barrels per day (bpd) to South Africa in March 2026, according to S&P Global. See IntelliNews: Dangote plans $3.5bn-plus Namibia-Botswana-South Africa fuel pipeline Dangote Industries Namibia has begun seeking environmental approval for a proposed petroleum storage terminal at Walvis Bay with a planned capacity of 1.6mn barrels. The current application concerns the subdivision of about 68 hectares of industrial land and does not authorise construction, according to Market Watch. Namibia’s National Planning Commission has put the terminal’s cost at about $140mn. Dangote also said a separate distribution infrastructure project in Cameroon was approaching finalisation, without specifying its investment value, capacity or commissioning timetable. Refinery expansion lifts export capacity The proposed infrastructure would extend the reach of the Dangote Petroleum Refinery near Lagos, allowing the group to supply more landlocked African markets through coastal storage facilities and inland distribution networks. The refinery, Africa’s largest, was built with a nameplate capacity of 650,000 bpd and completed performance tests at 700,000 bpd in June. Dangote is pursuing a $14.3bn expansion that would raise capacity to about 1.4mn bpd by 2029, increasing the volumes available for export. Nigeria’s seaborne petroleum-product shipments, including coastal movements and exports, averaged 561,000 bpd in the second quarter of 2026, against 79,000 bpd in 2023. The refinery has also warned that continued petrol import licences in Nigeria could push more surplus fuel into regional and international markets. See IntelliNews: Nigeria’s Dangote says petrol imports may push more fuel to export markets Much of the network still at planning stage The approximately $50bn investment envisaged between 2026 and 2030 covers the group’s industrial businesses, including mining, manufacturing, ports and energy, rather than fuel distribution alone. While the Djibouti-Ethiopia project was formally launched in September, much of the Southern African infrastructure remains at the planning or permitting stage. No consolidated financing package or construction timetable has been disclosed for the wider network.

Italian energy major Eni (BIT: ENI) finalised the operational commissioning of the Bouri Gas Utilisation Project in Libya’s offshore area,