Enbridge Inc has reached a positive final investment decision on the Mainline Optimization Phase 1 project (MLO1), earmarking $1.4 billion. “MLO1 will add capacity to the company’s Mainline network and Flanagan South Pipeline (FSP) to meet customer demand for incremental egress, increasing deliveries of Canadian heavy oil to key refining markets in the U.S. Midwest (PADD II) and Gulf Coast (PADD III)”, Calgary, Canada-based Enbridge said in an online statement. The project aims to add 150,000 barrels per day (bpd) of capacity to Mainline and up to 100,000 bpd to FSP. “MLO1 will increase capacity on the Mainline through a combination of upstream optimizations and terminal enhancements”, Enbridge said. “In addition, Enbridge plans to add pump stations and terminal enhancements for FSP to increase capacity and will utilize existing capacity on Seaway Pipeline”. The Seaway Pipeline is a 50-50 venture between Enbridge and Enterprise Products Partners LP. “The FSP expansion is underpinned by long-term take-or-pay contracts for full-path service from Edmonton, Alberta to Houston, Texas, which support attractive returns for MLO1”, Enbridge said. “As part of the open season process on FSP earlier this year, the majority of existing customers elected to extend their existing full-path contracts through the next decade”. The announcement did not say when Enbridge expects to complete the project. In Enbridge’s quarterly report November 7, chief executive Greg Ebel said Enbridge was “advancing” phase 2 to add a further 250,000 bpd of incremental full-path capacity to Mainline “before the end of the decade”. Currently the Mainline pipeline, stretching over 13,800 kilometers (more than 8,500 miles), carries up to about three million bpd of light, medium and heavy crude from the Canadian province of Alberta to Eastern Canada and the U.S. Midwest, according to Enbridge. It started service seven decades ago. Earlier this year Enbridge announced a Mainline investment of up

New Era Energy & Digital Inc has reported over $4.2 million in losses from operations for the third quarter as it winds down assets toward becoming an integrated power and digital infrastructure company. Revenue for July-September was around $160,000 “primarily reflecting remaining natural gas operations”, the company, recently rebranded from New Era Helium Inc, said in an online statement. For the first nine months of 2025, revenue totaled nearly $700,000, while operating losses landed at about $8.14 million. “These results reflect the company’s development-stage investments in engineering, site preparation and the advancement of its digital infrastructure platform, as well as the ongoing wind-down of non-core production assets”, the Nasdaq-listed company said. Chief executive E. Will Gray II said, “This quarter represents the first full financial period since our strategic transformation for New Era… The results you see today reflect a company in transition from a legacy helium and natural gas operator into a vertically integrated developer of AI-optimized digital infrastructure”. “The investments we are making across engineering, land aggregation, site preparation and our Texas Critical Data Centers (TCDC) joint venture are intentional and necessary steps in building the physical foundation for the next wave of AI and high-performance computing”, the CEO said. “Equally important, we have taken decisive action to strengthen our capital structure. Over the past year, we eliminated all convertible debt and terminated our equity purchase facility agreement, steps that were essential to preparing the company for more traditional, institutional forms of financing”, Gray added. “Major AI data center developments are typically funded off balance sheet at the project level, often in partnership with infrastructure funds, hyperscalers and strategic investors. While some level of equity contribution from the parent company will be required, our objective is to ensure that the majority of development capital, particularly for powered shells and

Across the country, we’re asking the transmission grid to do more than ever. Developers are submitting thousands of new interconnection requests. Data centers and electrification are driving unprecedented load growth. Yet while transmission planners have seen a tenfold increase in workload, they haven’t received a tenfold increase in support and are still expected to shoulder the burden. As a result, utilities and ISOs now face a three-way test: maintaining reliability, enabling the clean-energy transformation and keeping electricity affordable. To achieve all three, they must complete a growing number of complex studies—faster and without additional resources. Planners are doing more with less Every reliability and interconnection study represents months of modeling, validation and coordination. These studies determine which projects move forward, what upgrades are needed and how billions of dollars are allocated. They are the backbone of the grid and the volume of these studies has increased by orders of magnitude. Yet the tools planners rely on to carry out this work haven’t evolved. In response, planning teams are piecing together ad hoc solutions—scripts, spreadsheets and homegrown Python tools—to meet rising study demands. It’s the best anyone can do with the time and resources available, but these one-off efforts are hard to scale, maintain or share across teams. One example: the challenge of base-case development One recurring challenge for many utilities is developing base cases; the models that underpin all reliability planning studies. To build one, engineers start with a current model of the system, then apply updated load forecasts, generation additions and transmission-topology changes. They often have to merge hundreds of files and manually resolve conflicts as part of this effort to create a final, solvable model. The frequency of rebuilding or updating base cases has increased nearly 10x, driven by rapid generation turnover, load growth and policy change. Many

Serbia is willing to pay a premium to regain control of oil refiner NIS AD as it seeks ways to unshackle the Russian-owned company from crippling US sanctions, President Aleksandar Vucic said on Sunday. NIS’s owners, units of Russia’s Gazprom PJSC, are in talks with third-party investors from Asia and Europe who could potentially take it over, Vucic said in a live broadcast of a government meeting in Belgrade to discuss ways to resolve the dilemma. “If they don’t agree on a purchase price, my proposal is that we offer a better price,” Vucic said. “We are ready to even overpay” for the 56 percent stake held by Gazprom units, he said. Serbia’s only refiner is at risk of running out of crude within days after the sanctions – which took effect Oct. 9 – cut off its supply route through neighboring Croatia. Vucic and Finance Minister Sinisa Mali warned that this could have devastating consequences for Serbia’s economy and its credit rating. The country has just a week to find a solution to avert a fuel crisis, Vucic said. “Whatever it costs, we’ll find the money,” he said. A possible buyout by the state, which holds almost 30 percent of the refiner, would require negotiations with international financiers, and possibly a budget review to secure funding, the president said, without going into a possible valuation. “We want to avoid confiscation, nationalization,” Vucic said. As the majority owner, the Russian stakeholders “have the right to make decisions, but we have the right to live,” he said. Vucic cited Bulgaria’s decision last week to seize control of Lukoil PJSC’s local refinery, also threatened by US sanctions, as an example of what other countries are doing to shield their markets. Trading in NIS shares was suspended in January, after the US Office of Foreign Assets Control unveiled the punitive measures, which

Suriname’s state-owned oil and gas company Staatsolie Maatschappij Suriname NV (Staatsolie) has declared the Sloanea-1 well in the offshore Block 52 a commercial natural gas discovery and said operator Petroliam Nasional Bhd (Petronas) would now submit a development plan that includes a liquefied natural gas (LNG) facility. “With FID [final investment decision] planned in the second half of 2026, Suriname may expect first gas to flow in 2030”, Staatsolie said. Sloanea-1 is Petronas’ first hydrocarbon discovery in the South American country. It announced the discovery December 11, 2020, after drilling into 4,780 meters using the Maersk Developer rig. The partners had considered Sloanea-1 “commercially unattractive”. They agreed to drill an appraisal well and negotiate a “gas addendum” that would lay out the terms for assessing how to develop the discovery, as announced by Staatsolie’s March 4, 2024. “In accordance with the PSC [the production sharing contract signed April 2013], Staatsolie and Petronas Suriname evaluated monetization options for this gas discovery [Sloanea-1], resulting in a gas addendum to the PSC”, Staatsolie said announcing the declaration of commerciality (DOC). “In 2024, Petronas Suriname advanced the appraisal of the Sloanea reservoir by drilling the Sloanea-2 appraisal well to assess its lateral extent and conduct comprehensive well testing. This confirmed the field’s gas in place and recoverable volumes. “On 11 November 2025, Staatsolie approved the delineation of the commercial field for the Sloanea-1 gas discovery, signifying its ‘declaration of commerciality’. “The selected development concept includes gas development wells, subsea infrastructure and a floating LNG facility, a first in the region”. Malaysia’s state-owned Petronas said separately the DOC marks “Suriname’s first gas development milestone in its expanding deepwater energy landscape”. Petronas has made two more discoveries offshore Suriname, all in Block 52: Roystonea-1 in 2023 and Fusaea-1 and Sloanea-2 in 2024. Block 52 spans over 4,700 square kilometers (1,814.68

Greece’s state-owned DEPA Commercial SMSA on Sunday signed a letter of intent (LOI) to supply Ukraine an unspecified volume of liquefied natural gas (LNG) from the United States for the 2025-26 winter via Ukraine’s state-owned Naftogaz Group. This follows Naftogaz’s agreement earlier this month with Atlantic-See LNG Trade SA, formed early November by DEPA and Aktor Group, for the importation of LNG from the U.S. into Ukraine and other European countries. Naftogaz and Atlantic-See “agreed to jointly develop the supply of LNG from the U.S. to Europe and Ukraine through Greek LNG terminals and the Vertical Corridor”, Naftogaz said in a statement on its website November 7. DEPA Commercial chief executive Konstantinos Xifaras said in an online statement Sunday about the LOI, “The supply of U.S. LNG will be facilitated through Atlantic-See, in which DEPA holds a 40 percent stake, underlining the company’s commitment to providing practical and secure energy solutions across Southeast Europe”. DEPA Commercial said, “Under the framework of the prospective agreement, LNG volumes originating from the U.S. are expected to be transported through ‘Route 1’ [of the Vertical Corridor], offered jointly by the gas transmission system operators (TSOs) of Greece (DESFA), Bulgaria (Bulgartransgaz), Romania (Transgaz), Moldova (VestMoldTransgaz) and Ukraine (GTSOU)”. Newly Proposed Gas Routes Recently the TSOs requested their national regulators to approve more flows on the Vertical Corridor, a network of existing gas infrastructure allowing multidirectional flow across seven European countries, via two routes: Routes 2 and 3. “TSOs request the regulators’ approval on the availability of Routes 2 and 3 until April 2026; and the possibility of simultaneous provision of Route 1, Route 2 and Route 3 special capacity products in competing auctions”, said a statement posted on DESFA’s website November 7, announcing a joint letter to regulators. “All participating TSOs have agreed to apply significant