Global crude oil prices are expected to remain near $100/bbl through yearend 2026 as continued Middle East supply disruptions, tanker attacks, and constrained shipping capacity keep oil markets tight, the US Energy Information Administration (EIA) said in its November Short-Term Energy Outlook (STEO). EIA forecasts Brent crude oil spot prices will average about $100/bbl in November and December before gradually declining in 2027 as Middle East production recovers and global inventories rebuild. Brent is projected to average $97/bbl in 2026 and $86/bbl in 2027, falling to $77/bbl by fourth-quarter 2027. Brent averaged $124/bbl in October, up $10/bbl from September and the highest monthly average since July 2022 on an inflation-adjusted basis. Prices rose for a third consecutive month as declining inventories, tanker attacks in the Middle East and Black Sea, and higher shipping costs disrupted global oil flows. However, Middle East exports increased slightly in October following the restart of Saudi Arabia’s East-West Pipeline, according to Vortexa vessel-tracking data cited by EIA. Continued shipments through the Strait of Hormuz, supported by ship-to-ship transfers along Oman’s coast, also helped ease supply constraints. Brent fell below $100/bbl on Nov. 4. Middle East crude oil production shut-ins averaged an estimated 2.5 million b/d in October, down sharply from a peak of 10.9 million b/d in May. EIA expects disruptions to remain near 2.5 million b/d through fourth-quarter 2026 before declining to 1.9 million b/d in first-half 2027 and 1.3 million b/d in the second half. EIA assumes most Middle East production outside Iran will return to pre-conflict levels by mid-2027, supported by pipeline bypass routes, ship-to-ship transfers, and additional pipeline capacity in the United Arab Emirates. Iranian exports, however, are expected to remain constrained throughout the forecast period. Global oil inventories declined by an estimated 1.2 million b/d in third-quarter 2026 but are

Salt Creek Midstream LLC has ordered long-lead equipment for a fourth cryogenic natural gas processing plant at its Pecos Processing Complex in Reeves County, Tex. Slated for final investment decision by yearend 2026, the proposed Pecos IV train project, if approved, would add up to 300 MMcfd of capacity and enter service in second-half 2028, the operator said in a release Nov. 11. Depending on a final capacity decision for the project, the expansion could lift the company’s overall installed Permian gas processing capacity to as much as 900 MMcfd. With the Pecos site designed for further expandability up to 1.2 billion bcfd from its current 600-MMcfd capacity, Salt Creek said it has also now secured grid power to support that potential buildout. The proposed project follows customer and volume growth across Salt Creek’s Delaware basin system, which the company said will exceed its existing system’s 600 MMcfd of processing capacity in first-half 2027. To support its planned Permian growth program, Salt Creek confirmed it has also secured strategic offloading contracts to provide firm processing capacity as a bridge to the planned expansions. Those offloads are scheduled to enter service by the end of first-quarter 2027, according to the operator. Salt Creek reported the addition of nearly 300,000 acres dedicated across the Permian’s eight core counties, following additional acreage commitments signed earlier in the year. The dedications cover more than 20 unidentified customers. The operator said it expects about 75% of anticipated 2027 throughput to come from investment-grade counterparties, while customer volume commitments to support about 35% of projected volumes. The company’s acreage position includes about 40,000 dedicated acres in the liquids-rich core of the Woodford fairway, along with additional exposure to prospective areas. Salt Creek estimated Woodford volumes to exceed 200 MMcfd by yearend 2027 based on more than

Listen to the article 5 min This audio is auto-generated. Please let us know if you have feedback. Gisela Glandt is vice president of virtual power plants at Uplight, a provider of utility demand management solutions. Load growth is back, and it isn’t slowing down. Electrification, data centers and extreme weather are pushing utilities to find flexible capacity faster than they can build it. Demand-side programs including demand response, virtual power plants, time-varying rates and energy efficiency are one of the few levers that scale quickly and cost-effectively — yet the industry keeps hitting the same wall. Gisela Glandt Roughly 80% of customers say they want help managing their energy, but utilities are still seeing enrollment in demand management programs around 10% — despite larger incentives, more innovative technology, and more targeted marketing. What if the problem isn’t the customers and instead is the process of asking them to raise their hand? Opt-in utility program enrollment puts the burden on the customer: to understand the program, check to see if they are eligible, decide it’s worth it, and then take action. The benefits and incentives can show up months down the road, and they may even forget about them. Most people don’t make it past enrollment and it’s not because of lack of interest. It simply involves too many steps and too much brain power.  The industry is shifting from programs customers must join to flexibility that’s already embedded as a default or activated at the point of sale of a device, with no enrollment required. Where utilities have made this shift, customer participation climbs from 10% into the 70% to 100% range. One Midwestern utility that restructured a program from opt-in to opt-out scaled capacity four to five times faster — and had 70% to 80% of customers participate. 

Planet One Oil & Gas has encountered hydrocarbons in the Nya Gyidie-1X exploration well on the Deepwater Cape Three Points (DWCTP) Block offshore Ghana, opening what the company describes as a new carbonate exploration play in the country. The well, drilled about 148 km offshore in 2,289 m of water, encountered hydrocarbons in carbonate reservoirs between 3,364 m and 3,499 m measured depth. Planet One said further technical evaluation is under way to determine the discovery’s size and commercial potential. According to the operator, Nya Gyidie-1X is Ghana’s first successful test of a Cenomanian-Turonian carbonate reservoir system as a primary exploration target. Most of the country’s commercial oil and gas discoveries to date have been associated with sandstone reservoirs. “The significance of Nya Gyidie-1X goes beyond the hydrocarbons encountered in this well,” said Kwame Ntow Amoah, chief executive officer of Ghana National Petroleum Corp. “For the first time in Ghana, we have tested and confirmed hydrocarbons in a carbonate reservoir system, opening up a new geological play for further exploration.” The DWCTP block covers about 1,454 sq km in the Deepwater Tano basin. Planet One operates the block with partners GOIL Upstream Ltd. and Ghana National Petroleum Corp.

@import url(‘https://fonts.googleapis.com/css2?family=Inter:wght@100..900&display=swap’); .ebm-page__main h1, .ebm-page__main h2, .ebm-page__main h3, .ebm-page__main h4, .ebm-page__main h5, .ebm-page__main h6 { font-family: Inter; } body { line-height: 150%; letter-spacing: 0.025em; } button, .ebm-button-wrapper { font-family: Inter; } .label-style { text-transform: uppercase; color: var(–color-grey); font-weight: 600; font-size: 0.75rem; } .caption-style { font-size: 0.75rem; color: color-mix(in srgb, currentColor 60%, transparent); } Chevron Corp. has agreed to farm out to QatarEnergy a partial, non-operated interest in an exploration block offshore Namibia. Financial details were not disclosed.   Through the agreement, Chevron subsidiary Chevron Namibia Exploration II Ltd. will farm out 25% interest in Petroleum Exploration License 0082 (PEL82), comprising blocks 2112B and 2212A in Walvis basin, QatarEnergy said in a release this week. Upon completion of the deal, Chevron will remain operator of the block with 55% interest. Namcor E&P and Custos Energy will each hold a 10% interest. PEL82 covers an area of about 11,444 sq km in water depths of 350-2,300 m. Chevron acquired an 80% operated interest in the license in 2024 through a farm-in deal with National Petroleum Corp. of Namibia (Namcor). At the time of Chevron’s farmout with Namcor, about 70% of the total block area was covered by existing seismic (3,500 km of 2D and 9,500 sq km of 3D) data. Previous drilling activity on the license included the Murombe-1 and Wingat-1 wells. Results confirmed regional extension and presence of the Barremian-Aptianoil-prone source rock (Kudu shale). The Murombe-1 penetrated the Baobab sands with about 20% porosity. The Wingat-1 well recovered 38-41° API oil to surface.

The U.S. Department of Energy’s (DOE) Office of Energy Dominance Financing (EDF) today announced the financial close of a $480 million loan for Arena Energy’s Project Elkhorn to increase oil and natural gas production across the Gulf of America shelf. The project will modernize 22 offshore platforms off the coast of Louisiana and, at peak production, is expected to add up to 38,600 barrels of oil per day and up to 77 million cubic feet of natural gas per day to U.S. energy production. Today’s announcement is made possible by President Trump’s Working Families Tax Cut and marks the Energy Department’s first closed loan supporting domestic oil and natural gas production, underscoring DOE’s commitment to advancing American energy dominance and delivering affordable, reliable, and secure energy for American families and businesses. “The United States is the world’s largest producer and exporter of oil and natural gas, and thanks to President Trump, American energy production will continue to grow,” said U.S. Secretary of Energy Chris Wright. “Project Elkhorn will increase oil production by up to 38,600 barrels per day and create thousands of jobs. By providing financing for projects like Project Elkhorn, the Energy Department is expanding domestic production and strengthening our energy security to power American prosperity for decades to come.” Arena Energy currently produces approximately 30,000 barrels of oil per day offshore in the Gulf of America. Project Elkhorn will modernize existing offshore infrastructure and expand production capacity—adding approximately 125 million barrels of oil and 250 billion cubic feet of natural gas to U.S. energy production over the life of the project. The project will create 2,400 construction-related jobs and 400 operations jobs in one of the nation’s most important offshore energy corridors. “Thanks to President Trump and Secretary Wright’s leadership, EDF is putting existing energy infrastructure back to work for the American people,” said EDF Director Gregory A. Beard. “Project Elkhorn will expand domestic oil and natural gas production, create good-paying