WASHINGTON—The U.S. Department of Energy (DOE) today released the finalized Fusion Science and Technology (FS&T) Roadmap, a national strategy to accelerate the development and commercialization of fusion energy on the most rapid, responsible timeline in history. Building on earlier roadmap efforts, the finalized roadmap brings together fusion science, technology, infrastructure, workforce development, and commercialization priorities into a single national strategy to support fusion pilot plants and commercial fusion power in the mid-2030s. Fusion is the process that powers the sun and stars. For decades, scientists and engineers have worked to bring that same process to Earth as a source of abundant, reliable energy. The finalized roadmap outlines how DOE, industry, universities, and national laboratories will work together to accelerate the path toward commercial fusion energy in the United States. This effort advances President Trump’s energy dominance agenda and reinforces the Administration’s commitment to expanding reliable American energy production, strengthening domestic supply chains, and maintaining U.S. leadership in critical technologies. By accelerating progress toward commercial fusion power, DOE is helping secure a future of abundant and reliable energy. “Fusion energy has entered a new era defined by extraordinary scientific progress and public-private momentum,” said DOE Under Secretary for Science Dr. Darío Gil. “With this roadmap, we now have the clarity, coordination, and sustained commitment needed to turn the promise of fusion into a reality for the American people.” Developed with input from more than 800 scientists and engineers across the public and private sectors, the finalized FS&T Roadmap reflects contributions from more than 15 private companies, over 10 National Laboratories, and more than 70 universities. The roadmap identifies the critical science and technology gaps that must be closed to realize fusion pilot plants and strengthen U.S. leadership in the global fusion industry. The FS&T Roadmap establishes a unified strategy for the U.S.

Petroliam Nasional Bhd. (PETRONAS) subsidiary PETRONAS Refinery & Petrochemical Corp. Sdn. Bhd. (PRPC) has agreed to buyout Saudi Arabian Oil Co.’s (Aramco) equity interests in the partners’ dual 50-50 joint ventures responsible for operating the 300,000-b/d integrated refining and petrochemical refinery of the Pengerang Integrated Complex (PIC) in southeastern Johor, Malaysia. Subject to fulfillment of customary closing conditions, Petronas will take 100% ownership and become full operator of Pengerang Refining Co. Sdn. Bhd. and Pengerang Petrochemical Co. Sdn. Bhd., collectively known as PRefChem, Aramco and Petronas said in separate releases. Aramco said divestment of the Malaysian assets will support the strategic optimization of the company’s own downstream portfolio by providing additional flexibility to pursue investments aligned with its broader downstream strategy. While Aramco will no longer hold ownership in the Malaysian ventures, the company said it will continue actively explore commercial arrangements with Petronas following the sale, including continuing its existing agreement to supply Saudi Arabian crude oil to the site, as well as opportunities related to technology exchange and integrated product distribution. Petronas said its move to take full control of the downstream assets will allow the company to further enhance operational alignment and flexibility across PRefChem’s value chain, while harnessing its international oil supply network and integrated operating model to support continued reliability and resilience across varying market conditions. Full ownership of PRefChem’s in-country operations also will strengthen Petronas’ ability to support Malaysia’s long-term energy security and industry resilience, the operator said. A definitive timeframe for when the parties expect to finalize the proposed transaction was not revealed. PRefChem operations In addition to the Johor refinery, PRefChem’s operations at PIC include a steam cracker complex equipped to produce 3.4 million tonnes/year (tpy) combined of ethylene, propylene, butadiene, benzene and raffinate-2. PRefChem also operates an associated petrochemical complex at the

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Chevron Corp. applied June 2 to join Argentina’s Large Investment Incentive Regime (RIGI) for a $13.8-billion unconventional oil development at its 100% operated El Trapial-Este block in northern Neuquén province. Until recently, RIGI had attracted about $93 billion across 36 projects. Chevron’s application, which remains subject to government approval, is equivalent to almost one seventh of that total. The filing, which does not consitute a final investment decision, is Chevron’s largest individual investment proposal in Argentina since it entered the country in 1999 and the second-largest project submitted under RIGI, behind YPF SA’s $25-billion LLL Oil development.  Chevron said it is targeting production of about 30,000 b/d from El Trapial-Este, subject to the availability of takeaway infrastructure. The block currently produces about 7,000 b/d. Chevron tested the block with a 7-well pilot in 2021 and has been carrying out development since late 2022, using laterals of more than 3,000 m and techniques transferred from the US Permian basin. In 2023, Chevron committed $500 million to that phase. During the company’s first-quarter earnings call on May 1, chief executive officer Mike Wirth anchored Chevron’s 2030 targets in “assets that are operating today.” El Trapial-Este was not explicitly identified among assets described as the main base for those targets. Wirth also said Chevron would not accelerate Permian production even with Brent above $100/bbl, preferring to manage that asset for free cash flow rather than volume. In the same presentation, Wirth named Argentina among the sources of equity crude that feed Chevron’s global refining system, along with Tengiz, Guyana, the Permian, and Venezuela. The earnings call came weeks before the El proposal filing.  Vaca Muerta costs, takeaway capacity  Breakeven costs in Vaca Muerta’s best blocks are about $40/bbl at the wellhead, according to Rystad Energy, while normalized well productivity—adjusted for lateral length and fracture

Santos Ltd. has let a contract for the Transocean Equinox semisubmersible mobile offshore drilling unit for a multi-well campaign at Bedout subbasin exploration permits offshore North West Shelf Australia, said partner Carnarvon Energy Ltd. in a June 1 release. The objective of the 2027 Bedout exploration campaign is to define the scale of the subbasin’s resource potential and target some of the largest prospects in the exploration portfolio. Shortlisted prospects include Ara, Yuma, Goats Eye, and Hutton, which are all defined on the Bedout MegaMerge 3D seismic survey. The Bedout exploration campaign is on track to start begin in April 2027, with one firm well and one contingent well. The Transocean Equinox is currently engaged in a multi-well exploration drilling campaign off the coast of Victoria, which is expected to be completed by early 2027.  Bedout basin is proposed to be an integrated gas and liquids project. To date, five fields have been discovered. Net 2C contingent resource of 230 MMboe is booked as of Dec. 31, 2024. Santos is operator at Bedout. Carnarvon holds 20% interest in Yuma, Goats Eye, and Hutton, and 10% interest in Ara.

Underground working natural gas storage capacity in the Lower 48 states increased modestly in 2025, with most additions concentrated in the South Central and Mountain regions, according to the US Energy Information Administration (EIA). Natural gas storage plays a key role in balancing seasonal demand fluctuations, allowing supplies to be injected during periods of lower consumption and withdrawn during periods of peak demand. EIA calculates natural gas storage capacity in two ways: demonstrated peak capacity and working gas design capacity. Both increased in 2025. EIA data show demonstrated peak storage capacity rose by 6 bcf, or 0.1%, from the previous year, marking the third consecutive annual increase. Demonstrated peak capacity is the sum of the largest volume of working gas stored in each storage field during the previous five-year period, regardless of when the peaks occurred. The South Central and Mountain regions posted the largest gains, with demonstrated peak capacity increasing by 16 bcf and 18 bcf, respectively. Capacity declined in other regions, falling 15 bcf in the East, 8 bcf in the Pacific, and 5 bcf in the Midwest. Working gas design capacity, sometimes referred to as nameplate capacity, is based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which federal or state regulators usually must certify.  As of November, Lower 48 design capacity totaled 4,683 bcf, up 26 bcf from a year earlier. The South Central region accounted for most of the increase, adding 21 bcf of design capacity, while the Mountain region added 6 bcf. Design capacity in the East declined by 2 bcf, primarily because of base gas adjustments. Capacity in the Midwest and Pacific regions was unchanged from the previous year.