Sembcorp Industries Ltd. is carrying out a strategic review of its business, with various possibilities under consideration, including potentially going private or selling some assets, people with knowledge of the matter said. The Singaporean firm, which is backed by state-owned Temasek Holdings Pte, is working with a financial adviser on the review, according to the people, who asked not to be identified because the matter is private.  Sembcorp’s stock rose as much as 4.9%, the steepest intraday gain since Aug 7. Considerations are at an early stage and Sembcorp may decide not to pursue any deal, the people said.  A spokesperson for Sembcorp said the company always assesses options to enhance shareholder value, including investments, divestment, restructuring, listing and capital management.  “As part of such assessments, we work with consultants from time to time, as the needs arise” the spokesperson said. “The assessed options may or may not result in any form of transaction.”  “We will make the necessary announcements in accordance with the requirements in the SGX-ST Listing Manual where an initiative is material and has progressed to a stage where there is a high level of certainty,” the spokesperson added.  Sembcorp’s businesses include wind, solar, hydro and energy storage operations in Southeast Asia, China, India, the UK and Middle East, as well as gas and diesel-fired power plants in similar geographies, urban solutions such as waste and water management, and corporate decarbonization services.  Past restructurings include Covid-hit Sembcorp Marine’s demerger in 2020. Sembcorp Industries’ chief executive officer at the time said the move would help it focus on the energy and urban sectors. Sembcorp Industries also completed divestments in Chile, China and Panama that year. In 2024, it announced the sale of Sembcorp Environment Pte for S$405 million. Sembcorp’s shares have climbed more than 250% since the end of 2020, giving the

For more than a decade, the phrase “first, eat your energy efficiency vegetables” has been used to encourage consumers and utilities to prioritize reducing energy use before making changes to how energy is sourced. This principle remains true today, but with a new twist: electrification. As utilities navigate the evolving energy landscape, ensuring that efficiency and electrification work hand-in-hand is critical to reducing emissions, optimizing grid performance, and keeping customer bills in check. The Foundation Energy efficiency (EE) has long been the go-to strategy for utilities looking to lower energy consumption, reduce peak demand, and help customers save money. Electrification, on the other hand, can increase energy demand—especially if customers adopt electric vehicles (EVs) and heat pumps without implementing efficiency measures first. But when done right, electrification can be a powerful tool for decarbonization while still maintaining the benefits of energy efficiency. Why Smart Load Management Matters Electrification without efficiency is like skipping the vegetables and going straight for dessert—it may taste good in the short term but leads to problems down the line. Increased electricity consumption from EVs, heat pumps, and other electric technologies can put additional stress on the grid. The key is to integrate energy efficiency strategies with electrification efforts to balance load growth and avoid excessive peak demand. Targeting Customers Who Are Ready for the Next Step Not every customer is ready for a full-scale energy retrofit, but many are open to incremental improvements. The good news? Data shows that those who adopt smart thermostats or EVs are often inclined to pursue further energy efficiency improvements, and vice versa. Utilities can leverage this customer propensity by using targeted marketing and strategic program design to enhance energy efficiency and demand response (DR) participation. Here’s how: 1. Promote Heat Pumps to Homes with Recent Insulation Work A home

APA Corp. and its partners have declared a “significant” petroleum discovery in the Lagniappe area on Alaska’s North Slope. Drilled to about 10,500 feet, the Sockeye-2 well “encountered a high-quality reservoir with approximately 25 feet of net oil pay in one blocky, Paleocene-aged sand with an average porosity of 20 percent”, Houston, Texas-based APA said in an online statement. “As compared to recent regional field analogs in the Brookian play, the porosity and permeability are both better than expected, with the permeability to be confirmed through a planned flow test”, the oil and gas explorer and producer said. “Additional zones of potential pay were also encountered in the shallower Staines Tongue formation. “The Sockeye prospect is amplitude supported across 25,000 to 30,000 acres, and confirms the partners’ geologic and geophysical models, derisking numerous additional prospects in the area. “Wireline logging is complete and additional data collection is underway, including acquiring core and flow testing the well”. APA holds a 50 percent stake in the leasehold through subsidiary Apache Corp. Operator Lagniappe Alaska LLC of Armstrong Oil & Gas Inc. owns 25 percent. Santos Ltd. has the remaining 25 percent. Sockeye-2 is the second successful exploratory well drilled by the consortium on their 325,411-acre position on state lands. The first discovery, King Street-1, struck oil in two Brookian zones. “The Sockeye-2 well further demonstrates the potential of the play, presenting an exciting opportunity in an active area of the North Slope with significant existing infrastructure”, commented Bill Armstrong, chief executive of Armstrong Oil & Gas. The leasehold sits east of Prudhoe Bay, one of the biggest oilfields in the United States. In a separate statement, Santos said, “The exploration well cost is carried by APA as part of a 2023 farm-in agreement”. On a separate upstream development in Alaska, Santos also said phase

The New York State Energy Research and Development Authority has allocated $5 million to support building solutions that can be demonstrated in existing buildings, including small- to medium-sized commercial, multifamily and single-family buildings, the department announced Friday. Through the Enabling Innovative Clean Energy Building Solutions program, the funding aims to accelerate the market-readiness of new and emerging clean energy and energy efficiency technologies that can help to manage future energy use, enhance energy efficiency and lower operating costs in buildings across the state, NYSERDA says. “By addressing critical areas like clean heating and cooling, energy efficiency, and building decarbonization, NYSERDA … will not only help the State meet its climate goals but also support long-term resilience and cost savings for tenants and building owners across New York State,” Richard Yancey, CEO of the Building Energy Exchange, said in a statement.  The program seeks applications for projects and programs that demonstrate the “latest innovations in integrated systems, materials and technologies that can greatly improve building or home performance, reduce costs, and/or improve resiliency,” NYSERDA said. The maximum funding for each selected proposal is $1 million, with eligible projects being required to have been previously awarded funding from a federal, state or local government entity — besides NYSERDA — foundation or non-profit to develop an innovative clean building technology product or solution, per the release. Eligible funding areas include solutions related to building envelopes, such as components or materials that improve performance or enable building envelope retrofit; clean heating and cooling; intelligent grid-interactive building controls; low-global warming potential refrigerant applications and leak detection; or thermal storage.  Clean heating and cooling solutions include new heat pump equipment, ground source systems and hybrid systems, with grid-interactive building controls including those that enable electric load and energy asset management. Thermal storage solutions that integrate heating,

Microgrids don’t pose an immediate threat to diesel generators as the way most managers ensure their facilities have backup power, but Allan Schurr, the chief commercial officer at microgrid company Enchanted Rock, expects more operators to look at what he says is a cleaner, administratively easier approach that microgrids offer.  “Diesel generators are in short supply and sometimes it’s two years before you can get a diesel generator delivered,” Schurr told Facilities Dive. “By having a microgrid … you can [have something] more reliable and cleaner” and have it up and running within a year.” A microgrid is a self-contained electrical network that companies like Schurr’s install on their client’s property. Enchanted Rock builds its network using half-megawatt natural gas generators that it gangs together based on the amount of load the client wants to back up. For a hospital, it might be a network of 10 generators. For a grocery store, it might be two or three.  “Our standardization of equipment is part of our differentiator,” said Schurr, referring to his company’s use of a single-size generator. “That allows us to dial in exactly the amount of backup power that’s needed for any facility size.” Power from the microgrid is cleaner, Schurr says. In the case of Enchanted Rock, it’s cleaner because it’s generated from natural gas. But microgrids can also use solar, wind and other non-fossil-fuel burning sources.  The cleaner power might be important to organizations that make sustainability a priority but it can also help lower energy costs by enabling the microgrid to run power outside of emergency situations and sell it as a supplemental power source to the local utility grid. That revenue goes to the microgrid and helps offset what the property owner pays for its backup power.  “So, [our clients] can get the air

Dive Brief: The U.S. Nuclear Regulatory Commission’s proposed Part 53 rule must be changed to comport with recent directives from Congress and the Executive Branch to “achieve the most effective and efficient regulatory framework possible,” the Nuclear Energy Institute said in February. The industry group’s recommendation was one of dozens submitted by utilities, trade associations, nuclear technology developers and other industry stakeholders since the NRC released the proposed rule last fall. Many recommendations, though not all, urged the NRC to amend the proposed rule to make it less prescriptive or reduce perceived burdens on future licensees. The current version of the “risk-informed, technology-inclusive” Part 53 framework, which would provide an alternative to the existing Part 50 and Part 52 licensing pathways, incorporates changes requested by lawmakers in 2023 and ordered by NRC commissioners in 2024 to improve the new framework’s efficiency. Dive Insight: The revised Part 53 framework eliminates quantitative health objectives, a set of safety metrics that some in the industry feared would restrict future license applicants’ flexibility. In a March 2024 staff memo, the NRC suggested applicants propose “a comprehensive plant risk metric (or set of metrics)” instead. The revised Part 53 also removes a second possible licensing pathway, known as Framework B. Framework B more closely resembled the existing licensing pathways, but with technology-neutral modifications that reduce burdens on non-light water reactor designs.  Though the NRC voted last year to explore whether aspects of Framework B could inform existing licensing frameworks or possibly find life as a new, standalone framework, NEI in its comments last month recommended against the standalone approach, arguing that it was distracting NRC staff from pursuing more significant improvements to Part 53. In its comments, NEI encouraged NRC staff to take a “systematic and aggressive search for potential changes, in requirements, policy and