North America added 94 rigs week on week, according to Baker Hughes’ latest North America rotary rig count, which was published on January 9. Although the total U.S. rig count dropped by two week on week, the total Canada rig count increased by 96 during the same period, pushing the total North America rig count up to 741, comprising 544 rigs from the U.S. and 197 rigs from Canada, the count outlined. Of the total U.S. rig count of 544, 525 rigs are categorized as land rigs, 16 are categorized as offshore rigs, and three are categorized as inland water rigs. The total U.S. rig count is made up of 409 oil rigs, 124 gas rigs, and 11 miscellaneous rigs, according to Baker Hughes’ count, which revealed that the U.S. total comprises 475 horizontal rigs, 57 directional rigs, and 12 vertical rigs. Week on week, the U.S. land rig count dropped by two, and its offshore and inland water rig counts remained unchanged, Baker Hughes highlighted. The U.S. oil rig count dropped by three week on week, its gas rig count dropped by one, and its miscellaneous rig count increased by two week on week, the count showed. The U.S. horizontal rig count dropped by one, its vertical rig count dropped by two, and its directional rig count increased by one, week on week, the count revealed. A major state variances subcategory included in the rig count showed that, week on week, Louisiana dropped three rigs, and New Mexico, North Dakota, Texas, and Wyoming each dropped one rig. Utah added four rigs and Colorado added one rig week on week, the count highlighted. A major basin variances subcategory included in the rig count showed that, week on week, the Permian basin dropped three rigs, the Haynesville, Mississippian, and Williston basins

Intensity Infrastructure Partners LLC and power producer Rainbow Energy Center LLC have indicated they are nearing a positive final investment decision (FID) on a new pipeline project to bring Bakken natural gas to eastern North Dakota. “[T]he firm transportation commitments contained in executed precedent agreements are sufficient to underpin the decision to advance Phase I of their 36-inch natural gas pipeline in North Dakota, reflecting growing confidence in the region’s long-term power and industrial demand outlook”, the companies said in a joint statement. “This approach establishes a scalable, dispatchable power and gas delivery hub capable of adapting to evolving market conditions, supporting sustained data center growth, grid reliability needs and long-term industrial development across North Dakota”. “The system will provide reliable natural gas supply through multiple receipt points, including Northern Border Pipeline, WBI Energy’s existing transmission and storage network, and direct connections to six Bakken natural gas processing plants, creating a highly integrated supply platform from Bakken and Canadian production”, the online statement added. “The pipeline is designed to operate without compression fuel surcharges, reducing operational complexity while enhancing reliability and tariff transparency for shippers. “Uncommitted capacity on phase I supports incremental gas-fired generation along the planned pipeline corridor and at Coal Creek Station, leveraging existing power transmission infrastructure, a strategic geographic location and a proven operating platform. “The 36-inch pipeline enables future throughput increases without the need for duplicative greenfield infrastructure as demand continues to develop”. Rainbow chief executive Stacy Tschider said, “By leveraging established assets like Coal Creek and integrating directly with basin supply and interstate systems, this project is positioned to meet near-term needs while remaining expandable for the next generation of load growth”. The project would proceed in two phases. Phase 1 would build a 136-mile, 36-inch pipeline with a capacity of about 1.1 million dekatherms a day (Dthd). The phase 1 line would

In an insight report released recently, analysts at Wood Mackenzie outlined that U.S. tight oil production “will shrink without a crash event for the first time” in 2026. “Holding oil production flat in the U.S. today requires over two million barrels per day of new supply,” the analysts said in the report. “We expect output to fall by 200,000 barrels per day in 2026 with WTI prices 20 percent lower than 2025,” they added. “This signal could change market mentality and bolster international conventional investment plans. But caution is still needed. That 2026 tight oil deficit is filled by Guyana alone, and U.S. liquids will return to growth in 2028,” the Wood Mackenzie analysts continued. In its latest short term energy outlook (STEO) at the time of writing, which was released back in December 2025, the U.S. Energy Information Administration (EIA) showed that Lower 48 States crude oil production, including lease condensate and excluding the Gulf of America, would drop from an average of 11.29 million barrels per day in 2025 to an average of 11.11 million barrels per day in 2026. This production came in at 11.03 million barrels per day in 2024, the EIA’s December STEO highlighted. Total U.S. crude oil production, including lease condensate, was projected to drop from an average of 13.61 million barrels per day in 2025 to an average of 13.53 million barrels per day in 2026 in that STEO. Total U.S. crude oil output, including lease condensate, averaged 13.23 million barrels per day in 2024, the EIA’s latest STEO at the time of writing showed. The EIA’s next STEO is scheduled to be released on January 13. In the Wood Mackenzie report, the analysts also predicted a shale gas “renaissance” in the U.S. this year. “As LNG FIDs have come thick and fast,

Tamboran Resources Corp has appointed Todd Abbott, former chief operating officer (COO) of Seneca Resources Co LLC, as chief executive officer (CEO) effective January 15. Abbott takes over from interim CEO Richard Stoneburner, who remains chair. Stoneburner assumed the role of interim CEO in the third quarter of 2025 following Joe Riddle’s resignation. “Abbott has over 25 years’ upstream oil and gas experience spanning unconventional shale operations, business planning, corporate finance and strategy”, Tamboran said in an online statement. Before becoming COO of Seneca Resources, where he gained Appalachian Basin experience, Abbott was part of Marathon Oil Corp and Pioneer Natural Resources Co. At Marathon and Pioneer, Abbott had oversight of Permian Basin, Eagle Ford and Alaskan operations, Tamboran noted. “His background at Seneca, Marathon and Pioneer demonstrates an ability to improve productivity while lowering costs, which aligns with our focus on safe and efficient execution and delivering value for shareholders from our Beetaloo Basin development”, Stoneburner said. Abbott said, “The scale and opportunity that Tamboran has in the Beetaloo Basin, supported by the quality of the board and management team, is what has attracted me to the CEO role”. Abbott takes over what would be an enlarged Tamboran, which is in the process of completing the acquisition of Falcon Oil & Gas Ltd. On September 30, 2025, Sydney-based Tamboran and British Columbia-incorporated Falcon announced a definitive merger agreement that they said would create a leading position of about 2.9 million net acres in the Beetaloo sub-basin onshore Australia’s Northern Territory. “The acquisition is accretive to Tamboran stockholders given the implied acreage value of $169 per acre reflects a four percent discount to Tamboran’s current implied acreage value of $176 per acre”, a joint statement said. Tamboran and Falcon are already partners through the Beetaloo Joint Venture, which last year sanctioned the

Utility leaders are managing a hard reality. Load is growing faster than the grid was built to handle, increasing the likelihood of costly upgrades and rate pressure. AI-driven data center development is making headlines as a major source of load growth. These projects are large, fast-moving and highly visible, drawing public attention and political scrutiny. Utilities and commissions are now facing the question: “How do we add capacity quickly, without overbuilding the grid and pushing costs into rates?” One of the most promising answers is leveraging distributed load flexibility. With distribution-level orchestration, this flexibility can enable utilities to serve growing loads on existing distribution infrastructure, supporting affordability for all customers. Bottom-up load growth requires bottom-up solutions Distributed load flexibility refers to the growing share of new electricity demand that is spatially distributed across the grid and can be shifted temporally. The flexibility opportunity now includes electric vehicles, batteries, heat pumps, smart water heaters and connected building systems. These grid-edge devices are distributed across homes, workplaces and commercial zones. Adoption of these resources is accelerating and many already respond to price signals and automation. Managed EV charging is a common example. A vehicle may be plugged in overnight but only needs a few hours of charging. When charging is scheduled to avoid bottlenecks, that flexibility becomes a real capacity tool for the utility. However, many programs, price signals and planning tools were designed for bulk system needs. Time-of-use rates and demand response reduce system peaks by telling every device to do the same thing: shift away from the bulk system peak. The “just shift it off-peak” solution misses a significant risk. Flexibility without orchestration simply moves the problem rather than solving it. EV charging can synchronize around the same low-cost hours. Batteries can do the same if they charge in identical

For decades, municipalities and utility companies have buried water mains, gas lines, fiber optic conduits, power cables and other vital infrastructure under streets and sidewalks. Burying these systems improves safety, reliability and aesthetics, but it also creates a long-term problem: once installed, many of these utilities become practically invisible. The ground protects and hides them, but over time the memory of where they run becomes foggy. Records age, streets are widened or rerouted and even highly accurate GPS coordinates can drift or lose relevance as the surface infrastructure changes. The result? What was once a known network of pipes and cables becomes a metaphorical “lost treasure.” When crews dig — for maintenance, upgrades or new construction — that invisibility can turn into a disaster. Minor incidents are common: broken lines that cause service disruptions and headaches. But sometimes the consequences are far worse: ruptured gas mains, flooding from damaged water or sewer lines, or severed fiber cables; all capable of causing serious safety hazards, costly repairs and major public inconvenience. The limitations of “traditional” locating Historically, locating buried plant often relied on conductive materials (metal pipes, conduits or tracer wires). These can be detected with standard locating equipment. But since the 1970s, many new installations, especially gas, water and fiber optic conduits, have been built using nonconductive materials such as PVC or HDPE. When utilities are nonconductive, conventional electromagnetic locators often fail. In blind trials (McMahon, 2000) using standard survey methods, as much as half of all subsurface utilities were missed. [AC1] Additionally, PHMSA (Pipeline Hazardous Materials Safety Administration) has reported (PHMSA, 2025) an average cost of $594,218,469 over the past three years for gas utility pipeline incidents with an average of 11 deaths and 30 injuries. More expensive and specialized methods exist such as ground penetrating radar (GPR), but these have