Energy Secretary Chris Wright said the US is prepared to sell more oil and natural gas to China if Beijing cuts back on purchases from Russia.  “There’s so much space for mutually beneficial deals between the US and China,” Wright said Thursday during a Bloomberg Television interview, noting that the US is the world’s largest oil and gas exporter, while China is the biggest importer.  The energy secretary plans to travel to Asia within weeks, or possibly sooner, following President Donald Trump trip to the continent this week.  During his trip, Trump said he reached deals with Chinese President Xi Jinping and South Korea President Lee Jae Myung to buy more US oil and gas. Trump also cited a “very large scale” transaction involving Alaskan oil and gas in a post on the social media site Truth Social but didn’t provide more details. “There is lots of room from the United States to grow our role in supplying natural gas, oil, and frankly nuclear technology to South Korea,” Wright said in the interview.  WHAT DO YOU THINK? Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

8.4 GW data center pipeline DTE Energy has signed agreements to serve a 1.4 GW hyperscaler and has line of sight to another 7 GW of potential large loads, officials said. $30 billion investment pipeline DTE plans to invest $30 billion in generation, distribution and other infrastructure across the 2026-2030 timeframe. 12 GW New generation DTE expects to add from 2026 to 2032, including batteries, renewables and gas. DTE Energy has signed a 1.4 GW agreement to serve a hyperscale data center and sees “transformational growth” ahead in a project pipeline that could represent up to an additional 7 GW of load. It is the utility’s first hyperscaler agreement at a time when data centers are rapidly expanding around the United States.  Large loads, including AI data centers, could ultimately add 20% to U.S. utilities’ peak demand, most within the next decade, Wood Mackenzie said in a September report. DTE serves about 2.3 million customers in southeast Michigan, including Detroit. “This is an exciting milestone,” DTE President and CEO Joi Harris said in a Thursday call with analysts. “Aside from the 1.4 GW of new load, we are still in late-stage negotiations with an additional 3 GW of data center load providing potential further upside to our capital plan as we advance these negotiations. … And we have a pipeline of an additional 3-4 GW behind that.” The data center contract of 1.4 GW increases DTE’s electric load by 25%, officials said. “We also expect longer-term growth opportunities through the expansion of these initial hyperscaler projects,” Harris said. The generation investment needed to support the additional load “could very well come into the back end of our five-year plan, providing incremental capital investment.” The utility has added about $6 billion to its five-year plan and now expects to invest $30 billion in

$72 billion capital expenditure plan Up 33% from AEP’s previous five-year capex plan, partly driven by 765-kV transmission projects in Texas and the PJM Interconnection region. 65 GW peak load in 2030 Up 76% from AEP’s summer peak, driven by 28 GW in data center and other large load agreements. $2.6 billion year-to-date operating earnings Up 13% from a year ago, partly driven by 765-kV transmission projects in Texas and the PJM Interconnection region. 7% to 9% earnings per share annual growth rate Up from 6% to 8% previously. AEP’s stock price jumped 6% Wednesday to $122.11/share. 3.5% Annual residential rate hikes AEP expects its customers will face over the next five years. Surging loads In the last 12 months, AEP’s utilities sold 6% more electricity compared to the previous year, with residential sales up 2.3% and commercial sales up 7.9%, and those sales are expected to continue growing, according to the company. About 2 GW of data centers came online in the third quarter, Trevor Mihalik, AEP vice president and CFO, said Wednesday during an earnings conference call. AEP expects its peak load will hit 65 GW by 2030, up from 37 GW, with demand surging in Indiana, Ohio, Oklahoma and Texas, according to William Fehrman, AEP chairman, president and CEO. The growth estimate includes 28 GW of customers with electric service agreements or letters of agreement, he said. About half of that 28 GW is in the Electric Reliability Council of Texas market, 40% in the PJM Interconnection and 10% in the Southwest Power Pool, according to Fehrman. About 80% of that pending demand is from hyperscalers such as Google, AWS and Meta, Mihalik said. The remaining demand growth is from industrial customers with projects such as a Nucor steel mill in West Virginia and Cheniere Energy’s liquefied

Melanie Davidson is a hydrogen policy and markets expert. Most recently she led clean fuels strategy at San Diego Gas & Electric. She is former board member of the California Hydrogen Business Council and was a founding staff member of the Green Hydrogen Coalition. Recently, over $2 billion of federal funding for the U.S. Department of Energy California and Pacific Northwest Hydrogen Hubs was terminated. These Hubs were premised on the use of “renewable, electrolytic hydrogen” — meaning hydrogen generated by using renewable electricity to power water-splitting electrolyzers. The resultant hydrogen would have replaced fossil fuels for heavy duty transportation, port operations, and power generation.  The idea of a fully renewable, water-based, hydrogen economy for the West was an exciting one — both in its altruism and the premise, backed by the DOE’s 2021 “Hydrogen Shot.” The idea was for cheap, abundant solar and rapidly declining electrolyzer cost curves to generate hydrogen from water with zero emissions — for $1/kg by 2030, no less.  However, cuts in Hub funding, together with a 2027 sunset date for projects to qualify for the hydrogen production tax credit, are just two more blows to the many pre-existing economic challenges facing a renewable hydrogen future. At least in California, those challenges include rising (not falling) capital costs for electrolyzers and electrical equipment, high interest rates, a scarcity of water rights, and high costs of grid electricity, qualifying renewable energy credits, and land.  The renewable Hubs were anchored on the idea that by leveraging otherwise curtailed solar (terrawatt-hours worth annually), we could generate cheap, abundant, seasonally stored renewable electrolytic hydrogen at distributed locations, then convert the hydrogen back to the grid via fuel cells as needed. It’s an elegant idea, but it doesn’t pencil. The capital costs of those electrolyzers, compressors, liquefiers, hydrogen storage vessels and fuel

In its latest weekly petroleum status report, the U.S. Energy Information Administration (EIA) highlighted that U.S. commercial crude oil inventories, excluding those in the Strategic Petroleum Reserve (SPR), decreased by 6.9 million barrels from the week ending October 17 to the week ending October 24. This EIA report, which was released on October 29 and included data for the week ending October 24, showed that crude oil stocks, not including the SPR, stood at 416.0 million barrels on October 24, 422.8 million barrels on October 17, and 425.5 million barrels on October 25, 2024. The report highlighted that data may not add up to totals due to independent rounding. Crude oil in the SPR stood at 409.1 million barrels on October 24, 408.6 million barrels on October 17, and 385.8 million barrels on October 25, 2024, the report highlighted. Total petroleum stocks – including crude oil, total motor gasoline, fuel ethanol, kerosene type jet fuel, distillate fuel oil, residual fuel oil, propane/propylene, and other oils – stood at 1.677 billion barrels on October 24, the report revealed. Total petroleum stocks were down 15.4 million barrels week on week and up 43.6 million barrels year on year, the report showed. “At 416.0 million barrels, U.S. crude oil inventories are about six percent below the five year average for this time of year,” the EIA said in its latest weekly petroleum status report. “Total motor gasoline inventories decreased by 5.9 million barrels from last week and are about three percent below the five year average for this time of year. Both finished gasoline and blending components inventories decreased last week,” it added. “Distillate fuel inventories decreased by 3.4 million barrels last week and are about eight percent below the five year average for this time of year. Propane/propylene inventories increased by 2.5

Shell Plc beat profit estimates and maintained share buybacks while paying down debt, showing its resilience to weaker oil prices. The third-quarter performance was helped by stronger oil and gas trading, a vital part of the business that struggled earlier in the year amid geopolitical volatility. An expansion in Shell’s liquefied natural gas business after the startup of a new project in Canada also contributed to the positive outlook.  The strength of Shell’s balance sheet — with net-debt falling from the prior quarter — has positioned the company to maintain consistent returns to investors even as oil prices have fallen. Following years of wide fluctuations, the company’s results have reached the point of “boring” consistency for some analysts. Chief Executive Officer Wael Sawan has been on a two-year push to cut costs, improve reliability and offload under-performing assets in an effort to close a valuation gap with the company’s US rivals. Shell’s shares have risen 16% in London since the start of 2025, outperforming its closest peers.  “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 America and Brazil,” Sawan said in a statement on Thursday.  The company maintained its pace of share buybacks at $3.5 billion a quarter. Adjusted third-quarter net income dropped about 10% from a year earlier to $5.43 billion, but was well above the average analyst estimate of $4.74 billion. Net debt declined to $41.2 billion from $43.2 billion at the end of June. Shares of the company were little changed.  After years of outsized profits as demand roared back following the pandemic, the world’s largest energy producers are facing leaner times with crude prices having dropped about 14% this year. Oil market fundamentals point to an oversupply