Obsidian Energy Ltd. is selling its operating assets in the Pembina oil field in Alberta, Canada, to InPlay Oil Corp. for approximately $224.77 million (CAD 320 million). Obsidian will retain its non-operated holdings in Pembina Cardium Unit #11, the company said in a news release. The Pembina assets include 498 net sections of land in the Pembina area of Central Alberta, including associated facilities and gathering systems. Consideration for the acquisition will consist of $154.53 million (CAD 220 million) in cash, $59.71 million (CAD 85 million) of InPlay’s common shares, and InPlay’s 34.6 percent working interest in the Willesden Green Cardium Unit #2 oil field, which would bring Obsidian Energy’s ownership in the field to 99.8 percent. This additional interest is estimated to be valued at $15 million, according to the company. As part of the transaction, Obsidian Energy said it has agreed to drill four wells on two pads in the Pembina area during the first quarter of 2025 at InPlay’s expense. All rights to the wells and associated infrastructure will be transferred to InPlay upon the close of the transaction. The effective date of the transaction is December 1, 2024, and is expected to close early in the second quarter of 2025, subject to approval by InPlay shareholders, receipt of all necessary regulatory approvals and the satisfaction of other customary closing conditions. Obsidian Energy said the transaction allows the company to focus on its light oil development in Willesden Green, part of the Willesden Green Oil and Gas Field and the Duvernay Formation. As part of the transaction, InPlay will assume all assets and liabilities associated with the Pembina assets. InPlay said in a separate statement that the petroleum and natural gas assets are producing approximately 10,000 barrels of oil equivalent per day (boepd), consisting of 68 percent

Centrica said it has secured a sale and purchase agreement to provide liquefied natural gas (LNG) to Petróleo Brasileiro S.A (Petrobras). The contract between the two companies is for the purchase of 0.8 million tons per annum (mtpa) of LNG for 15 years, beginning in 2027, Centrica said in a news release. The financial details were not disclosed. The agreement comprises approximately 30 percent of Centrica’s U.S. portfolio and will be sourced from Centrica’s Sabine Pass and Delfin supply agreements, the United Kingdom-based company noted. The agreement “marks a significant step in expanding Centrica’s global LNG business, diversifying the locations it can deliver LNG to and supporting energy security in Brazil with an important new long-term partner,” the company said in a statement. Centrica Group Chief Executive Chris O’Shea said, “Centrica is investing to deliver the energy security, efficiency and decarbonization solutions our customers need today and in the future, and LNG is, and will continue to be, a crucial foundation of the energy transition. This agreement demonstrates our approach to building long-term partnerships while derisking our portfolio exposure in the medium-term, in turn positioning us to continue growing our portfolio as new LNG supply comes into the market over the coming years”. Petrobras Director of Energy Transition and Sustainability Maurício Tolmasquim said, “The agreement with Centrica is aligned with Petrobras’ priorities to reduce its exposure to the spot market volatility, increase its competitiveness and be the best option for its customers. We also consider the contribution of this important product to promoting the energy transition”. Flexible Power Projects in Ireland Meanwhile, Centrica’s subsidiary Bord Gáis Energy has secured a 10-year capacity market contract to deliver a 334-megawatt (MW) open cycle gas turbine power station in Galway, Ireland. The new power station will be capable of running on biomethane or

Elixir Energy Ltd. said it has signed agreements for a Mongolian partnership with Gobi Terra (UK) Ltd. that provide for the Australian company’s eventual exit from the Central Asian nation. The companies agreed to form two incorporated joint ventures (JVs), one to hold Elixir’s coal bed methane (CBM) business in Mongolia and the other to hold its renewable energy assets in the country, according to a regulatory disclosure by Adelaide-based Elixir. Gobi Terra, which Elixir described as a private United Kingdom company “controlled by Mongolian business interests”, will have a 51 percent stake each in the JVs. In the CBM JV, Gobi Terra “will fully carry Elixir through all costs to a final investment decision (FID) on a gas development”, stated the filing on the Australian Securities Exchange. The farm-out agreement consists mainly of the Nomgon CBM production sharing contract and related facilities. “The Farmout Agreement also contains conditional put and call options that can be exercised upon FID being reached, providing for Elixir to exit at a price of US$0.30/GJ of 2P [proven and probable] booked reserves, capped at US$30 million”, Elixir added. In the renewables JV, which will contain Elixir’s Solar Ilch pre-development solar farm and wind and solar monitoring equipment, Gobi Terra will also own 51 percent “and fully carry Elixir through all costs to any final investment decisions on the proposed solar/wind farm developments”, Elixir said. The companies agreed that Elixir would receive $2 million plus $20,000 per megawatt (MW) of installed capacity at a maximum of 50 MW. “A 50 MW solar farm would therefore entail a total payment of $US3 million to Elixir”, the filing said. They also agreed to payments of $1 million plus $10,000 per MW of installed capacity at a maximum of 200 MW. “A 200 MW wind farm would therefore entail

Across the US, utilities are making significant advancements in the energy transition, one such being electrification: switching end-use devices like heating systems and vehicles away from fossil fuels and onto electric fuel. Because electrification – and the associated demand increase – could increase system costs if demand is left unmanaged, a subsequent trend has emerged: demand management at the grid-edge. Utilities are investing in new solutions to serve customer demand (particularly from new grid-edge devices like EVs and heat pumps) more efficiently. An important tool in a utility’s demand management toolbox is pricing innovation – that is, developing new rate designs that more accurately communicate to customers the costs and benefits of their use of the power system. With new time-of-use rate designs, dynamic pricing models, location-based incentives, utilities have a wealth of solutions at their disposal. But to implement these pricing innovations at scale, utilities will need modern billing technologies that can keep up. Implementing rate design innovation requires more than just smart meters Over the last decade, US utilities have invested billions of dollars into advanced metering infrastructure (AMI). The transition away from manually-read meters to communications-enabled smart meters has allowed utilities to collect more granular consumption data from end customers. The value of these AMI investments relates to the outcomes utilities are able to achieve with this new, granular meter data. Utilities across the US are seeking to deliver value from their AMI investments by implementing time-varying rates for customers, something they weren’t able to do without granular meter data. However, many utilities are finding that even with modernized metering equipment, the process of implementing new rate designs proves difficult and expensive if their customer IT systems (specifically, billing) have yet to be modernized. Coding a new rate design or product offering into a legacy billing system

Empowering the energy transition Significant progress has been made in recent years to decarbonize electricity generation through the increased build-out of renewable energy, such as solar and wind. Hitachi Energy tackled the equally gnarly challenges of sustainable transmission and distribution with the aim to accelerate the transition towards a carbon-neutral energy future. As electricity becomes ever more vital for the functioning of modern society, there is less room for compromise on the reliability and stability of power systems. Consequently, we have to deal with higher short-circuit currents. To address this need, the company unveiled the EconiQ® high-voltage roadmap in 2021, outlining an extensive portfolio of eco-efficient, SF6-free switchgear and breakers at various voltage levels in the R&D pipeline. Since then, the roadmap has continued to drive forward the pace of eco-efficient innovation. This year, Hitachi Energy has made crucial updates to the EconiQ roadmap, reflecting the evolving needs of modern electrical grids. The introduction of 420 kilovolt (kV) gas-insulated switchgear (GIS) and 420 kV live tank circuit breakers (LTA) with an 80 kiloampere (kA) short-circuit current rating marks a significant leap in grid resilience. While 63 kA systems have been sufficient in many networks until now, the shift to 80 kA short-circuit capacity meets the demands of increasingly meshed transmission energy networks, mainly driven by renewable energy integration, increasing electrification of transport and industry, and burgeoning data centers. The EconiQ roadmap shows Hitachi Energy’s SF6-free switchgear products available now and those to come with their target release date. The new roadmap includes, among other updates, the 420 kV circuit breaker (with applications in DTB and GIS) with 80 kA short-circuit capacity and an 800 kV dead tank circuit breaker. Hitachi Energy Why short circuits matter Short-circuits have always been an essential factor in grid design and operation. Short circuits result from

The utility sector is undergoing a significant transformation. Increased demand for electricity, aging infrastructure, expanding renewable energy adoption, extreme weather and technological advancements are all making planning and operations processes and decision making much more complex.  In this article, we’ll outline three of the most pressing energy trends every utility must prepare for in 2025.  Trend #1: Electricity loads are skyrocketing Global electricity demand is expected to grow annually by 3.4% through 2026. On-going electrification efforts, including the increased adoption of electric vehicles (EVs), heat pumps and other connected devices will drive some of this demand, but the lion’s share will come from data centers.  Data center loads (also referred to as hyperscalers), are exploding, straining the grid’s capacity infrastructure. Experts believe data center demand could exceed 1,000 TWh by 2026, more than doubling the sector’s 2022 consumption. Around the world, streaming, remote work, crypto mining and cloud computing — all data center-enabled activities — are on the rise. However, the real culprit behind data center load growth is artificial intelligence (AI). AI-enabled applications are notoriously power-hungry, with new AI data centers using 5 to 10 times more power than traditional data centers. For utilities, keeping up with this trend means planning for massive increases in load growth, unlike anything they’ve seen in the past. “I think the biggest challenge for utilities is the size of the growth and how sudden it’s been,” said Carlos Romero, VP Strategic Operations for Energy Exemplar. Romero explained that hyperscalers like Meta, Amazon and Microsoft have requested sites from 1 GW to more than 5 GW per site, which is significantly more than the 1% to 2% load increases that utilities have historically seen. “To put that in perspective, the average nuclear power plant is roughly 1 GW to 1.5 GW. If a data