3D Energi Ltd said Tuesday it has voluntarily halted trading on the Australian Securities Exchange (ASX), having defaulted on the payment of its share of costs in a ConocoPhillips-led exploration campaign in the Otway basin offshore Victoria. “Joint venture cash calls for the drilling program are higher than originally forecast and a balance of approximately $2.5 million remains outstanding by the company which it does not currently have”, Melbourne-based 3D Energi said in a stock filing. “A default notice has been issued by the joint venture operator to the company with a remedy period to 6th February. “Additional forecast company drilling program expenditure subject to cash calls due on 6th February is currently estimated at approximately $5.3 million, which if not paid by that date may well become the subject of an additional default notice and remedy period. “Consequently, the company is implementing a suspension of the trading of its shares on ASX while it addresses its funding position and the implications of payment default on the level of its ongoing interest in the permit”. 3D Energi plans to resume ASX trading in the first week of February. Earlier this month it announced the Charlemont-1 gas discovery, the joint venture’s second discovery under the VIC/P79 exploration after Essington-1. The newest well targeted the penultimate prospect in the Charlemont trend, which culminates with the La Bella discovery, according to 3D Energi. “Phase 1 of the Otway Exploration Drilling Program has identified important new natural gas resources close to existing offshore gas production and processing infrastructure in the Otway basin, supplying the Australian domestic gas market”, 3D Energi executive chair Noel Newell said in a statement January 14 announcing the second discovery. “This enhances the strategic significance of the discovery and supports future development optionality, subject to further technical and commercial evaluation,

The U.S. Energy Information Administration (EIA) projected that the U.S. natural gas Henry Hub spot price will drop this year and rise next year in its latest short term energy outlook (STEO). In the EIA’s January STEO, which was released on January 13 and completed its forecast on January 8, the EIA forecast that the commodity will average $3.46 per million British thermal units (MMBtu) in 2026 and $4.59 per MMBtu in 2027. The U.S. natural gas Henry Hub spot price averaged $3.53 per MMBtu in 2025, the EIA’s latest STEO showed. According to a quarterly breakdown included in its latest STEO, the EIA sees the U.S. natural gas Henry Hub spot price coming in at $3.38 per MMBtu in the first quarter of 2026, $2.75 per MMBtu in the second quarter, $3.42 per MMBtu in the third quarter, $4.28 per MMBtu in the fourth quarter, $4.78 per MMBtu in the first quarter of 2027, $4.30 per MMBtu in the second quarter, $4.43 per MMBtu in the third quarter, and $4.84 per MMBtu in the fourth quarter of next year. Last year, the Henry Hub spot price averaged $4.15 per MMBtu in the first quarter, $3.19 per MMBtu in the second quarter, $3.03 per MMBtu in the third quarter, and $3.75 per MMBtu in the fourth quarter, the EIA’s January STEO showed. “On an annual basis, U.S. natural gas prices are relatively flat in 2026 before rising in 2027 as market conditions tighten,” the EIA said in its latest STEO. “We expect the Henry Hub natural gas spot price will average just under $3.50 per million British thermal units (MMBtu) this year, a two percent decrease from 2025, and then rise by 33 percent in 2027 to an annual average of almost $4.60 per MMBtu,” it added. In its STEO,

(Update) January 26, 2026, 9:39 PM GMT: Article updated with pricing details in first three paragraphs. Saudi Aramco priced a $4 billion bond sale, its first note sale this year, as the world’s largest oil producer steps up borrowing to fund investment and dividends. The government-owned oil producer sold four bonds maturing in three to 30 years, according to a person familiar with the matter. The longest portion of the deal will pay 1.3 percentage point above Treasuries, said the person, who asked not to be identified because they are not authorized to speak publicly. That’s roughly a quarter-point less than initial pricing discussions. Overall, the sale attracted more than $22 billion of bids at the peak, with final books over $14 billion, the person said. Aramco is a key contributor to Saudi state finances, with large dividend payments supplementing royalties linked to crude sales. As oil prices have dipped and OPEC+ policy limited Saudi production, cash flows lagged payouts before a rebound in the third quarter. Aramco’s $17 billion in debt sales over the last two years helped support payouts. Saudi Arabia’s budget remains heavily dependent on oil revenue as the kingdom pursues an ambitious modernization drive. Crude prices remain well below levels needed to balance the state budget, forcing the government to project spending shortfalls for the coming years. Aramco has turned to debt to augment its cash flow and plans to invest more than $50 billion this year in oil and natural gas production, while maintaining its high base dividend of $21 billion. In November, the company reported a surprise jump in third-quarter profit as rising production outweighed lower crude prices. Earnings are set to slip for the full year, estimates compiled by Bloomberg show. While Brent crude has risen this year amid geopolitical tensions, including US attacks on

North Sea countries and transmission system operators on Monday signed an agreement committing to advancing investment in offshore wind projects and expanding cleaner power interconnection. The Joint Offshore Wind Investment Pact for the North Seas supports a goal set by the neighbors to reach 300 gigawatts (GW) of installed wind generation capacity in the North Seas by 2050, including 100 GW from cooperation projects. The pact was signed by the governments of Belgium, Denmark, France, Germany, Ireland, Luxembourg, the Netherlands, Norway and the United Kingdom, as well as electricity and transmission system operators, during the North Sea Summit in Hamburg, Germany. Under the pact, the governments pledged to ensure “a more evenly distributed offshore wind tender pipeline between 2031 and 2040 across the North Seas contributing to a European installation capacity of up to 15 GW per year”, according to the official text published online by Germany’s Economic Affairs Ministry. They also committed to crafting an Offshore Financing Framework for North Sea wind cooperation projects. The framework would “build on and strengthen existing instruments and processes such as the framework for trans-European networks for energy and the identification of projects of common interest and projects of mutual interest”. The Offshore TSO Collaboration and project developers have agreed to implement cooperation projects with a combined capacity of 20 GW in the 2030s. The first of these would be identified by 2026, according to the pact. The participating governments also pledged to improve their national regulatory frameworks “to increase investor certainty in cooperation projects, including cross-border liability schemes, connection and balancing schemes”. The pact provides for an investigation by the participating European Union member states into “market arrangements for offshore hybrid projects to address hybrid-specific risks for generators”, read the text. “The UK is also committed to the development of the most

North America added six rigs week on week, according to Baker Hughes’ latest North America rotary rig count, which was published on January 23. The total U.S. rig count rose by one week on week and the total Canada rig count increased by five during the same period, pushing the total North America rig count up to 775, comprising 544 rigs from the U.S. and 231 rigs from Canada, the count outlined. Of the total U.S. rig count of 544, 526 rigs are categorized as land rigs, 15 are categorized as offshore rigs, and three are categorized as inland water rigs. The total U.S. rig count is made up of 411 oil rigs, 122 gas rigs, and 11 miscellaneous rigs, according to Baker Hughes’ count, which revealed that the U.S. total comprises 476 horizontal rigs, 55 directional rigs, and 13 vertical rigs. Week on week, the U.S. land rig count rose by two, its offshore rig count dropped by one, and its inland water rig count remained unchanged, Baker Hughes highlighted. The U.S. oil rig count rose by one week on week, while its gas and miscellaneous rig counts remained unchanged week on week, the count showed. The U.S. horizontal and vertical rig counts each increased by one week on week, and the country’s directional rig count dropped by one during the same period, the count revealed. A major state variances subcategory included in the rig count showed that, week on week, Louisiana dropped two rigs, Utah dropped one rig, Colorado added two rigs, and Wyoming and Texas each added one rig. A major basin variances subcategory included in the rig count showed that, week on week, the DJ-Niobrara basin added two rigs. Canada’s total rig count of 231 is made up of 158 oil rigs and 73 gas rigs,

Santos Ltd and its partners have shipped the first cargo from the Darwin LNG life extension project in Australia’s Northern Territory. The inaugural volume will be delivered to the Sakai terminal in Japan on an ex-ship basis, the Adelaide-based natural gas-focused producer said in an online statement Tuesday. The life extension project, or the Barossa Gas Project, involves the development of the Barossa field as a new source for the liquefaction plant in Darwin, which began producing liquefied natural gas (LNG) 2006 and has an LNG capacity of about 3.7 million metric tons a year, according to Santos. Darwin LNG’s previous source field, Timor-Leste’s Bayu-Undan, stopped exporting gas to the facility late 2023 due to depletion, though Santos said 2024 Bayu-Undan would continue sending gas to the Northern Territory until the end of that year. In its quarterly report July 16, 2025 Santos confirmed Bayu-Undan ceased production May 2025. The life extension project started up approximately six months earlier than planned and within budget, said Santos, which announced a final investment decision (FID) on the Barossa Gas Project March 30, 2021. The FID announcement pegged costs at $3.6 billion, making Barossa LNG the biggest investment in Australia’s oil and gas sector then, according to Santos. According to a Santos update June 18, 2025 investment in the project reached $3.95 billion. The early startup “is an outstanding achievement for a project of this scale and complexity in the global offshore upstream sector”, said Santos managing director and chief executive Kevin Gallagher. Gallagher noted Barossa LNG had “navigated through the impacts of the COVID-19 pandemic, regulatory approvals, legal challenges and supply chain disruptions during the construction phase”. Japanese power utility JERA Co Inc, one of the partners, said separately on Tuesday about the restart of Darwin LNG, “As energy demand continues to