Vermilion Energy Inc. said it has entered into a definitive agreement to sell its U.S. assets for cash proceeds of $87.61 million (CAD 120 million). The assets produce approximately 5,500 barrels of oil equivalent (boepd), consisting of 81 percent oil and liquids, and an estimated approximately 10 million barrels of oil equivalent (MMboe) of proved developed producing reserves as of Dec. 31, 2024, Vermilion said in a news release. The company said it expects the transaction, which has an effective date of January 1, to close in the third quarter, subject to the satisfaction of other customary closing conditions. The transaction agreement includes CAD 10 million of contingent payments based on WTI prices over the two-year period starting July 1. Vermilion said the transaction, combined with the sale of its East Finn assets in 2023, completes the company’s exit from the USA. The company said it plans to focus on its core gas-weighted assets in Canada and Europe. Net proceeds from the transaction will be directed towards debt repayment to “further accelerate deleveraging efforts and strengthen Vermilion’s balance sheet,” the company said. Meanwhile, Vermilion said it is adjusting its 2025 capital budget to a range of CAD 630 to 660 million, reflecting a reduction of approximately CAD 100 million from the mid-point of our previous capital budget range of CAD 730 million to 760 million. The reduction reflects the removal of all remaining exploration and development capital associated with the Saskatchewan and U.S. divested assets post-closing, the company said. Vermilion said it expects full-year and second-half 2025 production to range between 117,000 and 122,000 boepd, 68 percent natural gas-weighted in the second half of 2025. The company said it estimates that over 90 percent of production will come from its global gas portfolio and over 80 percent of capital is

Standard Lithium Ltd. has announced the successful production of battery-quality lithium sulfide using Telescope Innovations Corp.’s new trademarked low-temperature method. “Standard Lithium has been working with its research and development partner, Telescope Innovations, to develop new and novel conversion technologies to make next-generation battery materials”, Vancouver, Canada-based Standard Lithium said in a press release. “This new conversion process has now been successfully used to convert lithium hydroxide produced by Standard Lithium at its southern Arkansas Demonstration Plant, into battery-quality lithium sulfide. “Samples of the lithium sulfide have been shipped to solid-state battery companies in Asia and North America for ongoing testing and validation purposes”. “This development of new IP and technology with our research partner, Telescope Innovations, exemplifies our approach to becoming the leading new lithium company in North America”, said Standard Lithium president and chief operating officer Andy Robinson. “Whilst our principle area of focus, and capital allocation, is building the first DLE [direct lithium extraction] project in North America at our South West Arkansas Project Phase 1 with our joint venture partner Equinor, we understand that constant technological evolution is integral to staying at the forefront of this rapidly evolving industry. “This recent work led by Telescope demonstrates that we are able to take lithium chemicals produced from the Smackover Formation in southern Arkansas, and then transform them into the feedstocks required by the next generation of batteries”. Telescope’s DualPure production method used feedstocks including lithium hydroxide monohydrate from Standard Lithium’s demo plant in Arkansas. The process can also use lithium carbonate. DualPure’s processing temperatures do not reach 100 degrees Celsius, avoiding thermal risks, according to Telescope. “Lithium sulfide is a key raw material required for many next-generation solid-state battery chemistries, but despite the importance of lithium sulfide in the next generation of battery technology, it is only produced

The Northeast Power Coordinating Council Inc. (NPCC) forecast in its 2025 Summer Reliability Assessment that Northeastern North America – New England, the state of New York, and the Canadian provinces of Ontario, Québec, and the Maritimes – will have adequate electricity this summer. NPCC’s summer peak electricity demand is projected to be 104,600 MW, about 400 MW lower than last summer. The installed capacity to meet the region’s demand is approximately 157,000 MW, a decrease of 1,300 MW since last summer, primarily due to the retirement of the Pickering G1 and G4 nuclear units in Ontario. Forecasts indicate sufficient transmission and spare capacity to meet peak demand and operating reserves, with spare operable capacity estimated between 4,700 MW and over 17,000 MW, NPCC said in a media release. “NPCC’s assessment indicates our Region has spare capacity for this summer, which can be used to help mitigate reliability risks that may result from unexpected unavailability of key facilities, fuel supply interruptions, generation maintenance, or higher than anticipated demand”, Charles Dickerson, NPCC President and Chief Executive Officer, said. Because of its winter peak demand, Québec is predicted to comfortably cover the anticipated electricity demand, allowing for the transfer of excess electricity supplies to other regions if necessary, NPCC noted. The evaluation took into account a broad spectrum of related risks, such as demand exceeding expectations, uncertainties in projected demand, unforeseen outages of generator plants, transmission limitations between adjacent regions and within NPCC, the execution of operational procedures, the anticipated effects of demand response initiatives, and extra capacity unavailability alongside diminished transfer capabilities, NPCC said. “NPCC continues to see sustained growth in distributed photovoltaic resources”, Phil Fedora, NPCC Chief Engineer and Senior Vice President of External Affairs, said. “The reduction to NPCC’s summer peak demand due to behind-the-meter photovoltaic resources is estimated to be over

BEL Valves announced in a release sent to Rigzone recently that it had “lock[ed]… in [a] GBP 5 million ($6.7 million) North Sea oil installation”. The company noted in the release that it has supplied 11 actuated and 19 manual slab gate valves to the Murlach oil field development in the North Sea, adding that the valves feature local control panels, range in diameter from two to 12 inches, and can withstand up to 690 Bar pressure in Duplex and Super Duplex materials. BEL Valves highlighted in the release that the Murlach oil field development is a joint venture between BP Exploration Operating Company and NEO Energy, “with the first oil extraction expected in 2025”. It is situated around 135 miles east of the Aberdeenshire coastline and lies in a water depth of 305 feet to 311 feet, the release pointed out. “The Murlach Field Development Project is a really significant North Sea project and to have our slab gate valves playing such a vital part in its operational safety is a great reflection of the trust the industry has in our products,” David Gallagher, Project Director of BEL Valves, said in the release. “We’ve been manufacturing valves for the oil industry since the mid-1960s and our reputation for quality and reliability is second to none,” he added. “And with our ability to design and manufacture bespoke solutions, deliver fast-track orders, and provide full life cycle support, it’s understandable why BEL Valves is held in high esteem by infrastructure specifiers and contractors all over the world,” he continued. “The importance of high pressure, safety critical shut down valves can never be underestimated,” Gallagher went on to state. “The fact we’re known throughout the global oil and gas industry for delivering products that do exactly that, while also being supported by

Every megawatt-hour matters. Grid demand spikes, prices surge, and systems are pushed to their limits. Energy storage system operators need to know how much energy they can count on and how quickly they can deploy it. The catch? In most grid-scale battery energy storage systems (BESS), that number is fuzzier than it seems.  Imagine operating a 100 MWh battery energy storage system. In practice, most operators hold back 10-15% of that capacity to avoid overestimating available capacity and risking a shortfall on any market commitments. That safety buffer—built around measurement uncertainty—means you’re only dispatching 85 MWh. In today’s volatile energy markets, that 10-15% margin isn’t just a technical issue. It’s a missed opportunity. Every unclaimed megawatt-hour represents lost revenue, stranded grid support capacity, and a system falling short of its full potential. Worse, usable energy loss doesn’t stop at estimation errors. Over time, hidden imbalances between individual cells begin to chip away at overall system performance, further reducing capacity and complicating operations.  Understanding State-of-Charge (SoC) Calibration Knowing how much energy is available to dispatch at any given moment is core to profitability. This is where SoC calibration comes into play: a software-enabled process that allows the battery management system (BMS) to track the state of charge of the battery with a high degree of precision.  This level of accuracy is especially important in systems using LFP batteries. Known for their long cycle life and safety, LFP batteries are widely used in grid-scale projects—but they come with a challenge: their relatively flat voltage curve between 25% and 90% SoC makes it difficult for the BMS to accurately determine SoC by the voltage curve alone during regular operations.   This is particularly problematic in markets where batteries operate within a narrow SoC band—often between 30% and 70%—to deliver ancillary services. If a

On May 15, 2025, federal investigators disclosed that undocumented “ghost” communication modules were embedded in some Chinese-manufactured solar inverters. China produces about 70 percent of the world’s inverters, according to the International Energy Agency. Multiply that share across the millions of distributed energy resources (DERs) the United States will deploy this decade and you have a network whose endpoints outnumber today’s central-station assets by orders of magnitude. Here’s what keeps me up at night: Each inverter, battery-management system and smart meter contains firmware and communications devices that grid operators seldom inspect and cannot easily patch. As an industry, we’re essentially deploying millions of black boxes across our critical infrastructure. The energy transition’s defining strength—scale—has become our biggest vulnerability. Why conventional defenses fall short Traditional perimeter tools were designed for a grid dominated by a few hundred control-room assets. Distributed energy completely flips that model: Scale: We’re defending millions of endpoints instead of dozens of plants Diversity: Multiple vendors, protocols and code bases make uniform hardening nearly impossible Physical exposure: Rooftop and roadside installations lack utility-grade site security Supply-chain opacity: Operators receive only “black-box” documentation of embedded components I’ve personally torn down equipment from major manufacturers and found undocumented hardware, hidden communication devices, and features that weren’t in any manual. This isn’t theoretical—it’s happening right now. Principles for a secure distributed grid After years of building and securing distributed energy systems, here’s what actually works: 1. Zero-trust architecture: Never trust vendor-supplied data paths. Ever. If you didn’t build it, assume it’s compromised. 2. Hardware agnosticism: Abstract your control logic from field devices. When (not if) you need to swap suppliers, you should be able to do it with minimal code updates. 3. Physical verification: Tear-down inspections and software bills of materials (SBOMs) must continue through the asset’s entire operational life. A