WASHINGTON — The U.S. Department of Energy (DOE) today announced the award of contracts for the initial phase of the Strategic Petroleum Reserve (SPR) Emergency Exchange as directed by President Trump. The first oil shipments began today—just nine days after President Trump and the Department of Energy announced the United States would lead a coordinated release of emergency oil reserves among International Energy Agency (IEA) member nations to address short-term supply disruptions. Under these initial awards, DOE will move forward with an exchange of 45.2 million barrels of crude oil and receive 55 million barrels in return, all at no cost to the taxpayer. This represents the first tranche of the United States’ 172-million-barrel release. Companies will receive 10 million barrels from the Bayou Choctaw SPR site, 15.7 million barrels from Bryan Mound, and 19.5 million barrels from West Hackberry. “Thanks to President Trump, the Energy Department began this first exchange at record speeds to address short-term supply disruptions while also strengthening the Strategic Petroleum Reserve by returning additional barrels at no cost to taxpayers,” said Kyle Haustveit, Assistant Secretary of the Hydrocarbons and Geothermal Energy Office. “This exchange not only maintains reliability in the current market but will generate hundreds of millions of dollars in value in the form of additional barrels for the American people when the barrels are returned.” This initial action will ultimately add close to 10 million barrels to the SPR’s inventory when the barrels are returned. Taxpayers will benefit from both the short-term support for global supply and long-term growth of the SPR’s inventory. This helps protects U.S. and global energy security. The Trump Administration continues to pursue additional opportunities to strengthen the reserve and restore its long-term readiness as a cornerstone of American energy security. For more information on the Strategic Petroleum Reserve and DOE’s

In this Then & Now episode of the Oil & Gas Journal ReEnterprised podcast, Managing Editor and Content Strategist Mikaila Adams reconnects with Deborah Byers, nonresident fellow at Rice University’s Baker Institute Center for Energy Studies and former EY Americas industry leader, to revisit a set of questions first posed in 2017. In 2017, the industry was emerging from a downturn and recalibrating strategy; today, it faces heightened geopolitical risk, market volatility, and a rapidly evolving technology landscape. The conversation examines how those earlier perspectives have aged—covering oil price bands and the speed of recovery from geopolitical shocks, the role of US shale relative to OPEC in balancing global supply, and the shift from scarcity to economic abundance driven by technology and capital discipline. Adams and Byers also compare the economics and risk profiles of shale and offshore development, including the growing role of Brazil, Guyana, and the Gulf of Mexico, and discuss how infrastructure and regulatory constraints shape market outcomes. The episode further explores where digital transformation—particularly artificial intelligence—is delivering tangible returns across upstream operations, from predictive maintenance and workforce planning to capital project execution. The discussion concludes with insights on consolidation and scale in the Permian basin, the strategic rationale behind recent megamergers, and the industry’s ongoing challenge to attract and retain next‑generation talent through flexibility, technical opportunity, and purpose‑driven work.

Eni North Africa, a unit of Eni SPA, together with Libya’s National Oil Corp., plans to develop two new gas discoveries offshore Libya as tiebacks to existing infrastructure. The gas discoveries were made offshore Libya, about 85 km off the coast in about 650 ft of water. Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3), adjacent geological structures, were successfully drilled through the exploration well C1-16/4 and the appraisal well B2-16/4 about 16 km south of Bahr Essalam gas field, which lies about 110 km from the Tripoli coast. Gas-bearing intervals were encountered in both wells within the Metlaoui formation, the main productive reservoir of the area. The acquired data indicate the presence of a high-quality reservoir, with productive capacity confirmed by the well test already carried out on the first well. Preliminary volumetric estimates indicate that the BESS 2 and BESS 3 structures jointly contain more than 1 tcf of gas in place. Their proximity to Bahr Essalam field will enable rapid development through tie-back, the operator said. The gas produced will be supplied to the Libyan domestic market and for export to Italy. Bahr Essalam produces through the Sabratha platform to the Mellitah onshore treatment plant.

Azule Energy has started natural gas production from the New Gas Consortium (NGC)’s Quiluma shallow water field offshore Angola. Start-up of the gas delivery from Quiluma field follows the November 2025 introduction of gas into the onshore gas plant, marking the beginning of production operations. The initial gas export will be 150 MMscfd and will ramp up to 330 MMscfd by yearend, the operator said in a release Mar. 13.  In a separate release Mar. 17, NGC partner TotalEnergies said the startup marks the first development of a non-associated gas field in Angola, noting that the gas produced “will be a stable and important source of gas supply for the Angola LNG plant that is delivering LNG to both the European and Asian markets.” The non-associated gas of NGC Phase 1 will come from Quiluma and Maboqueiro shallow water fields with additional potential related to gas from Blocks 2, 3, and 15/14 areas. An onshore plant will process gas from the fields and connect to the Angola LNG plant, aimed at a reliable feedstock supply to the plant, sited near Soyo in the Zaire province in north Angola. The plant holds a capacity of 400MMscfd of gas and 20,000 b/d of condensates. Azule Energy, a 50-50 joint venture between bp and Eni, is operator of NGC project with 37.4% interest. Partners are TotalEnergies (11.8%), Cabinda Gulf Oil Co., a subsidiary of Chevron (31%), and Sonangol E&P (19.8%).

Equinor Energy AS and partners will consider a tie back of a new oil discovery to Johan Castberg field in the Barents Sea, 220 km northwest of Hammerfest. Preliminary discovery volume estimates at the in the Polynya Tubåen prospect are 2.3–3.8 million std cu m of recoverable oil equivalent (14–24 MMboe). Wildcat well 7220/7-5, the 17th exploration well in production license 532, was drilled about 16 km southwest of discovery well 7220/8-1 well by the COSL Prospector rig in 361 m of water, according to the Norwegian Offshore Directorate. The well was drilled to a vertical depth of 1,119 m subsea. It was terminated in the Fruholmen formation from the Upper Triassic. The objective was to prove petroleum in Lower Jurassic reservoir rocks in the Tubåen formation. The well encountered a 26-m gas column and a 26-m oil column in the Tubåen formation in reservoir rocks totaling 39 m, with good to very good reservoir quality. The total thickness in the Tubåen formation is 125 m. The gas-oil contact was encountered at 972 m subsea, and the oil-water contact was encountered at 998 m subsea. The well was not formation-tested, but extensive volumes of data and samples were collected. It will now be permanently plugged. ‘New’ Barents Sea oil province The discovery comes as Equinor aims to increase volumes in the Johan Castberg area—originally estimated at 500–700 million bbl—by an additional 200–500 million bbl, with plans to drill 1-2 exploration wells per year in the region, Equinor said. “With Johan Castberg, we opened a new oil province in the Barents Sea one year ago. It is encouraging that we are now making new discoveries in the area,” said Grete Birgitte Haaland, area director for Exploration and Production North at Equinor. Production at Johan Castberg began in 2025.  In June 2025, the Drivis

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