For energy companies, the assumptions behind a BI value can change materially during the policy period. Margins and throughput can shift, while repair timelines can extend. External events can also change the economics of an operation quickly. Yet the declared BI value and the policy provisions governing recovery may remain unchanged. This raises a practical question: what should trigger a reassessment, and how will the policy respond if the exposure has changed materially? A BI value has a shelf life A BI calculation draws on assumptions about revenue, margins, production, throughput, fixed costs and recovery time. Those inputs can change at different rates and for different reasons. For a downstream operator, a significant movement in crack spreads can change the earnings exposure associated with an interruption. For a midstream operation, a change in throughput or a prolonged constraint on a critical pipeline can alter the financial impact. Across the energy value chain, an extended repair or recovery period can materially increase the duration of a loss. Organizations should establish materiality thresholds for reassessment, supported by a consistent methodology for revisiting the valuation when conditions change. Where a material change increases exposure, organizations may also need to consider whether to redeclare their values. Aon’s approach to business interruption valuation provides a methodology for reassessing the valuation when material changes occur. The percentage on a volatility clause tells only part of the story A stated volatility allowance can overstate the protection available if the exposure has increased materially or operations resume during the recovery period. The Lloyd’s Market Association introduced an updated Onshore Energy BI Volatility Clause in 2024 after carriers identified the previous version as unsuitable for partial losses. The revised clause was intended to address the policy’s indemnity exposure in those circumstances. Organizations should model the provision against realistic loss

As utilities work to expand system capacity and improve power quality, one challenge continues to surface: how to add capability without adding more equipment, more maintenance and more space. Traditionally, capacitor bank applications require multiple devices to perform separate functions. One device energizes and de-energizes the bank. Another provides protection. Additional equipment may be required to manage switching transients and inrush currents. Today’s advanced medium-voltage breaker technology changes that equation. By combining point-on-wave switching and protection in a single breaker, utilities can eliminate separate switching devices while maintaining precise capacitor bank control. The result is a simpler installation with fewer components, a smaller footprint and lower overall system complexity. More functionality in less footprint In many substations, available space has become a valuable asset. Adding new equipment often means expanding infrastructure, increasing costs or limiting future growth. Advanced breaker technology can serve as both the energizing device and the protection device for capacitor banks, eliminating the need for separate switching equipment between the breaker and the bank. With fewer devices installed in the yard, utilities can: Reduce substation footprint Simplify installation and commissioning Lower equipment and maintenance costs Create room for future expansion Improve overall system reliability Rather than adding more components to solve power quality challenges, utilities can accomplish more with less equipment. Consistent performance in real-world conditions Modern utility equipment is increasingly being asked to operate in environments that are far different from traditional indoor substations. Installations may be exposed to extreme temperatures, dust, humidity and rapidly changing operating conditions. Conventional switching technologies often depend on highly controlled operating conditions and precise timing. Variations in voltage supply, temperature or environmental conditions can impact performance. New actuator and control technologies provide highly repeatable operating performance regardless of environmental conditions. Whether deployed in a hot industrial facility, an outdoor substation

As rack densities climb toward 1 MW and beyond, traditional low-voltage alternating current (AC) architecture is being pushed into territory it wasn’t originally designed to handle. A primary reason the industry is increasingly looking toward 800 VDC to support the next generation of high-density compute.  But the bigger question isn’t whether direct current (DC) can power these new racks. It’s where the conversion to DC should happen and how much of the traditional power architecture is still necessary.  Sidecars offer a bridge to 800 VDC  One near-term answer is the sidecar, a power-conversion unit positioned next to the compute rack.  Sidecars give operators a practical way to introduce 800 VDC racks into facilities built around existing low-voltage AC distribution. Rather than redesigning the facility, operators can convert AC power to DC beside the rack.  That makes sidecars an important bridge between today’s infrastructure and emerging DC compute. But much of the existing electrical architecture remains in place. Power still moves through transformers and low-voltage UPS infrastructure before another conversion takes place near the rack.  Each stage introduces losses and nearly all of that lost energy ultimately turns into heat, putting more pressure on the cooling system to remove it.    SMA’s white paper models the difference. In the architecture studied, delivering 1 MW through a traditional AC system with rack-level conversion results in approximately 80 kW of power loss per megawatt delivered to the rack. Converting medium-voltage AC to 800 VDC outside the building and distributing DC directly reduces that loss to approximately 20 kW.  At data center scale, the difference becomes more than significant.  Moving power infrastructure outside  Efficiency is only part of the equation. Data center operators are also under pressure to maximize one of their most valuable resources: white space.  A native DC architecture takes a different approach.

Utilities do not need research to tell them the operating environment has become more demanding. They see it in the systems they manage, the investment decisions they make and the expectations customers and regulators place on them. New research helps quantify that experience. Three in four utility and energy industry professionals surveyed for the 2026 State of Grid Resilience say operational risk is higher than it was five years ago. More than half expect load growth on their distribution systems to be very or extremely significant over the next decade. Nearly four in five expect resilience-related investment to increase over the next five years. At the same time, 61% identify affordability and customer rate pressure as the biggest barrier to accelerating that investment. Taken together, the findings show a challenge utilities have navigated for years. They are committed to resilience, but how resilience is measured, funded and deployed can affect how quickly they can act. Measuring performance under stress Utilities already recognize a distinction between reliability and resilience. Nearly half of respondents define reliability as day-to-day operational performance and resilience as performance under disruption. The measures guiding investment do not always reflect that distinction. Traditional reliability metrics such as SAIDI, SAIFI and CAIDI provide an important and consistent view of everyday grid performance. But only 48% of respondents agree that current reliability metrics adequately capture performance during major disruptive events. The difference becomes clearer when utilities are asked what matters during those events. More than half say restoring service as quickly as possible is the most important outcome during a major storm or disruption. When asked what best demonstrates a resilient grid, respondents first point to limiting the number of customers affected and quickly restoring normal operations. Yet investment decisions remain weighted toward traditional reliability. SAIDI and customer outage frequency

WASHINGTON — Kazakhstan and Guyana have joined Algeria, Nigeria, Qatar, and the United States in calling on the European Union to delay implementation of, and make targeted changes to, the EU Methane Regulation (EUMR), removing unnecessary barriers to energy exports into Europe while ensuring a workable compliance framework. This approach would provide greater regulatory certainty for energy suppliers, including for American producers and exporters.  “American energy exports play a vital role in supporting our allies and driving economic growth,” said U.S. Department of Energy Assistant Secretary for International Affairs Kaveh Farzad. “The growing coalition on this initiative underscores the importance of a pragmatic approach that provides regulatory certainty and ensures reliable energy continues to reach our European allies.” The U.S. Department of Energy recognizes the action by the European Parliament to advance a three-year delay of EUMR implementation as a step forward and encourages swift final adoption of this measure through trilogue negotiations between the European Parliament, Council, and Commission.  The expanded coalition of critical crude oil and natural gas suppliers urges EU leaders to address significant gaps in the regulation’s reporting, verification, and compliance framework. Continued delays in establishing these requirements leave energy producers and importers without the clarity and certainty they need to comply, putting Europe’s energy security, competitiveness, and access to reliable energy supplies at risk.  The six signatories represent a broad and geographically diverse group of energy suppliers to Europe. In 2025, Kazakhstan, the United States, Nigeria and Guyana together accounted for roughly 37% of EU crude-oil imports by volume, while Algeria, Qatar, Nigeria and the United States were collectively responsible for approximately nearly 50% of EU natural gas imports, including LNG.  These figures underscore the importance of ensuring that the EUMR strengthens methane performance without inadvertently restricting access to diverse sources of energy.  Kazakhstan and Guyana join the initiative launched in

@import url(‘https://fonts.googleapis.com/css2?family=Inter:wght@100..900&display=swap’); .ebm-page__main h1, .ebm-page__main h2, .ebm-page__main h3, .ebm-page__main h4, .ebm-page__main h5, .ebm-page__main h6 { font-family: Inter; } body { line-height: 150%; letter-spacing: 0.025em; } button, .ebm-button-wrapper { font-family: Inter; } .label-style { text-transform: uppercase; color: var(–color-grey); font-weight: 600; font-size: 0.75rem; } .caption-style { font-size: 0.75rem; color: color-mix(in srgb, currentColor 60%, transparent); } <!–> Equinor Energy AS awarded Aibel a front-end engineering and design (FEED) study contract covering topside modules for the proposed floating production, storage, and offloading (FPSO) vessel for Wisting field development in the Barents Sea. The contract includes FEED work and further maturation of the FPSO topsides design to support the Wisting partners’ project execution decision. It also contains an option for engineering, procurement, and project management (EPma) services. Any contract for fabrication of the topside modules would be awarded later, Equinor said. Work will begin immediately and is scheduled for completion in late 2027. The FEED study will form part of the basis for the Wisting license partners’ planned investment decision in late 2027. Equinor and partners plan to decide on concept selection and the project’s further progression by yearend 2026. “We are at an early stage in the development of Wisting, and considerable work remains to develop a project that is profitable and feasible,” said Trond Bokn, Equinor’s senior vice-president for project development. ]–> <!–> –> <!–> Dec. 2, 2019 ]–> <!–> –> <!–> April 22, 2024 ]–> <!–> –> <!–> May 21, 2026 ]–> Wisting Wisting, discovered in 2013 in the Hoop area of the Barents Sea about 310 km north of Hammerfest, is the largest oil discovery on the Norwegian continental shelf yet to be developed. The field contains estimated recoverable resources of just under 500 MMboe. Water depths across the development area are 390-418 m. In July, Equinor submitted for public consultation