Listen to the article 4 min This audio is auto-generated. Please let us know if you have feedback. Dive Brief: The Southwest Power Pool board of directors on Wednesday approved an $8.6 billion slate of 50 transmission projects across its 14-state footprint. The projects are intended to help the grid operator meet peak demand, which it expects will double, to reach 109 GW, in the next 10 years. Key to the 2025 Integrated Transmission Plan is development of a 765-kV regional transmission “backbone” that can carry four times the power SPP’s existing 345-kV lines do, and do so more efficiently. The grid operator’s transmission system “is at capacity and forecasted load growth will only exacerbate the existing strain,” it said. “Simply adding new generation will not resolve the challenges.” 765-kV transmission lines are the highest operating voltages in the U.S. but are new in both SPP and in the neighboring Electric Reliability Council of Texas market. Texas regulators approved the higher voltage lines for the first time in April. Dive Insight: Transmission developers in SPP and ERCOT are turning to 765-kV projects to mitigate line losses and move greater volumes of power into demand centers at a time when electricity demand is expected to rise significantly. “With the new load being integrated into the system, SPP could see an increase in the footprint’s annual energy consumption by as much as 136%,” the grid operator said in its ITP. “Investments in transmission are the key to keep costs low, maintain reliability, and power economic growth.” Even under conservative assumptions, SPP forecasts a 35% increase in demand, “making timely transmission investment essential,” the grid operator said. SPP selected Xcel Energy in February to construct the first 765-kV lines in its footprint. Those lines were identified in its 2024 plan. AEP Texas will build

The price gas power merger and acquisitions have reached in some markets, according to energy analytics firm Enverus. The artificial intelligence boom, along with expectations of increased manufacturing and electrification, is driving a surge in natural gas investment, but thermal generation remains risky, some analysts say, drawing parallels to the dot com bubble at the turn of the century. 

Alexandra Klass is the James G. Degnan Professor of Law at Michigan Law, and Dave Owen is the Albert Abramson ’54 Distinguished Professor of Law at UC Law San Francisco. The United States faces massive growth in electricity demand. If utilities’ projections are right, data centers will drive much of that growth. And if utilities try to meet that demand in traditional ways, the results could be bad for consumers, the environment and the tech industry. Those traditional ways assume that utilities must meet the needs of electricity customers at all times. This requires utilities to build new power plants and transmission and distribution lines and (in most states) pass those costs, plus a profit margin, on to consumers. Utilities also will not allow major new users to connect to the grid until those users’ needs can be met. These principles are a poor fit for the present moment. Building new power plants and transmission lines has become increasingly difficult. If data centers must wait until that infrastructure is fully built, they may wait for years. Worse, utilities and government officials are citing the potential data-center boom as a reason to extend the life of old, expensive, and heavily polluting coal plants or to build new gas plants. If they do so, and if they pass those costs on to consumers, retail electricity prices and pollution will rise. And if current demand projections turn out to be overestimates — which has happened during past tech booms — consumers will pay for new power plants that never needed to be built. But this unfortunate scenario is not inevitable. We are scholars of energy, natural resources, and environmental law, and in a paper we explore a better way of meeting this moment. Our inspiration comes from legal systems for allocating water, particularly in

The oil market appears “torn”. That’s what Standard Chartered Bank Energy Research Head Emily Ashford outlined in a report sent to Rigzone by the Standard Chartered team this week, which included a Brent price forecast from Standard Chartered’s machine learning model for next Monday. “The market appears torn between the overwhelming media narrative of an impending supply glut just over the horizon on the one hand, and increasingly unpredictable U.S. policy with a focus on some of the largest producers, and the demand implications of the evolving tariff/trade war landscape on the other,” Ashford said in the statement. “Front-month Brent crude prices closed at $68.89 per barrel on 3 November, just $0.01 per barrel higher than our machine learning model SCORPIO’s forecast set last week,” Ashford added. “This week the model sees an increase of $1.67 per barrel to $66.56 per barrel settlement on Monday 10 November, mainly driven by data from the U.S. (pointing sideways but bullish altogether),” Ashford continued. In the report, Ashford cautioned that “the ongoing U.S. shutdown means that some key data releases remain on pause”. Ashford highlighted in the report that Standard Chartered’s “core view” is that crude oil sentiment “is currently overwhelmingly negative”. “We expect near-term weakness driven by perceived market oversupply and global demand indicators,” Ashford noted. “Low prices then start to quash U.S. shale output growth, and if OPEC+’s return of barrels is sustained, the market will highlight tightness and geographic concentration of spare capacity, which we expect to be supportive in the medium term,” Ashford added. Standard Chartered’s report projected that the ICE Brent nearby future crude oil price will average $68.50 per barrel overall in 2025 and $63.50 per barrel overall in 2026. The report forecast that the commodity will come in at $65 per barrel in the fourth quarter

DNO ASA and Aker BP ASA have signed agreements to recalibrate their exploration and production ownerships in the Norwegian continental shelf, including the Kjottkake discovery. Aker BP will assume operatorship of Kjottkake until the start of production, after which DNO will resume operatorship, according to online statements by the companies on Thursday. The move allows for faster development, with production now targeted for the first quarter of 2028, the companies said. Fornebu, Norway-based Aker BP “will draw on its alliance with suppliers and its equipment inventory to deliver the project on time”, DNO said. “Three years from discovery to production is a standout on the Norwegian continental shelf, where such tie-backs typically take at least twice as long to complete”, DNO said. DNO discovered Kjottkake earlier this year in the northern North Sea under Production License 1182 S (PL 1182 S). “The discovery was made in Paleocene injectite sandstones of excellent reservoir quality with preliminary estimates of gross recoverable resources in the range of 39 to 75 million barrels of oil equivalent (MMboe), with a mean of 55 MMboe”, DNO said in a press release March 26. “The Kjottkake exploration well encountered a 41-meter oil column and a nine-meter gas column. A sidetrack drilled horizontally 1,350 meters westwards along the reservoir in the Sotra Formation confirmed the presence of the oil column throughout the discovery”. Kjottkake sits 27 kilometers (16.78 miles) northwest of the Troll C platform and 44 kilometers southwest of the Gjoa platform, according to DNO. Under the swap agreements, DNO and Aker BP retain their Kjottkake stakes of 40 percent and 45 percent respectively. Concedo AS holds 15 percent. Also under the agreements DNO will transfer its 28.9 percent stake in the producing Vilje field to Aker BP, whose interest will increase to 75.76 percent. Aker BP

Oil extended declines after Saudi Arabia lowered the prices of its crude, signaling uncertainty surrounding the supply outlook, while equities slumped in another pressure on the commodity. West Texas Intermediate settled near $59, sliding around 0.3% on the day after falling in the previous two sessions. Volatility hit Wall Street, also weighing on oil prices. Saudi Arabia lowered the price of its main oil grade to Asia for December to the lowest level in 11 months. Even though the price cut met expectations, traders saw it as a bearish signal about the cartel’s confidence in the market’s ability to absorb new supply, with a glut widely expected to begin next year. Prices have given up ground since the US sanctioned Russia’s two largest oil producers last month over Moscow’s war in Ukraine, and abundant supplies have so far managed to cushion the impact of stunted flows from the OPEC+ member to major buyers India and China. Key price gauges indicate that supply perceptions are worsening, with the premium that front-month WTI futures command over the next month’s contract, known as the prompt spread, narrowing in the past few weeks to near February lows. That’s also true for Brent crude. Still, US shale companies are forging ahead with their production plans, with Diamondback Energy Inc., Coterra Energy Inc. and Ovintiv Inc. this week announcing they inend to raise output slightly for this year or 2026 despite oil prices falling close to the threshold needed for many US shale wells to break even. Oversupply gloom hasn’t permeated refined products markets, though. Traders are still assessing how those supplies may be impacted by the US clampdown on purchases of Russian crude and Ukraine’s strikes on its neighbor’s energy assets. Those factors, as well as diminishing global refining capacity, bolstered diesel futures and gasoil