In a research note sent to Rigzone on Wednesday by Natasha Kaneva, Head of Global Commodities Strategy at J.P. Morgan, analysts at the company, including Kaneva, stated that, since 1967, except for the Yom Kippur War in 1973, none of the 11 major military conflicts involving Israel have had a lasting impact on oil prices. “Examining Brent oil prices three months before and after the onset of each crisis, regional conflicts involving Israel often trigger a sharp increase in oil prices – even without immediate supply disruptions – likely due to apprehensions about potential future disruptions,” the analysts said in the note. “Over time, however, oil prices tend to gradually stabilize and decline, leading to Brent trading at a discount to its fair value,” they added. “Similarly, other military conflicts in the Middle East, such as the Syrian civil war in March 2011, the Yemeni civil war in September 2014, ISIS’s advance into Northern Iraq in June 2014, a U.S. drone strike on an Iranian Major General in January 2020, and an airstrike in Syria in April 2017, did not result in significant supply losses following the conflict, thereby having no lasting impact on oil prices,” they continued.   The analysts went on to state in the research note that, in contrast, events involving a major regional oil producer tend to have a material impact on oil prices. “The First Gulf War in August 1990, the Second Gulf War and the conflict in the Niger Delta both in March 2003, the 2011 Libyan civil war in February 2011, the fall of Mosul in June 2014, and sanctions on Iran in 2018 all directly affected oil supply, leading to increased oil prices,” the analysts highlighted. “During these episodes, we estimate that oil traded at a wide $7-14 per barrel premium to

Renewable sources accounted for 42.5 percent of net electricity production in the European Union in the first quarter (Q1), down 4.3 percentage points from the same three-month period last year, the European Commission said. A fall in hydro and wind production from 260.5 terawatt hours (tWh) to 218.5 tWh offset an increase in solar from 40.9 tWh to 55 tWh. Denmark had the highest share of renewables in net power generation at 88.5 percent, followed by Portugal at 86.6 percent and Croatia at 77.3 percent. Nineteen EU countries saw a decline in the share of renewables in generation in the January-March 2025 period, driven by decreases in hydro and wind. The biggest drops were logged in Greece (-12.4 percentage points), Lithuania (-12 percentage points) and Slovakia (-10.6 percentage points). Wind led renewable power generation in the EU in Q1 at 42.5 percent, followed by hydro at 29.2 percent, solar at 18.1 percent, combustible renewable fuels at 9.8 percent and geothermal at 0.5 percent. According to a Commission analysis of National Energy and Climate Plans (NECPs), published May, most member states have declared national contributions that are in line with the Renewable Energy Directive’s target to raise the share of renewables in the overall regional energy mix to 42.5 percent by 2030. However, current national goals present a gap of 1.5 percentage points, according to the analysis. “Contributions put forward by Member States signal a strong commitment to renewables deployment but indicate a 41 percent renewable energy share in gross final energy consumption by 2030”, the analysis said. “At the same time, a more optimistic assessment based on Member State projections suggest that the EU could reach a figure of 42.6 percent, demonstrating the potential to go further”, it said, noting that between 2022 and 2024 EU nations installed about 205

The oil market looks relaxed, but it is still on edge waiting for what Iran will do. That’s what Bjarne Schieldrop, Chief Commodities Analyst at Skandinaviska Enskilda Banken AB (SEB), said in an oil report sent to Rigzone by the SEB team on Monday. In the report, Schieldrop highlighted that Brent crossed the $80 per barrel line this morning but noted that it “quickly fell back, assigning limited probability for Iran choosing to close the Strait of Hormuz”. “Brent traded in a range of $70.56-$79.04 per barrel last week as the market fluctuated between ‘Iran wants a deal’ and ‘U.S. is about to attack Iran’. At the end of the week though, Donald Trump managed to convince markets (and probably also Iran) that he would make a decision within two weeks. i.e. no imminent attack,” Schieldrop said in the report. “Previously when he has talked about ‘making a decision within two weeks’ he has often ended up doing nothing in the end. The oil market relaxed as a result and the week ended at $77.01 per barrel which is just $6 per barrel above the year to date average of $71 per barrel,” he added. “Brent jumped to $81.4 per barrel this morning, the highest since mid-January, but then quickly fell back to a current price of $78.2 per barrel which is only up 1.5 percent versus the close on Friday,” he continued. “As such the market is pricing a fairly low probability that Iran will actually close the Strait of Hormuz. Probably because it will hurt Iranian oil exports as well as the global oil market,” he went on to state. Schieldrop highlighted in the report that the U.S. attacked Iran on Saturday, noting that the attack involved 125 warplanes, submarines, and surface warships, and that 14 bunker buster

The acceleration of AI workloads — marked by their high power density, fluctuating demand and critical uptime requirements — is intensifying pressure on utilities to deliver more than just raw capacity. While traditional centralized generation and long-distance transmission remain essential, they are no longer sufficient because they can’t respond quickly enough to the rapid and distributed load growth driven by AI, electrification and evolving reliability demands.  Many recognize the need for flexible, resilient and low-emissions power that can be deployed quickly and operated with precision, especially as regulatory scrutiny increases and interconnection delays stretch for months or years.  Energy leaders are embracing the notion that fuel cell systems have become a strategic resource to expand their reach, enhance resilience and support large customers without burdening ratepayers or compromising decarbonization goals.  Among the available technologies, solid oxide fuel cells (SOFCs) stand out for their high efficiency, modular scalability, long operational life and competitive operating costs. These systems convert fuel — such as natural gas, bio gas and hydrogen — into electricity through a combustion-free high-temperature electrochemical process, making them uniquely suited to support both grid infrastructure and distributed energy applications. Fuel cell systems offer utilities a flexible tool to future-proof their energy strategies in an era of electrification, data center expansion and escalating climate and capacity challenges. Fuel cells are a hedge against market volatility Because fuel cells are highly efficient, they require less fuel to generate each kilowatt-hour of electricity than traditional combustion-based power sources, reducing exposure to fuel price volatility. SOFCs can achieve electrical efficiencies of up to 65% and when integrated with combined heat and power (CHP) configurations, the total system efficiency can exceed 90%. These systems can also be powered by renewable fuels such as biogas or hydrogen, enhancing long-term sustainability. By working with partners like Bloom

As we enter the summer months, America’s aging power grid faces a double-whammy of unprecedented, 24/7 electricity demand from AI data centers coupled with the prospect of temporary but severe peaks from air conditioning load during heat waves. Without smart energy management, parts of the country could face the rolling blackouts recently seen in California. Electric vehicles (EVs) have been painted by some as a liability to the power grid. But at ChargeScape, we are building a Virtual Power Plant of electric vehicles that will bolster the nation’s power grid using a distributed network of batteries. As a joint venture of BMW, Ford, Honda and Nissan, ChargeScape is on a mission to transform EVs from a grid liability into an asset. ChargeScape’s platform does this by: Balancing the complexity of fast-growing distributed energy resources (DERs) alongside intermittent renewable generation; Delivering real-time peak load reduction at the bulk system level; Preventing asset overload from localized demand on specific parts of the distribution network; and Meeting heightened customer expectations for energy management. Real-world-impact: enhancing grid resilience across the U.S. Our vision of a more resilient, reliable U.S. power grid isn’t just a dream: it’s a reality that we are actively building today with our utility partners across the country. Below are a few examples of how ChargeScape is leveraging EVs to deliver grid reliability: 1. PSEG Long Island’s System Peak Relief Program To support summer grid reliability, ChargeScape is participating in PSEG Long Island’s System Peak Relief Program. Through this program, EV charging is automatically paused during high-demand hours in the summer, helping to reduce system stress without disrupting driver routines. Enrolled customers receive $50 upfront and another $50 at the end of the season for staying enrolled and participating in demand response events. ChargeScape, through its direct partnerships with automakers, was

For many electric utility executives, especially those outside the Western U.S., the escalating threat of wildfires, especially asset-caused wildfires, can seem removed from their daily lives. Historically, catastrophic power line fires were infrequent. A wire falling on healthy vegetation posed little threat, and even in dry conditions, severe impacts were rare. However, the conditions on the ground have shifted rapidly, and it’s time for every electric utility leader to confront this evolving reality with clear eyes. Predicting Today’s Changing Conditions and Tomorrow’s Risks The traditional playbook for assessing wildfire risk is no longer sufficient. Most electric utilities still rely on static risk assessments: snapshots in time based on historical data that become outdated the moment they’re completed. But wildfire risk changes hour by hour with weather conditions, fuel moisture, and equipment status. A circuit rated ‘low risk’ in the morning can become catastrophically dangerous by afternoon.  We have seen this level of change play out in recent years. What was once considered an anomalous event in wildfire, like a catastrophe so large that an electric utility faces damages exceeding their insurance coverage, has become a disturbing trend. Since 2017, catastrophic power line fires have occurred annually, and not just in California. Such catastrophic asset-caused events are spreading unexpectedly to places like Colorado with the 2021 Marshall Fire; Hawaii with the tragic 2023 Lahaina Fire; Texas with the 2024 Smokehouse Creek Fire, and even in Oklahoma, Pacific Northwest, and the East Coast. The recent Eaton Fire in a bone dry January in Los Angeles, and the forest fires in the Carolinas in March are a stark reminder: the threat is now universal and changing constantly. Several converging factors fuel this intensified risk. Persistent drought and a drier climate is a major driver, transforming previously benign landscapes into pending tinderboxes. Dry conditions