A/S Norske Shell and its license partners are investing in a new drilling and well intervention campaign at Ormen Lange in the Norwegian Sea. An investment figure was not disclosed. The campaign, which follows the 2025 start of subsea compression to compensate for the natural pressure drop in the reservoir, includes two sidetracks from existing wells to access additional gas volumes, as well as an option for modifications to a third well. First production is expected in 2029, the operator said in an early October release. The campaign is expected to increase recovery by about 3.5 billion cu m of gas over the life of the field. “Ormen Lange has been producing for almost 20 years, but there is still room for further resources. This investment will enable us to produce gas volumes that today’s wells cannot reach efficiently, thereby creating additional value from the field while contributing to reliable gas supplies to Europe,” said Claire Richardson-Dissel, asset manager for Ormen Lange at Norske Shell. Ormen Lange  Norway’s second largest developed gas field, Ormen Lange was Norway’s first deepwater field development. The field is developed without a platform, with all production from subsea installations installed at depths of up to 1,100 m. Gas from sandstone at a depth of almost 3,000 m is piped up the Storeggakanten peninsula to the onshore plant at Nyhamna in Aukra municipality, where it is processed before export to the UK and the EU.  Shell is operator of Ormen Lange with 17.8% interest. License partners are Petoro AS (36.5%), Equinor Energy AS (25.4%), Orlen Upstream Norway AS (14%), and Vår Energi AS (6.3%).

Saturn Oil & Gas Inc., Calgary, has agreed to acquire privately held Corex Resources Ltd. for $302 million (Can.) through a plan of arrangement, expanding its light oil position from southeast Saskatchewan into southwest Manitoba. The acquisition adds about 7,000 b/d of 100% light oil-weighted production and increases Saturn’s forecast 2026 exit production rate to 54,000-56,000 boe/d from its previous outlook, the company said Oct. 19. Corex’s assets lie adjacent to Saturn’s existing southeast Saskatchewan operations. The company said the transaction adds 323 gross (279 net) identified drilling locations, including booked and unbooked development opportunities, as well as potential open-hole multilateral targets. The acquired asset base is characterized by an average working interest of about 96% and includes operated production infrastructure, pipelines, and other infrastructure. Saturn said it has identified about $6 million/year in operating and efficiency synergies. The addition of Corex’s production is not expected to affect Saturn’s full-year 2026 average production guidance of 43,000-44,000 boe/d, but, Saturn said, the deal, along with Saturn’s expanded 2026 capital program, positions the company to exit 2026 with production of 54,000-56,000 boe/d, establishing a base for 2027. The transaction is expected to close in December 2026, subject to customary conditions.

WASHINGTON— The U.S. Department of Energy (DOE) today announced approximately $967 million in additional funding through its Grid Resilience State and Tribal Formula Grant program to modernize critical energy infrastructure, lower electricity costs and strengthen America’s power grid. The funding will support locally driven projects across states, territories, and tribes to upgrade critical infrastructure, prevent power disruptions, and meet growing electricity demand while helping lower costs for American families and businesses. The investment advances President Trump’s American energy dominance agenda. Projects funded through the program will help states, territories, and tribes invest in infrastructure improvements that protect against disruptive events, improve system performance, and ensure communities and businesses have dependable power when they need it most. “Lowering costs and unleashing prosperity are top priorities for President Trump,” said U.S. Secretary of Energy Chris Wright. “These commonsense investments provide resources directly to states, territories, and tribes to lower electricity costs and strengthen grid reliability for American businesses and families.” “A strong and dependable grid is the backbone of American economic prosperity,” said Office of Electricity Assistant Secretary Katie Jereza. “This funding will help Americans across the country, including our tribal partners, optimize their electricity systems and prepare for future growth while strengthening energy security and deploying technologies that can lower the long-term cost of delivering reliable power.” States, tribes, and U.S. territories can view their funding allocations and application instructions here.

Agiba Petroleum Co.—a 50-50 joint venture of Eni SPA subsidiary IEOC Production BV and Egyptian General Petroleum Corp. (EGPC)—has initiated startup activities for its Meleiha Phase 2 project in Egypt’s Western Desert, advancing development of a gas hub in the Merged Meleiha concession. Part of the operator’s development of a new gas hub within the Merged Meleiha concession and designed to increase processing capacity for from the area’s natural gas fields to support growth of Egypt’s domestic output, the planned installation will be equipped to process up to 100 MMcfd of gas production, Eni said in a release Oct. 20. Planned infrastructure at the site includes development wells, gathering systems, trunklines, and a dedicated gas-export pipeline connecting new production to Egypt’s existing gas network. Eni did not reveal a schedule for completing full startup and commissioning activities for Meleiha Phase 2, but—once completed—the company said the project will help enable the rapid monetization of Egypt’s natural resources and enhanced operational efficiency. Western Desert development Meleiha Phase 2 builds on Agiba’s ongoing exploration and development in the Western Desert concession. In April 2022, Eni reported that three discoveries in the Meleiha concessions had been tied into production, adding an estimated 8,500 boe/d. The Nada E Deep 1X well encountered 60 m of net hydrocarbon pay in the Alam El Bueib and Khatatba formations. Meleiha SE Deep 1X found 30 m in the Matruh and Khatatba formations, while Emry Deep 21 encountered 35 m in Alam El Bueib. Including discoveries made in 2021, Eni said the results brought the exploration total to eight wells, with a 75% success rate. Agiba operates the Meleiha concession, in which it holds a 76% interest alongside partner Lukoil PJSC (24%), according to Eni’s website.

Prolonged disruptions to LNG shipments through the Strait of Hormuz are putting mounting pressure on global natural gas markets, with limited spare liquefaction capacity leaving demand reductions as a key mechanism for restoring market balance. Despite elevated prices in Europe and the Asia Pacific, alternative suppliers have limited ability to quickly replace lost Gulf exports, raising the prospect of tighter markets extending into 2027. European gas prices remain elevated as the Northern Hemisphere enters winter with unusually low inventories. Dutch TTF natural gas futures traded around €88/MWh (about $29/MMbtu) on Oct. 19, while EU underground storage stood at 74.6% of capacity as of Oct. 18, compared with a 5-year seasonal average of about 89%. German storage was particularly low, at about 61%. The Strait of Hormuz remains a major supply constraint. Since the Middle East conflict began in late February, around 80% of previously available LNG exports from Qatar and the UAE have been sidelined. Combined exports averaged 1.73 billion cu m (bcm)/month during March–September, compared with a 5-year pre-crisis average of 9.37 bcm/month. Renewed attacks on commercial shipping have complicated prospects for a sustained recovery in shipments. An October analysis by the Oxford Institute for Energy Studies (OIES) suggests that prolonged supply disruptions would be absorbed primarily through reduced LNG imports and demand rather than increased production elsewhere. Using an April 2027 restart of Gulf LNG exports as its modeling baseline, OIES estimates that delaying the recovery until October 2027 would create a 49-bcm supply gap in 2027 relative to that baseline. Other exporters would provide only 7.3 bcm of additional supply, leaving 41.7 bcm, or 85% of the shortfall, to be absorbed through lower imports and demand. US LNG exports offer limited additional flexibility US LNG export installations continue operating at high utilization rates, supported by the substantial

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