BP Plc’s profit exceeded expectations, with operational improvements and higher oil and gas production outweighing lower prices, as the company’s turnaround plan builds momentum. The British energy giant posted adjusted third-quarter net income of $2.21 billion, higher than the average analyst estimate of $1.98 billion. Its quarterly share buyback plan was maintained and net debt rose slightly.  The results signal Chief Executive Officer Murray Auchincloss is starting to deliver a turnaround plan to win back investor confidence by focusing on oil and gas production, selling non-strategic assets and cutting costs.  “We continue to make good progress to cut costs, strengthen our balance sheet and increase cash flow and returns,” Auchincloss said in BP’s earnings statement. “We are looking to accelerate delivery of our plans, including undertaking a thorough review of our portfolio.” BP shares were little changed in London trading, as crude prices declined. BP’s plan to divest $20 billion of assets by the end of 2027 to improve the balance sheet still includes expectations of a transaction for lubricants business Castrol, Auchincloss said in an interview on Bloomberg TV. The firm also raised its disposal expectations for 2025, saying proceeds will exceed $4 billion after previously guiding between $3 to $4 billion. Quarterly share buybacks were held at $750 million, a reduced level BP announced earlier this year along with a strategic reset. Gearing — a ratio of net debt to equity that analysts have flagged as elevated compared to peers — ticked higher to 25.1%, from 24.6% in the previous quarter. Even though the company returned to focusing on fossil fuels, BP said its full year reported upstream production is expected to be slightly lower than last year. But in a telephone interview on Tuesday, Auchincloss said “maybe we’ll do better than that, but we don’t want to

Implementation of the Inflation Reduction Act and Bipartisan Infrastructure Law suffered from muddled aims, and projects took too long to materialize under the Biden administration, according to an October report from former Department of Energy staffers who interviewed more than 80 of their former colleagues on the topic. The slow rollout meant that the “political theory animating the [Biden] administration’s approach — that the economic development generated by clean energy projects and industries would create a durable bipartisan coalition — was never truly tested,” and the Trump administration has been able to claw back much of the associated funding, the report says. “Programs frequently tried to satisfy multiple aims at once: decarbonization, onshoring, labor, equity, national security,” the report says. “This layering of priorities blurred mandates and slowed action. This proved to be particularly challenging for requirements that were at odds with energy industry realities (e.g., impractical [Build America Buy America] requirements for every component; labor union requirements for transmission projects where union labor didn’t exist).” The report was written by Ramsey Fahs, a former policy advisor at DOE; Louise White, a former senior consultant with DOE’s Loan Programs Office and Office of Technology Transitions; and Alan Propp, who first worked as a senior strategy consultant with DOE’s LPO and then served as a deputy chief of staff in its Loan Underwriting and Structuring Division. All three left the agency in January.  The authors say they interviewed more than 80 “political appointees and career staff who sat at the heart of implementation, with a primary focus on the infrastructure offices” at DOE, and noted that the interviews “are not exhaustive and at times interviewees reported conflicting information or divergent experiences.” However, interviewees seemed to agree that the implementation of the IRA and BIL was hampered by jumbled priorities, as well

Listen to the article 13 min This audio is auto-generated. Please let us know if you have feedback. Twenty-five years ago, a data center boom helped fuel a race to build gas-fired power plants, with the energy secretary, utilities, politicians and experts warning of blackouts and economic stagnation if the country didn’t meet surging demand for electricity. By 2001, however, the dot com bubble had burst, the economy was in recession and the huge demand increase never materialized. Efficiency and productivity improved rapidly, and demand remained more or less level for the next two decades, leaving many utilities with excess capacity and ratepayers footing the bill. Some analysts and industry sources see parallels between then and now. Once again, headlines are warning of imminent energy shortfalls due largely to the power needs of artificial intelligence. Leading figures in government and industry are promoting more firm generation, and particularly gas, as a matter of economic and national security.  “Can the same thing happen? Definitely,” said Eugene Kim, Wood Mackenzie’s Americas Gas Research team director. “The utilities and anyone planning for power demand is forecasting unprecedented and, in some cases, even exponential growth. Whether that materializes or not – huge degree of uncertainty.” Gas investment reaches new heights Investment firms, utilities, tech giants, energy companies and others are pouring billions into acquiring existing gas plants or developing new ones to serve data centers. Gas power merger and acquisition valuations have doubled since 2024, reaching up to $1.93 million/MW in some markets, according to energy analytics firm Enverus.  While there are echoes of the millennium today, there are a few important differences.  The first is that the U.S. is producing and consuming more gas than ever before — driven largely by the rise of fracking — with production concentrated in Texas and Louisiana

In a statement posted on its website recently, 80 Mile Plc announced that an independent petroleum reserves and resources evaluation identified “13 billion barrel potential” at Jameson Land Basin in Greenland. “80 Mile plc … notes the recent announcement …  by its U.S. joint venture partner, March GL Company and Pelican, regarding the results of an independent assessment and prospective resources report prepared by Sproule ERCE confirming the world-class potential of the Jameson Land Basin, located in Eastern Greenland,” 80 Mile said in the statement. “Independent assessment by U.S. based oil field specialists, Sproule ERCE estimate 13.03 billion barrels (P10) of gross un-risked recoverable prospective oil resources across the upper levels of the Jameson Basin,” it added. “The report also highlights potential upside outside these already identified target areas, across the broader license and at depth. Specifically, the Permian base layer,” it continued. In the statement, 80 Mile highlighted that its attributable share equates to approximately 3.9 billion barrels (P10) based on its 30 percent interest post earn-in completion. The company also noted that the report “identifies 58 prospects and leads, putting Jameson among the most prospective undrilled basins globally”. 80 Mile pointed out in the statement that it and March GL had previously entered into a binding joint venture agreement for drilling to commence at Jameson. Under this agreement, March GL will fund 100 percent of the costs associated with up to two exploration wells, each to a minimum depth of 3,500 meters, designed to delineate the hydrocarbon potential of the Jameson Basin, 80 Mile noted in its latest statement. In return, March GL may earn up to a 70 percent working interest, with 80 Mile retaining a 30 percent interest through its wholly owned subsidiary White Flame Energy A/S upon completion of the second well, 80 Mile added. “Until that time, 80 Mile retains 100

Shell plc reported stronger-than-expected third-quarter 2025 earnings on Oct. 30, buoyed by robust operations, higher trading contributions, and steady upstream performance in key regions. The oil major posted adjusted earnings of $5.4 billion, topping the company’s own forecast of $5.09 billion. The result compares with $6 billion in the same quarter a year earlier and $4.26 billion in second-quarter 2025. Cash flow from operations (CFFO) totaled $12.2 billion, down from $14.7 billion a year earlier. Cash capital expenditure was at $4.9 billion for the quarter. “Shell delivered another strong set of results, with clear progress across our portfolio and excellent performance in our Marketing business and deepwater assets in the Gulf of Mexico and Brazil,” said chief executive officer Wael Sawan, citing record output in Brazil and two-decade highs in the Gulf, along with the highest marketing earnings in more than a decade.  To sustain its shareholder returns, Shell noted another $3.5-billion share buyback program for the next 3 months; the 16th consecutive quarter of at least $3 billion in buybacks. The company also reduced its net debt to $41.2 billion, down from $43.2 billion in the previous quarter. Shell third-quarter operational highlights Adjusted earnings for Integrated Gas were $2.14 billion, higher than in $1.7 billion second-quarter 2025, reflecting higher volumes and significantly higher trading and optimization results. The company’s LNG Canada project ramped up, with 13 cargoes delivered from phase 1. Shell said it expects startup of the second phase later this quarter. Upstream delivered $1.8 billion in adjusted earnings, up from $1.7 billion in second-quarter 2025, reflecting higher volumes, partly offset by the rebalancing of participation interests in Brazil. Marketing contributed $ 1.32 billion in adjusted earnings, up from $1.2 billion in the previous quarter, benefiting from higher margins and seasonally higher volumes. Chemicals & Products reported $550 million

ExxonMobil Corp. announced third-quarter 2025 earnings of $7.5 billion, up from $7.1 billion for second-quarter 2025 but down from $8.6 billion for third-quarter 2024. Year-to-date earnings totaled $22.3 billion, down from $26.1 billion for the same period last year. Exxon noted that this drop in earnings from a year ago was primarily due to the lower oil price environment, with Brent crude averaging $68.20/bbl in the third quarter, a 13% decline compared to the same quarter last year. Exxon’s free cash flow for third-quarter 2025 was $6.3 billion, down from $11.3 billion in the same quarter last year. Shareholder distributions totaled $9.4 billion, including $4.2 billion of dividends and $5.1 billion of share repurchases, consistent with the company’s announced plans. Cash capital expenditures were $8.6 billion in the third quarter, including $2.4 billion in growth acquisitions.  However, higher oil and gas production partly offset the impact of lower oil prices. Third-quarter net production reached 4.8 MMboe/d, up from 4.6 MMboe/d a year ago, underpinned by record production from both the Permian basin and Guyana. In Guyana, Exxon broke records with quarterly production surpassing 700,000 b/d and started up the Yellowtail development 4 months early and under budget. In the Permian, the company also set production record of nearly 1.7 MMboe/d, while continuing to expand the use of proprietary technologies like its lightweight proppant that improves well recoveries by up to 20%. The company acquired more than 80,000 additional net acres in the Permian basin from Sinochem Petroleum in the third quarter. “The transaction provides opportunities to further deploy the company’s innovative technology, leading to greater returns,” said Darren Woods, ExxonMobil chairman and chief executive officer. Meantime, Exxon has now started up eight of its 10 key 2025 projects, with the remaining 2 on track. “No one else in our industry