The deal also includes two new oil batteries in Simonette—the first of which came online in this year’s third quarter and the second expected online by the end of first-quarter 2027—with combined capacity of 24,000 b/d, a 50% interest in a 90-MMcfd Simonette natural gas processing plant, and a 65% interest in a 57-MMcfd Pouce Coupe gas plant. Ovintiv said the infrastructure is expected to enhance margins and support future oil growth. “The Logan assets have demonstrated leading oil productivity performance and will immediately compete for capital alongside the rest of our portfolio,” said Brendan McCracken, president and chief executive officer (CEO) of Ovintiv. The company estimates the acquisition will generate about $60 million/year in cost synergies, primarily through reduced capital, operating, and overhead costs. Ovintiv said the transaction is expected to be immediately accretive to key operational and financial metrics, including about 5% accretion to cash flow per share in 2027. Ovintiv’s acquisition of Logan assets is expected to close in first-quarter 2027, subject to shareholder, court, and regulatory approvals, after which, the operator expects its core Montney position to increase to about 720,000 net acres. Also included in the transaction is about 60,000 net acres with exposure to the Duvernay shale. Logan Oil spin-out As part of the transaction, Logan will spin out Logan Oil Corp. to existing shareholders ahead of closing. The company will include the Sawn Lake steam-assisted gravity drainage (SAGD) project in Alberta’s Peace River region, to be acquired through a previously announced deal to acquire Andora Energy Corp. from CanAsia Energy Corp.; Clearwater assets in the Nipisi area to be acquired from Woodcote Energy Inc.; and certain undeveloped lands in northwest Alberta, including Charlie Lake lands. The assets will be excluded from the Ovintiv transaction and retained by Logan shareholders through the new company. Logan

That’ll be the case particularly in Appalachia, where many EQT and Range operations sit side by side and where new power generation facilities are being built to serve demand from data centers and other users. Rice said EQT today is exposed to 3 bcfd of demand from local markets. “That’s before we think about adding the sustainable growth,” Rice added. “We’ve got a significant amount of supply that we’re going to be able to support with gas supply contracts. This long-duration inventory that we have is going to allow us to continue to extend that opportunity set.” EQT CEO Jeremy Knop added that Range’s acreage along and near parts of the Ohio River is “almost like beachfront real estate” as economic development leaders in the region look to capitalize on long-term tailwinds from the data center, energy and advanced manufacturing sectors. Those factors, Rice said, helped kick EQT-Range talks into gear from a timing perspective. He told analysts that the long-term prospect of Range assets growing their capacity to 5 bcfd from today’s roughly 2.5 bcfd and EQT growing its productive capacity to more than 12 bcfd will allow the combined organization to be more aggressive in the market. “Seeing how we can put these companies together and take a significant piece of this opportunity, I think to me was the compelling catalyst for us to act now,” Rice said. Another contributor to making the deal work is Range’s natural gas liquids production, which accounts for about 30% of the company’s total output. Andrew Dittmar, principal analyst at Enverus Intelligence Research, said working more liquids into its profile has been a key strategic priority. “It helps lower the cost of supply relative to gas prices and improves cash flow when gas struggles, as it has through 2026,” Dittmar wrote. “That

Equinor ASA and Aker BP ASA have entered into a strategic collaboration on tight reservoirs on the Norwegian Continental Shelf (NCS). Through technology development, standardization, and greater scale, the companies aim to enable development of more discoveries and increase oil and gas recovery. The collaboration covers prospects, discoveries, and projects across the NCS, with the companies agreeing to contribute relevant opportunities from their respective portfolios and jointly identify where technology development, standardization, and exchange of experience can create the greatest value. The collaboration also includes resource maturation and well stimulation solutions. The ambition is to establish a sufficient and predictable activity level to support a competitive value chain, with the expertise and supplier capacity required to develop more tight reservoir discoveries. The collaboration will be governed through a joint steering structure and multidisciplinary working groups comprising representatives from both companies. Regional opportunities Large volumes of oil and gas remain in tight reservoirs on the NCS, with the Norwegian Offshore Directorate estimating a recoverable resource potential of about 2.8 billion boe in mapped tight reservoirs, comparable in size to the expected recoverable resources of Johan Sverdrup field. Many of the nearly 90 discoveries that have yet to receive a development decision are located in such reservoirs. Tight reservoirs have low permeability, meaning that oil and gas flow very slowly through the rock. Using conventional methods, only a limited share of the resources can be recovered, and many discoveries are too costly to develop on a standalone basis. The Norwegian Offshore Directorate has therefore encouraged companies to work together.

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