Ghana’s Petroleum Hub Development Corp. (PHDC) has entered a memorandum of understanding (MOU) with an international consortium for a proposed $28-billion second phase of the country’s multiphased petroleum hub to be built in the Jomoro municipal district of the country’s Western Region. Signed with a consortium led by UAE-based Global Sphere FZE on behalf of investors from South Korea, Mali, and the UAE, the MOU covers development of Phase 2’s planned 300,000-b/sd refinery, two petrochemical plants, 4 million cu m of storage, and a multi-berth jetty under a build-own-operate model that—if approved—would lead to start of construction within 6 months of the agreement’s Oct. 19 signing, PHDC said in a release. Phase 2 will be the second tranche of the three-phased project that collectively aims to add three grassroots refineries totaling 900,000 b/sd, five new petrochemical plants, fresh storage capacity of 10 million cu m, and at least two jetties supporting imports and exports. Dr. Toni Aubynn, PHDC’s chief executive officer, described the MOU as an opportunity to develop Ghana’s industrial capacity and create jobs. Investor representative Boubacar Belco Bah said the consortium would work with PHDC, AMS Technologies, the project development consortium, and technical and financial institutions on project preparation and risk allocation, including plans for participation by Ghanaian contractors, professionals, and service providers. While its confirmation of this latest agreement sets out Phase 2’s proposed installations and construction window, PHDC did not specify financing commitments, detailed partner responsibilities, or a commissioning schedule. The precise identity of AMS Technologies was neither revealed nor could be confirmed, but PHDC previously announced an investment consortium dubbed “AMS/Double Tree Capital Bank” visited PHDC offices in early December 2025 with an expression of interest in exploring investment opportunities for Phase 2 of the project. Advancing the project Previously estimated at a combined cost

Oil prices declined Oct. 26 as renewed diplomatic efforts raised hopes of easing US-Iran tensions, while European natural gas prices climbed as colder weather and disrupted LNG supplies heightened concerns ahead of winter. Brent crude futures traded around $115/bbl, down about 1.6%, while US West Texas Intermediate (WTI) declined about 2% to $101/bbl in early trading. Both remained near 6-month highs following last week’s rally. On Oct. 26, senior officials from Saudi Arabia, Pakistan, and Turkey were expected to hold security talks with Iranian leaders in Tehran. This comes amid concerns that the US and Israel might launch fresh strikes against Iran, while attacks by the Houthi movement against Saudi Arabia continue to escalate. Iranian officials have indicated that the discussions will cover regional conflicts—including the situation in Lebanon—as well as efforts to establish a security framework led by Middle Eastern nations. Nevertheless, the persistent Houthi attacks on Saudi targets, combined with Iranian actions against oil tankers in the Strait of Hormuz, continue to fuel deep concerns regarding the security of oil infrastructure and maritime shipping. Meantime, low European gas inventories and colder weather heightened concerns over supplies for the winter heating season. EU storage stood at 74.6% of capacity as of Oct. 25, well below historical averages for late October, while disruptions to LNG shipments from Qatar and the UAE constrained supplies available to replenish inventories. Competition with Asian buyers for available LNG cargoes added to the pressure. Front-month Dutch TTF futures touched €97.50/MWh on Oct. 26, their highest level since December 2022.

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