U.S. commercial crude oil inventories, excluding those in the Strategic Petroleum Reserve (SPR), decreased by 3.3 million barrels from the week ending March 14 to the week ending March 21, the U.S. Energy Information Administration (EIA) highlighted in its latest weekly petroleum status report. This report was published on March 26 and included data for the week ending March 21. The EIA report showed that crude oil stocks, not including the SPR, stood at 433.6 million barrels on March 21, 437.0 million barrels on March 14, and 448.2 million barrels on March 22, 2024. Crude oil in the SPR stood at 396.1 million barrels on March 21, 395.9 million barrels on March 14, and 363.1 million barrels on March 22, 2024, the report outlined. The EIA report highlighted that data may not add up to totals due to independent rounding. 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 1.600 billion barrels on March 21, the report showed. Total petroleum stocks were up 3.5 million barrels week on week and up 19.9 million barrels year on year, the report revealed. “At 433.6 million barrels, U.S. crude oil inventories are about five 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 1.4 million barrels from last week and are two percent above the five year average for this time of year. Finished gasoline inventories increased and blending components inventories decreased last week,” it added. “Distillate fuel inventories decreased by 0.4 million barrels last week and are about seven percent below the five year average for this time of year. Propane/propylene inventories decreased by

Dive Brief: Automation manufacturer Schneider Electric plans to invest $700 million in its U.S. operations through 2027, the company announced Tuesday. The money will go toward facility upgrades, expansions and openings across eight sites in Texas, Tennessee, Ohio, North Carolina, Massachusetts and Missouri. Schneider expects to create more than 1,000 jobs.  The move marks Schneider’s largest-ever investment in the U.S., as the company aims to meet rising demand across its data center, utilities, manufacturing and energy infrastructure segments. Dive Insight: Schneider’s announcement is part of a larger $1 billion investment the company is making in the U.S. this decade.  Artificial intelligence-driven demand for data centers and electrical infrastructure is driving the need for heightened spending on electrical grid-related needs. Data center electricity demand could double by 2030 — consuming up to 9% of the country’s electricity generation, according to a May 2024 study by the Electric Power Research Institute. “We stand at an inflection point for the technology and industrial sectors in the U.S., driven by incredible AI growth and unprecedented energy demand,” Aamir Paul, president of North America Operations for Schneider Electric, said in a statement.  Schneider has been pushing a localization strategy in recent months, with a goal to locally source and produce roughly 90% of sales in each region. That push could help the company weather the Trump administration’s tariffs on Mexico, where Schneider has much of its North American production.  CFO Hilary Maxson said on a recent earnings call that the company is watching for any reciprocal tariffs that may impact their operations. If the United States-Mexico-Canada Agreement remains in place, Maxson said the impact to Schneider would likely be “immaterial.” If the trade deal and free trade zones are repealed, however, the CFO added that the hit to the company could be greater.  “We’re really

With data center electricity demand on the rise across the U.S., utilities should develop specialized tariffs to protect consumers and keep their grids green when these large load customers interconnect, the Southwest Energy Efficiency Project said Thursday in a report. “While AI offers the potential for significant economic and social benefits, there are growing concerns with the rapid increases in electricity demand from data centers and how they will impact the power sector and state and utility climate goals,” SWEEP said. Data centers today account for about 4.5% of U.S. electricity consumption, according to the analysis. But in its most recent report to Congress, the Lawrence Berkeley National Lab projected data centers could account for up to 12% of U.S. electricity use by 2028, SWEEP said. EPRI recently surveyed 25 utilities nationally and found almost half have received requests for new data center facilities with loads larger than 1,000 MW. And “almost half of the utilities surveyed have received data center requests that exceed 50% of their current system peak demand,” SWEEP said. The potential load additions “pose two types of threats to state greenhouse [gas] emission reduction goals,” SWEEP said: Utilities could add or utilize more fossil-fuel based generation, and they could struggle to add sufficient renewables to meet demand from the electrification of vehicles, buildings and industry, the report warned. To address these risks, SWEEP recommends that utilities ensure new data center customers — and other new industrial or commercial customers with demands over 50 MW, or combined demands from several facilities of more than 100 MW — “commit to providing sufficient revenue, over a contract period such as 12 years, to cover the generation and transmission investments made on their behalf.” Utilities should also “propose and attempt to get approval for tariffs that require new large data center customers, and other new

Drax has signed a 20-year joint venture agreement with Power Minerals Ltd (PML) to develop a factory for processing legacy ash into supplementary cementitious material (SCM), or fly ash, an ingredient in low-carbon green cement. The factory will be built next to the Drax power station in Selby, Yorkshire on land leased from Drax. Under the agreement, PML will build, own and operate the new facility, while Drax will sell its legacy pulverised fuel ash (PFA) to the joint venture and provide power to the factory. The factory is due to enter service by the end of 2026, with an initial production capacity of 400,000 tonnes per year. According to the announcement, the facility will ultimately process millions of tonnes of PFA. The move marks the latest shift for Drax, following the power station’s gradual conversion to biomass since the mid-2010s. Drax says it is the single largest generator of renewable electricity in the UK. However, the power station has also been found to be the largest emitter of carbon dioxide (CO2) in the UK by think-tank Ember Energy, based on an analysis of official data from the UK Emissions Trading Scheme registry and company annual reports.  Drax Group has also been fined by UK regulators for misreporting data on the forestry type and sawlog content it uses for its biomass. Nonetheless, Drax is continuing its push to bolster its green credentials. The company is also proposing to add carbon capture and storage (CCS) to the power station site. However, this bioenergy with carbon capture and storage (BECCS) initiative still requires government funding, as well as a confirmed route to carbon storage, in order to go ahead. The announcement on the fly ash partnership represents a further step in Drax’s green push. The company noted in the announcement that cement

Moody’s Ratings on Thursday upgraded credit ratings for PG&E Corp. and its Pacific Gas & Electric subsidiary, saying the companies faced reduced financial risks from wildfires. “PG&E’s upgrade reflects the organization’s continued improvement in mitigating wildfire risk over the last few years as well as its ability to strengthen both its financial profile and its relationships with key stakeholders,” Jeff Cassella, Moody’s Ratings vice president and senior credit officer, said in a press release. The upgrade also reflects the credit quality benefits provided by California’s $21 billion wildfire legislation (AB 1054), including continued access to the state’s wildfire insurance fund and credit positive shareholder liability cap and cost recovery provisions, Cassella said. “In the backdrop of the recent LA wildfires, we expect any legislative and regulatory actions resulting from the state’s continued wildfire risk will remain supportive for utilities by protecting them from uncapped liabilities due to inverse condemnation,” Cassella said. Since PG&E emerged from a wildfire-related bankruptcy in 2020, the utility has spent more than $20 billion to reduce wildfire risks, including the risk its equipment will cause wildfires, according to the credit rating agency. The utility hasn’t experienced any wildfires that significantly affected its finances since 2020, Moody’s noted. Also, PG&E’s financial risks are muted by the utility’s demonstrated ability to receive approvals for the utility’s annual wildfire safety certificate, which allows for the presumption of PG&E’s prudence and protects the company with a liability cap on reimbursement to the wildfire fund if it is found imprudent, Moody’s said. PG&E’s liability cap is about $4.1 billion, according to Moody’s. Although the state’s wildfire fund may be used to cover damages from January fires in southern California, Moody’s said it expects the remaining amount would be enough to support PG&E’s credit ratings and credit quality. “Further upward movement of

Alaska Gasline Development Corp. (AGDC) and Glenfarne Group LLC have signed agreements for the latter to acquire 75 percent of 8 Star Alaska, a company formed by AGDC to manage the planned Alaska LNG. Alaska LNG, approved by the Federal Energy Regulatory Commission May 2020, is designed to deliver natural gas from the state’s North Slope to both domestic and global markets. It is the only federally permitted liquefied natural gas (LNG) project on the United States Pacific Coast, according to AGDC. “Glenfarne assumes the role of Alaska LNG’s lead developer and will lead all remaining development work of Alaska LNG from front-end engineering and design through to a final investment decision (‘FID’)”, AGDC said in an online statement. The company said FID is planned for this year. “AGDC remains a 25 percent owner of 8 Star Alaska and a key partner to Glenfarne on the project”, AGDC added. Alaska LNG has three subprojects: an LNG export terminal with a capacity of 20 million metric tons per annum (MMtpa) in Nikiski, an 807-mile 42-inch pipeline and a carbon capture plant with a storage capacity of 7 MMtpa. “In light of steadily declining gas production from Cook Inlet, which has historically been Alaska’s primary in-state natural gas basin, phase one of the project will kick off immediately, prioritizing the development and final investment decision of the pipeline infrastructure needed to deliver North Slope gas to Alaskans as rapidly as possible”, AGDC said. The LNG plant will be built at a later phase, AGDC said previously. “Oil was discovered in Prudhoe Bay almost exactly 57 years ago and since then Alaskans have never given up on finding a way to also benefit from our North Slope natural gas”, commented Governor Mike Dunlea. “Alaska has made a significant investment to develop Alaska LNG