OPEC+ left December production targets unchanged on November 1, deferring any fresh policy move into next year as the group grapples with Iran war export disruptions

The US has hit a record high in oil production for September, even amid oversupply worries. The boom is led by the Gulf region and New Mexico! #EIA #OilProduction #EnergyNews

Nature, Published online: 27 October 2026; doi:10.1038/d41586-026-03388-2Output of the greenhouse gas from the Permian Basin has remained near constant over a period during which oil and gas...

Nature, Published online: 27 October 2026; doi:10.1038/d41586-026-03388-2Output of the greenhouse gas from the Permian Basin has remained near constant over a period during which oil and gas...

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

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.

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.

Canadian energy company TAG Oil reported that no formation oil reached the surface during initial production testing of its T-200 vertical well at the Badr Oil Field in Egypt's Western Desert

BP is advancing a phased programme to lift output from four Kirkuk oil fields to as much as 1.5mn bpd, a North Oil Co.

Significant oil production cut in the US Gulf as Hurricane Isaias approaches, impacting energy output and causing price hikes. #OilProduction #HurricaneIsaias #EnergyCrisis

Cenovus Energy looks to grow as it signs $5.7B deal to buy Athabasca Oil: Athabasca Oil has 40,000 barrels per day of oilsands production currently, but Cenovus Energy sees the opportunity to ratchet that up to 115,000 by 2032. #CenovusEnergy #AthabascaOil #Oilsands #EnergyInvestment #OilProduction

Oil flows through the Strait of Hormuz have topped 13.5mn barrels a day, led by a surge in Saudi Gulf loadings, Commodity Context's tally of Kpler data showed on September 25.

TotalEnergies and AMNI reached a Final Investment Decision for $800 million to unlock the Ima gas field, targeting 350 million cubic feet of daily production starting in October 2028.

DMEA - Downstream Middle East & Africa Nigeria’s Dangote Petroleum Refinery plans to invest $14.3bn to double processing capacity to 1.4mn barrels per day (bpd) by 2029 as it moves ahead with an initial public offering expected to be Africa’s largest ever. The privately held refinery signed offering documents with advisers and other transaction parties in Lagos on September 7. Its IPO prospectus sets out the expansion from a current crude-processing capacity of 700,000 bpd, 50,000 bpd above its original nameplate capacity. The company plans to offer 4.1bn ordinary shares at NGN525 each, raising about NGN2.15 trillion ($1.63bn) if fully subscribed. Reuters reported that subscriptions are scheduled to run from September 14 to October 13, with trading potentially beginning in late November. The offer includes an option to issue up to 30% more shares in the event of excess demand, subject to regulatory approval. The refinery has secured a $400mn underwriting commitment for the IPO as part of a wider $1bn programme structured by Dubai-based advisory firm Marob Strategies and Consulting and Washington-based investment group Lilium Capital. The commitment, provided through Lilium subsidiary Pan-African Refinery Investment SPV, is equivalent to roughly 25% of the $1.63bn base offer. The $400mn commitment is due to be implemented when the offer launches, subject to market conditions, corporate and regulatory approvals and applicable securities laws, and therefore does not represent proceeds already received. The $1bn programme also included a completed and fully funded $600mn private placement. Reuters reported in August, citing a source familiar with the matter, that the refinery had submitted an application to Nigeria’s Securities and Exchange Commission for a $5bn IPO, although the final size had not then been determined. The smaller approved offer may be easier for the market to absorb, while increasing the focus on valuation. At $1.63bn, the base IPO would raise an amount equal to about 11% of the stated $14.3bn expansion cost, although the proceeds are not necessarily earmarked solely for the expansion. Aliko Dangote, founder of Nigerian industrial conglomerate Dangote Group and majority shareholder in the refinery, has said the company has other funding options, including cash generation, bonds and private placements, and that broadening African ownership is a central objective of the offering. At the NGN525 offer price, the refinery’s 120.13bn existing registered shares imply a pre-IPO equity valuation of about $47bn. Including the 4.1bn new shares in the base offer would increase the implied post-IPO market capitalisation to roughly $49bn if the offer is fully subscribed, before any additional shares issued under the up-to-30% overallotment option. The IPO prospectus showed an after-tax profit of $1.82bn in the first half of 2026, compared with a $476mn loss for the whole of 2025, according to Reuters. The $20bn refinery, which began operations in 2024, has reduced Nigeria’s dependence on imported fuels while exporting products including jet fuel and diesel elsewhere in Africa and Europe. Chief executive David Bird told Reuters on September 8 that the expansion would add petrochemical and refining units, increase import substitution and allow the refinery to produce different specifications of diesel. Separately, Aliko Dangote said United Arab Emirates state oil company ADNOC had expressed interest in investing in the refinery alongside other potential partners, although he gave no details, citing confidentiality agreements. ADNOC is in talks to invest in refining businesses in Thailand and Nigeria as it seeks to secure outlets for crude and expand its international fuel-trading operations, Bloomberg reported, citing people familiar with the discussions.

Chevron plans to invest $7bn in Venezuela over the next five years as it targets more than a doubling of its oil production in the South American country to 600,000 barrels per day (bpd). The US oil major said on September 2 that it had been awarded two additional fields in Venezuela’s Orinoco Belt, home to the bulk of the country’s vast extra-heavy crude reserves. Chevron currently produces about 280,000 bpd in Venezuela. Under the new agreements, the company’s Petroindependencia joint venture with state-owned PDVSA will incorporate two adjoining areas in the Carabobo region of the Orinoco Belt. Chevron said the agreements also provide improved fiscal, commercial and legal terms, although it did not disclose those terms. Chevron currently participates in three Venezuelan joint ventures: Petroindependencia and Petropiar in the Orinoco Belt, and Petroboscán in Zulia state. The announcement represents the first substantial, company-specific capital and production commitments emerging from Venezuela’s latest contractual overhaul. Venezuela’s current oil output is around 1.25mn bpd, and Chevron’s current output is about 22% of that. Chevron’s planned 600,000 bpd output would be equivalent to nearly half today's national output—although Venezuela's overall production is expected to rise substantially over the same period. Chevron’s expansion would deepen the company’s position in the country as Washington seeks to attract private investment to revive an oil industry hampered by years of underinvestment and deteriorating infrastructure. The US company is currently the only US oil major producing in Venezuela. “With improved terms and additional acreage, we are strengthening a portfolio that we believe can deliver attractive low-cost oil growth, support energy supply and create differentiated long-term value,” Chevron chief executive Mike Wirth said. Energy Secretary Chris Wright was visiting Venezuela when Chevron made the announcement. He put Venezuela’s national production target at 2mn bpd by the end of 2030, an official goal, not an independently validated forecast. Chevron’s announcement follows a series of moves by the Trump administration to increase US involvement in Venezuela’s key oil sector. President Donald Trump announced on August 28 that the US had secured majority control over 65bn barrels of Venezuelan crude reserves, equivalent to roughly a fifth of the country’s estimated 303bn barrels. Washington has separately also partnered with private oil company North American Blue Energy Partners (NABEP), which has received concessions from Venezuela’s interim government covering 17 oilfields. NABEP has granted the US Defence Department a 35% equity interest. The deals follow the US capture of former Venezuelan president Nicolás Maduro in January and Washington’s subsequent move to exert control over the country’s oil exports. The US has worked with interim president Delcy Rodríguez, Maduro’s former vice president, as it seeks to restructure Venezuela’s ailing oil sector and bring in foreign capital. Venezuela’s oil industry has suffered from many years of under-investment, corruption and crippling US sanctions.

OPEC oil output climbed further in July as Gulf members restored supplies shut during the Iran war, a Reuters survey found, though total output remains well below pre-conflict levels.

Gulf Keystone Petroleum (GKP), the largest independent producer in the Kurdistan Region of Iraq, has resumed Shaikan output after a second precautionary halt over regional security

Gulf Keystone Petroleum (GKP), the largest independent producer in the Kurdistan Region of Iraq, has resumed Shaikan output after a second precautionary halt over regional security. In its half-year report released on August 25, the London-listed operator said gross output at Shaikan, in Duhok Governorate, restarted on August 16 and was approaching 40,000 barrels per day, with well activities under way to lift volumes further. The field had been shut in twice this year. The first stoppage ran from February 28 to June 23, after which production ramped up above 45,000 bpd before a second suspension between July 19 and August 15. Gross average production in the first half slumped to 14,600 bpd, from 44,100 bpd in the same period of 2025. CEO Jon Harris said the interruptions had tested the company but that decisive cost action had preserved liquidity. “GKP’s operational and financial performance in the first half of 2026 demonstrated the resilience of our business, our people and the Shaikan Field through a period of significant regional disruption,” he said, adding that the priority had been “the safety of our workforce while decisive action to reduce expenditures has enabled us to minimise cash outflow, maintain a robust, debt-free balance sheet and pay a $12.5 million dividend to shareholders”. Revenue on an entitlement basis was broadly flat at $82.8mn, against $83.1mn a year earlier, as an average realised price of $83.5/bbl — a $8.8/bbl discount to Dated Brent — offset the volume decline. Cash receipts under the tripartite interim export arrangement equated to roughly $30/bbl, with the balance accruing as a top-up receivable. Adjusted EBITDA rose to $51.7mn from $41.1mn, helped by a 25% cut in operating costs to $20.2mn. Free cash outflow was held to $2.0mn. Cash stood at $63.5mn on August 24, with no debt. The board declared a further semi-annual dividend of $10mn. Net capital expenditure of $18.3mn was directed at safety-critical upgrades, workovers and the PF-2 water handling facility, which remains on schedule for start-up in the first quarter of 2027. Harris said the interim export agreements between international oil companies, the Federal Government of Iraq and the Kurdistan Regional Government — extended for six months to end-January 2027 — had “worked effectively, with improved remuneration relative to local sales and consistent payments without delay following crude liftings”. Gulf Keystone is pressing for full PSC entitlement at international prices and additional liftings from the third quarter, and is in talks with Kurdistan’s Ministry of Natural Resources on a revised Shaikan field development plan ahead of a possible return to drilling in 2027.

Iran will find ways to deal with new US measures targeting its economy and oil industry, National Iranian Oil Co. (NIOC) chief Hamid Bovard said, as Washington ramps up pressure on Tehran in what US officials have called an “Economic D-Day”.