Oil fell to the lowest since May ahead of a weekend OPEC+ meeting where Saudi Arabia will seek to steer the group toward more production increases in the coming months. West Texas Intermediate slid 2.5% to settle below $62 a barrel, down 3.3% this week. The alliance will hold a virtual meeting Sept. 7 to decide its next move after completing the restart of 2.5 million barrels a day of idled supply at its previous gathering. Saudi Arabia wants to boost production further in a bid to offset lower prices with higher volumes, people familiar with the matter said. No decision has been made, and it’s not clear whether any increase would be agreed upon as soon as Sunday or only in later months. “If the eight OPEC+ countries were to agree on another production increase, we believe this would place significant downward pressure on oil prices,” Commerzbank analysts Barbara Lambrecht and Carsten Fritsch wrote in a note. “After all, there is already a significant risk of a supply surplus.” West Texas Intermediate crude futures have retreated about 14% this year after the shift by OPEC+ — coupled with supply increases from drillers outside the group — exacerbated concerns about a global glut. Market sentiment has also been weighed down by mounting worries over the health of the US economy, where job growth slowed last month. Geopolitical tensions have also been in focus this week, with the US looking to pressure buyers of Russian crude to push Moscow into agreeing on a truce in Ukraine. As part of that effort, Washington has imposed a 50% levy on some imports from India. President Donald Trump said Friday that the US seems to have “lost India and Russia to deepest, darkest China.” “Sentiment in crude markets is poor,” said Daniel Ghali, a

US developers are racing to cash in on the nation’s natural-gas export boom while they still can.  The massive US buildout of terminals that process and ship liquefied natural gas, or LNG, has transformed the nation into the world’s top exporter of the fuel. But plants still in development are facing a tight deadline: By 2027, global LNG supply will exceed demand, BloombergNEF estimates. By 2030, US rival Qatar will have finished its own years-long LNG buildout, further damping appetite for new terminals. And by 2031, a massive pipeline expansion by Gazprom PJSC could begin funneling more of Russia’s natural gas to China, possibly displacing as much as 40 million metric tons of LNG demand per year, according to BloombergNEF. Four US projects with the capacity to export 63 million tons of LNG a year are still awaiting final investment decisions. Even the $35 billion in US plants already under construction face headwinds amid a tight labor market that’s threatening to push back timelines. Golden Pass LNG, being jointly developed in Texas by Exxon Mobil Corp. and QatarEnergy LNG, is coming online in 2025, one year later than scheduled following a worker shortage and the bankruptcy of one of its contractors.  Here are the projects to watch. Louisiana LNG (Under construction) Developer: Woodside Energy Capacity: 27.6 million tons per year Woodside Energy announced its $17.5 billion final investment decision to build Louisiana LNG in late April, after the company acquired Tellurian Inc. in 2024. The facility is under construction in Calcasieu Pass, Louisiana, and targeted to come online by 2029. Corpus Christi LNG Expansion (Under construction) Developer: Cheniere Energy Inc.  Capacity: 3 million tons per year Cheniere Energy Inc., the largest American exporter, last month announced a $2.9 billion expansion of its Corpus Christi plant in south Texas. Two new production trains are slated to start toward the end of the decade, which

A Plains All American Pipeline LP and Plains GP Holdings subsidiary has agreed to acquire from subsidiaries of Diamondback Energy Inc. and Kinetik Holdings Inc. a 55% non-operated interest in EPIC Crude Holdings LP, the entity that owns and operates the EPIC crude oil pipeline, in a deal valued at about $1.57 billion, inclusive of about $600 million of debt. “By further linking our Permian and Eagle Ford gathering systems to Corpus Christi, we are enhancing market access and ensuring our customers have reliable, cost-effective routes to multiple demand centers,” said Plains chairman, chief executive officer, and president, Willie Chiang.  Plains also has agreed to a potential $193 million earnout payment should an expansion of the pipeline to a capacity of at least 900,000 b/d be formally sanctioned before yearend 2027. Diamondback Energy and Kinetik Holdings each agreed to sell their respective 27.5% equity interest, which they reached with acquisitions in September 2024, for about $500 million in net upfront cash and a $96 million share of the total potential $193-million contingent cash payment related to the potential expansion. Diamondback will maintain its commercial relationship with the EPIC Crude and Plains teams as an anchor shipper on the EPIC Crude pipeline, said Kaes Van’t Hof, chief executive officer and director of Diamondback Energy, in a separate release Sept. 2. The remaining 45% interest in EPIC Crude Holdings is owned by a portfolio company of Ares Management Corp. (EPIC Management), which also serves as operator. The EPIC assets include over 800 miles of long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi, Tex., with current operating capacity over 600,000 b/d. Other assets include total operational storage of about 7 million bbl and over 200,000 b/d of export capacity. EPIC Crude includes terminals

Equinor Canada Ltd. signed a head of agreement (HoA) with BW Offshore, confirming its selection as preferred bidder for the floating production, storage and offloading (FPSO) unit for the Bay du Nord deepwater oil project offshore Newfoundland and Labrador, Canada. Equinor operates Bay du Nord, Canada’s first deepwater oil project, in partnership with bp plc. The project holds an estimated 400 million bbl of recoverable light crude in its initial phase. The oil discovery lies in the Jurassic reservoirs of the Flemish Pass basin, about 500 km east of St. John’s in 1,170 m of water. Later discoveries, and potential tie-ins, lie in adjacent exploration licence EL1156 (Cappahayden and Cambriol) in waters about 650 m deep.  Development of  the project was postposedin 2023 for up to 3 years due to “changing market conditions and subsequent high cost inflation,” according to Equinor. During that time, however, Equinor and bp have advanced work to actively mature the project toward future development.  Under the newly signed HoA, Equinor and BW Offshore will continue to advance discussions on all technical and commercial aspects of the FPSO project. These include further maturation of design through front-end engineering design (FEED) work, and agreeing on a commercial solution. The FPSO will be tailored for the harsh environment of the sub-Arctic. The unit is expected to support production of up to 160,000 b/d of oil and will feature a disconnectable turret system and extensive winterization, BW Offshore said. The topside will include emission reduction initiatives such as high-efficiency power generation and heat recovery, variable speed drives and a closed flare system. The FPSO also will be designed for future tiebacks. Following pre-FEED completion mid-September, the two companies are expected to enter into a bridging phase to prepare for FEED in early 2026, subject to approvals by Equinor and bp.

Chevron Corp. has officially taken over operatorship of AREA OFF-1 block in Uruguay and 3D seismic acquisition on the block is expected late in this year’s fourth quarter. Handover of the South American block occurred in first-half 2025, partner Challenger Energy Group PLC said in a half-year report Sept. 3. In November 2024, Chevron completed a farm-in with Challenger to acquire a 60% interest in the offshore block, along with “various work streams necessary to prepare for 3D seismic acquisition,” Challenger’s chief executive officer Eytan Uliel told stakeholders. Uliel noted the start of seismic acquisition is still subject to finalization of permitting by the Uruguayan Ministry of Environment, “a process which is well advanced,” he said. In July, Challenger said the Ministry has consultations planned ahead of permit issuances, and that a final consultation was expected late that month. At the time, Challenger said it expected permits to be granted in August/September.  Chevron will carry the full cost of the seismic campaign up to a total program cost of $37.5 million. The 14,557-sq km block lies about 100 km offshore in water depths of 80-1,000 m, and holds prospective inventory of about 2 billion bbl of recoverable resource (Pmean) through multiple prospects (Teru Teru, Anapero, Lenteja) in a range of play types, according to Challenger.  Elsewhere in Uruguay, Challenger progressed work at the 13,000 sq km AREA OFF-3 block, substantially completing its planned technical work program in August. The primary geotechnical work focused on the licensing, reprocessing, and interpretation of a 1,250 sq km 3D seismic data set. Other subsurface studies addressed the geochemistry and further de-risked AREA OFF-3 exploration potential, the company said. The company began a formal farmout process for the block on Sept. 1.

Turkish Petroleum Corp. (TPAO) has let an engineering, procurement, construction, installation, and commissioning (EPIC) contract to Wison New Energies Ltd. for the floating production unit (FPU) to be utilized as part of Phase 3 of Sakarya gas field development. Sakarya lies about 170 km offshore the western Black Sea in block AR/TPO/KD/C26-C27-D26-D27 in 2,150 m of water. It is Türkiye’s largest-ever natural gas discovery and contains 405 billion cu m proven gas reserves. It was discovered in August 2020 and is being developed in three phases by TPAO. The gas field development project includes an offshore production system on the seabed, an onshore gas processing unit, and a 170-km pipeline system connecting the two.  The FPU must comply with deepwater operations and navigate the Bosphorus Strait’s 56-m air draft restriction. It will be anchored to the seabed in four groups with a total of 20 rope systems in an area about 180 km offshore where it will remain stationary. The unit is designed with a gas export rate of 25 MM std cu m/d (883 MMscfd), a produced water treatment capacity of 1,350 cu m/d, and a MEG regeneration and injection capacity of 2,503 cu m/d for hydrate inhibition, with a minimum 30-year design life. It is expected to be commissioned in mid-2028 with Phase 3 starting commercial production in 2030. Total Phase 3 production is expected to reach 40 million cu m/d. TPAO is operator of the field and holds 100% interest.