Listen to the article 5 min This audio is auto-generated. Please let us know if you have feedback. Dive Brief: Reliability risks are spreading across the bulk electric system, driven by soaring peak demand forecasts and lagging resource additions, the North American Electric Reliability Corp. said Thursday in its annual Long Term Reliability Assessment.  Summer peak demand across the bulk system is forecast to grow by 224 GW over the next 10 years, a more than 69% increase over the 2024 LTRA forecast and a 24% increase from 2025 peak demand, NERC said. New data centers account for most of the projected increase. Winter demand growth is even higher, with 246 GW of growth forecast over the next decade. The Midcontinent Independent System Operator, PJM Interconnection, Electric Reliability Council of Texas and parts of the Pacific Northwest all face a high risk of insufficient reserve margins or exceeding unserved energy criteria at some point within the next five years, according to the report.    Dive Insight: “The system is changing faster than the infrastructure needed to support it,” John Moura, NERC’s director of reliability assessments and performance analysis, said in a call with reporters. We are “in a period here where future electricity supply has never been more uncertain.” From 2024 to 2025, existing capacity from fossil-fueled generators fell by 21 GW, while bulk power system capacity for peak demand hours from battery, wind, and solar resources increased by 23 GW, according to the report. Bulk power system capacity “fell short of projections this year,” said Mark Olson, NERC’s manager of reliability assessments. “And that was the case last year as well,” he added. Delays in connecting new resources and unanticipated generator retirements are the cause of the miss. In a change from last year’s LTRA, NERC said solar PV is no longer the

The Railroad Commission of Texas (RRC) revealed its latest preliminary crude oil and natural gas production figures, which were for October last year, in a statement posted on its website recently. The preliminary reported total volume of crude oil in Texas in October 2025 was 125,078,417 barrels, according to the statement, which showed that the preliminary reported total volume of natural gas in the state during the same month was 957.0 billion cubic feet. The RRC noted in the statement that crude oil and natural gas production for October 2025 came from 157,228 oil wells and 84,019 gas wells. In its statement, the RRC highlighted that crude oil production reported by the RRC is limited to oil produced from oil leases and does not include condensate, which the organization said is reported separately by the RRC. The RRC also pointed out in the statement that preliminary figures are based on production volumes reported by operators and said they will be updated as late and corrected production reports are received. The RRC’s statement showed that the updated reported total volume of crude oil in Texas in October 2024 was 149,680,107 barrels. The preliminary reported total volume was 122,145,230 barrels, the statement highlighted. It showed that the updated reported total volume of natural gas in the state came in at 1.12 trillion cubic feet in October 2024. The preliminary reported total volume was 898.8 billion cubic feet, the statement outlined. According to the RRC’s statement, the county in Texas with the highest preliminary crude oil production figure in October 2025 was Martin, with 19,906,130 barrels. Midland ranked second, with 18,076,141 barrels, Loving was third, with 8,545,374 barrels, Upton was fourth, with 8,436,384 barrels, Reeves was fifth, with 6,374,887 barrels, Karnes was sixth, with 5,797,349 barrels, Reagan was seventh, with 5,603,608 barrels, Howard was

Murphy Oil Corp has increased its quarterly dividend per share by eight percent to $0.35, or $1.4 per share annualized for 2026. The bump-up comes despite the company expecting a fall in production this year. In 2026 Houston, Texas-based Murphy Oil projects 167,000-175,000 barrels of oil equivalent per day (boepd) in net output excluding non-controlling interest (NCI), compared to 182,294 boepd in 2025, according to its quarterly report. The 2025 figure grew from 177,412 boepd in 2024, toward the higher end of Murphy Oil’s guidance. In the fourth quarter of 2025, net production excluding NCI climbed to 181,431 boepd from 174,837 boepd in Q4 2024. Q4 2025 production surpassed the midpoint of guidance. Murphy Oil cited lower natural gas volumes from Tupper Montney for the expected decrease in annual production this year. The decline in the acreage, located in the Western Canadian Sedimentary Basin in British Columbia, “reflects the timing of new wells and higher royalty rates driven by anticipated AECO price strength”, Murphy Oil said. “Notably, while higher AECO prices adversely impact production through higher royalties, they boost our revenue realization as our Tupper asset is expected to generate over 35 percent in additional cash flow in 2026 compared to 2025. Furthermore, we plan to reach gas processing plant capacity with eight new wells versus 10 new wells in the prior year. “Overall, we expect to exit 2026 strong, supported by Chinook #8 and our Lac Da Vang (Golden Camel) asset coming online in the second half of the year”. Q4 2025 net profit was $11.89 million. That was a plunge from $50.34 million for Q4 2024 as lower liquids prices offset an increase in sales volumes and natural gas prices. After adjustment for nonrecurring items, net income landed at $0.14 per share. That beat the Zacks Consensus Estimate of $0.07 per

In a report sent to Rigzone by the Standard Chartered team on Wednesday, Standard Chartered Bank Energy Research Head Emily Ashford revealed the “market consensus” for the outcome of the next OPEC+ meeting, which is currently scheduled to take place on Sunday. “OPEC+ members meet virtually on February 1, with market consensus that the meeting will likely mirror January’s in both speed and outcome (rapid, with no policy change),” Ashford said in the publication. Ashford noted in the report that OPEC+’s monthly meetings “allow the group to be highly reactive and nimble in response to market conditions and sentiment”. “We have seen notable improvements in the forward curve over the past month,” Ashford said. “Backwardation at the front of the forward curve extends out through the 2026 contracts, while one month ago it was only the first three months, and the back of the curve has risen by $1 per barrel month on month,” the analyst added. “In addition, market sentiment appears to be gradually turning away from the overwhelmingly bearish ‘supply glut’ narrative that has dominated media reporting since Q4-2025,” Ashford continued. “However, we do not expect a pivot in strategy at this meeting and Q1 loadings remain paused,” the Standard Chartered analyst went on to state. The Standard Chartered Bank analyst projected in the report that “attention is more likely to fall on the OPEC+ overproducers’ updated compensation plans”. “Both Iraq and Kazakhstan have notable volumes to remove from their supply,” Ashford highlighted. “Kazakhstan’s compensation plan for January was 279,000 barrels per day, rising to 569,000 barrels per day for both February and March,” Ashford pointed out. Rigzone has contacted OPEC for comment on the Standard Chartered report. At the time of writing, OPEC has not responded to Rigzone. In a market update sent to Rigzone by the

GeoPark Ltd has signed a deal to buy Frontera Energy Corp’s oil and gas exploration and production assets in Colombia for up to $400 million plus assumed debt. The acquisition consists of 17 blocks in the Llanos and Lower Magdalena basins, GeoPark said in an online statement. GeoPark expects the licenses to immediately add 148 million barrels of oil equivalent (MMboe) to its proven and probable (2P) reserves and 99 MMboe to its proven reserves. The Quifa field in the Llanos basin has “potential to add approximately 16 MMboe of incremental net 2P reserves, for which a development plan is already under discussion”, the Latin American company added. The acquisition would result in the “consolidation of GeoPark’s core Llanos operating hub, adding large-scale, long-life assets including the Quifa field and the CPE-6, Guatiquia and Cubiro blocks, creating a highly synergistic corridor with greater scale, infrastructure utilization and operating efficiency”, GeoPark said. The acquisition also provides GeoPark “greater exposure to gas and condensate through the VIM-1 and El Dificil blocks, enhancing commodity diversification at a time of rising domestic gas prices in Colombia”, GeoPark said. “Pro forma production is expected to exceed 92,000 boepd [barrels of oil equivalent per day] by 2028, with EBITDA of approximately $950 million, doubling GeoPark’s previously announced 2028 standalone outlook of 44,000-46,000 boepd and $490-520 million of EBITDA”, it said. “Increased scale and diversification are expected to enhance cash flow generation, lowering the cash breakeven by approximately $8 per barrel at current strip prices.  “The stronger and more stable cash flow base is expected to materially improve GeoPark’s capacity to fund its growth plans in [Argentinian shale play] Vaca Muerta, while maintaining its disciplined capital allocation”. “In addition to the upstream asset portfolio, the transaction includes Frontera Energy’s integrated water management and environmental sustainability project, comprised of the SAARA

Prediction markets now put the probability of the U.S. striking Iran before June this year at 71 percent. That’s what Erik Meyersson, Chief EM Strategist at Skandinaviska Enskilda Banken AB (SEB), said in a report sent to Rigzone by the SEB team on Friday. “Brent crude futures rose above $70 per barrel yesterday (it now stands at $69.8), indicative of a substantial risk premium,” he noted. In the report, Meyersson warned that “another war including a naval intervention may bring greater risks of an event in the Strait of Hormuz”. “Given the limitations to [a] direct U.S. military strike, a likely scenario is that the U.S. seeks to start with a naval intervention to intercede Iran’s shadow fleet and sanctioned oil exports,” he said. “This also implies a higher chance of a risk event involving the Strait of Hormuz than last year’s war,” he warned. “The Polymarket estimate of the probability that Iran may attempt to close the Strait is 31 percent, compared to 24 percent on June 11th last year. The oil VIX index is at 55.4 percent, compared to 43.2 percent last year,” he added. “Even the Brent oil price is now on par with the level prevailing just before the June war, despite starting from a lower baseline,” Meyersson continued. “The Brent futures curve has seen a larger shift upwards relative to the period preceding last year’s war. This is the case for both the front-month and 12-year contract,” he went on to state. In a Rystad Energy market update sent to Rigzone just before 3pm GMT time on January 29, Rystad noted that oil prices had “risen sharply to $71.50 per barrel over the past few hours, their highest level since late September 2025, driven by mounting market speculation of an imminent U.S. military strike on Iran”.