US seeks to allow carbon storage on federal land

Market: Biofuels, Coal, Crude oil, Electricity, Emissions, Hydrogen, Natural gas, Oil products
03/11/23

President Joe Biden's administration is advancing a proposal to allow carbon capture and storage (CCS) on millions of acres of federal land owned by the US Forest Service.

The proposed rule, published Friday, would open up the possibility of siting carbon storage projects on the 193mn acres of federal land in 44 states managed by the Forest Service. The regulation could support the Biden administration's push to expand the use of CCS, a technology that captures CO2 and then stores it deep underground in subsurface geological formations.

The proposal would remove an existing restriction from the Forest Service that blocks projects from having "exclusive and perpetual use" of federal land. Because CCS projects store CO2 for thousands of years, the agency said the restriction needs to be removed for projects to advance. Projects would still be subject to other permitting requirements and environmental reviews.

The US has seen a surge of interest in CCS as developers try to take advantage of $12bn in new funding from the 2021 infrastructure law and the expansion of the "45Q" tax credit that pays up to $85/metric tonne of CO2 that is stored in geologic formations. The Inflation Reduction Act also offers tax credits for clean hydrogen and low-carbon renewables fuels that are likely to rely partially on CCS.

But project developers have run into obstacles as they seek regulatory approvals for CO2 pipelines and Class VI injection wells needed for CCS. US Senate Energy and Natural Resources Committee chairman Joe Manchin (D-West Virginia) on Thursday criticized the US Environmental Protection Agency for not yet approving permits for a backlog of 169 carbon injection wells, while at the same time proposing to mandate CCS for fossil fuel power plants.

"Not a single Class VI well has been approved," Manchin said. "At the same time, the administration is more than happy to mandate widespread deployment of carbon capture on gas- and coal-fired power plants."

By Chris Knight

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21/03/25

US hydrogen hype gives way to more practical prospects

Developers have reined in expectations, seeking faster commerciality for more specific applications, writes Jasmina Kelemen Houston, 21 March (Argus) — Hydrogen's one-time promise as a wonder fuel has been replaced in 2025 with a more practical understanding of its limitations, a momentum shift welcomed by industry proponents who gathered in Houston, Texas, last week at the CERAWeek by S&P Global energy conference. It has been a roller-coaster ride for the sector since the administration of President Joe Biden zeroed in on hydrogen as a means of reducing emissions and creating jobs, unveiling generous tax incentives in 2022's Inflation Reduction Act (IRA). A frenzy of project proposals soon followed. That excitement dissolved into a frustrating wait as the administration embarked on a years-long review process that only concluded in January with the release of finalised rules for the 45V production tax credits, leading some to conclude the hydrogen dream had crashed before take-off. The reality is more nuanced. "The death of hydrogen has been greatly exaggerated," Chevron's vice-president of hydrogen, Austin Knight, said at CERAWeek. "There are real projects actually happening," he said, pointing to the company's ACES Delta joint venture with Mitsubishi Power. The Utah project is forecast to initially convert 220MW of renewable power into 100 t/d of hydrogen, and will begin operations this year. Whittling the sector down to its most realistic prospects is a welcome departure from previous years, when hydrogen was viewed as the "Swiss army knife" of fuels — a tool that could be used to solve almost any problem — Oleksiy Tatarenko, senior principal at Rocky Mountain Institute, said. It is now being viewed as a more precise approach for specific applications in ‘hard-to-abate' industries such as steel and chemicals, he said. BP still sees hydrogen as an important component to decarbonising refineries, but its deployment timeline will be longer than expected, BP's senior vice-president of refining, terminals and pipelines, Amber Russell, said. BP has scaled back hydrogen plans, shelving 18 projects since October. Of those remaining, two include refineries in countries with fiscal incentives for hydrogen production, and near other industries looking to cut emissions. BP's 440,000 b/d Whiting refinery in Indiana could have similar potential, Russell said, but "45V ...and the IRA are incredibly important to helping us understand when that happens". One among many Hydrogen's shifting position in the clean energy landscape could even be seen in the CERAWeek conference's floor plan this year. In a space for showcasing new technologies and ideas, the Hydrogen Hub of previous years had disappeared, replaced by a New Energies Hub, under which hydrogen was just one of multiple clean-energy solutions on display, along with biofuels, nuclear power and other renewables. "That is a positive thing for this space writ large," GTI Energy's Open Hydrogen Initiative executive director, Zane McDonald, said. "We are starting to get very practical," he said. "We want to focus on projects that are going to make money, that have an offtaker and can materialise in the next two years." Among the projects expected to take off most rapidly are those that can tap into demand for lower-carbon fuels in Europe and Asia or more modestly sized US producers located near specialty industries that are looking to curb emissions. "The quality of the projects we're seeing in our pipeline is better," said Black & Veatch hydrogen and ammonia director Bryan Mandelbaum, who sees a growing niche for 10-200MW projects targeting heavy industries such as chemical processors. He contrasted this favourably with a flurry of clients that appeared after the 45V tax was first announced. "It was good for business in the short term, but at the same time you knew 80pc of those were never going to develop." Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Low snowpack, rain may lift Italian summer power prices

21/03/25

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21/03/25

Low snowpack, rain may lift Italian summer power prices

London, 21 March (Argus) — Low snowpack and hydro reserves in Italy may increase the call on gas-fired power plants this summer, likely supporting power prices in days when renewable generation is weakest. Hydro generation from run-of-river installations, pumped-storage plants and hydroelectric reserves accounted for almost 20pc of the power mix on average over 2020-24 in the third quarter — the second-highest share after the second quarter at 22.2pc — compared with gas-fired generation covering 45pc. But prevailing conditions suggest that without unusually wet weather this summer, Italian rivers could be drier than normal, limiting scope for hydro output and potentially opening more space for gas in the power mix, driving up electricity prices. Snow water equivalent — or the estimated water content of snow — moved back to a deficit to last year's levels on 23 February after showing signs of improvement over the first three weeks of the month, according to Italian meteorological association Cima. Snowpack was at a deficit of 57pc to the 2011-23 average as of 8 March, narrowing slightly compared with a 58pc deficit around the same time in February. The deficit in the Po basin, which accounts for almost half of Italy's snow water resource, is currently at a 44pc deficit to the seasonal norm, Cima data show. In the Apennines, the Tiber basin is at a 95pc deficit to the long-term average, marking the worst balance of the last 13 years. And hydro reserves have been at a consistent deficit to last year since January and moved to a deficit to the five-year norm in the middle of February. Rainfall in Malpensa and Paganella, in the north of the country, was at an average deficit of almost 2 mm/d and 1.6 mm/d, respectively, to the seasonal norm over November and December last year. While precipitation picked up in January and moved to a surplus to the norm of 1.9 mm/d in Malpensa and 1.4 mm/d in Paganella, minimum temperatures were 1.6°C above the long-term average in Milan, reducing snow accumulation. The latest data show that hydro reserves have picked up for the first time this year in week 11, reaching 2.1TWh and narrowing their deficit to the 2020-24 average to 0.8pc compared with 5.2pc a week earlier. Still, they remain 6.6pc below last year, with the deficit standing even wider at 9.1pc, when compared with the 2015-24 average. Looking ahead, forecasts indicate that minimum temperatures in Milan will hold around 2°C above the 10-year norm until the end of April, possibly leading some snowmelt to support run-of-river generation early in the second quarter, when power demand is typically at its lowest. But this would also leave less snow to melt later in the summer, when cooling demand peaks and drives up overall demand for electricity. While solar capacity increased steadily by over 500MW a month last year, the share of the power mix covered by solar output in the third quarter of 2024 remained almost unchanged from the same period in 2023. Assuming a similar monthly growth in photovoltaic (PV) capacity this year, the solar load factor is expected to increase by 1.8 percentage points to 17.8pc in the third quarter of 2025 on the year. This means that even if solar capacity and output continue growing, it may not be enough to offset a lack of hydro generation in the third quarter of this year, and thermal generation may still need to cover a significant amount of residual demand. The third quarter of 2025 has averaged €135.85/MWh ($146.83/MWh) so far this quarter, well above an average €91.60/MWh seen over the same period last year. Clean spark spreads for 55pc-efficient gas-fired units for the third quarter of 2025 have averaged around €19.60/MWh since the start of the year, compared with an average of €15.50/MWh over the same time last year. As solar and wind capacity is set to increase over the coming years to reach a national target of 110GW by 2030, renewable output will cover an increasing share of Italian electricity demand — estimated to reach 335TWh in 2028. Thermal plants may become less economically viable and will likely be decommissioned unless they are kept operating through ancillary services. But turning on gas-fired plants from cold and with a stop-start operation would lead to exaggerated costs and higher maintenance prices, Argus heard on the sidelines of the KEY25 Energy Transition Expo in Rimini earlier this month. This could lead to electricity prices spiking in periods of scarce hydro availability, as hydro-run-of river is Italy's largest single source of renewable generation, accounting for 17pc of the power mix last year compared with less than 5pc of hydro-pumped storage and reservoirs. By Ilenia Reale Italian hydro stocks TWh Gas and hydro output, hydro reserves GW, TWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Shell ends direct bitumen sales to some German buyers

21/03/25

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21/03/25

Shell ends direct bitumen sales to some German buyers

London, 21 March (Argus) — Shell will stop directly supplying bitumen to some of its low-volume customers in Germany, with effect from 1 April. Shell told customers it has restructured its bitumen distribution channels and can no longer directly distribute to certain customers, according to an email from Shell's bitumen supply unit in Germany seen by Argus . It recommended they instead buy from German bitumen trading and supply firm Bitumina Handel. Neither Shell Germany nor Bitumina Handel have commented, but Argus understands the oil major, which is one of Europe's leading refinery bitumen producers, has concluded a deal with Bitumina to take over supply to its affected customers. The move is part of a wider switch by Shell to focus more on trading bitumen cargoes and less on directly supplying truck volumes to inland customers. The company ended a long-term throughput and supply arrangement into the French market through the Nantes and Bayonne terminals on the French Atlantic coast. Spain's Repsol and Moeve have taken over those operations . Shell last year ceased its South African bitumen retail and truck supply operations . Shell's European bitumen production is at its 187,000 b/d Godorf refinery in western Germany and at its 447,000 b/d Pernis refinery in Rotterdam. The firm recently stopped processing crude at the 147,000 b/d Wesseling section of its 334,000 b/d Rhineland refinery complex. The effect of that on bitumen production at Godorf, the other section of Rhineland, is unclear. By Fenella Rhodes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Australia's Simcoa may buy carbon credits until 2028

21/03/25

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21/03/25

Australia's Simcoa may buy carbon credits until 2028

Sydney, 21 March (Argus) — Australia's silicon producer Simcoa will likely need to buy and surrender Australian Carbon Credit Units (ACCUs) until 2028 for safeguard mechanism compliance obligations before it completes a key decarbonisation project, it told Argus today. The project was awarded federal funds on 20 March. Australia's federal Labor government granted Simcoa A$39.8mn ($25mn) under its Powering the Regions Fund (PRF) to expand charcoal production at its Wellesley facility in Western Australia (WA) and remove the use of coal in silicon production. The project is expected to reduce the company's scope 1 emissions by around 90pc, or approximately 100,000 t/yr of CO2 equivalent (CO2e). Simcoa is Australia's only silicon manufacturer, which is a key component of solar panels. The funding will help maintain silicon manufacturing capability in the country in addition to cutting emissions, energy minister Chris Bowen said. The company currently uses 35,000 t/yr of metallurgical low ash coal in its operations, and anticipates usage will drop to zero after it doubles its charcoal production capacity by 25,000 t/yr to 50,000 t/yr. The completion date for the expansion is not expected before 2028. The firm may continue to buy [ACCUs] as it must use coal as a reducing agent for part of its production for calendar years 2025-27, or until the expansion project can be commissioned, the company told Argus on 21 March. Simcoa surrendered 22,178 ACCUs in the July 2022-June 2023 compliance year as it reported scope 1 emissions of 122,178t of CO2e with a baseline of 100,000t CO2e at its Kemerton silicon smelter. Figures were lower for the July 2023-June 2024 compliance period, the company said, without disclosing details. Australia's Clean Energy Regulator (CER) will publish 2023-24 safeguard data by 15 April . Simcoa anticipates scope 1 emissions at the Kemerton smelter to be "considerably below" the baseline once the charcoal expansion is completed and could make it eligible to earn and sell safeguard mechanism credits (SMCs), which traded for the first time in late February . "We will take whatever opportunity is available to us," the company said on potentially holding or selling SMCs in future. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Opec+ overproducers outline new compensation plans

21/03/25

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21/03/25

Opec+ overproducers outline new compensation plans

London, 21 March (Argus) — Seven Opec+ members have submitted plans to the Opec secretariat detailing how they intend to compensate for producing above their crude production targets since January 2024. The plans show that Iraq, Kazakhstan, Russia, the UAE, Kuwait, Oman and Saudi Arabia will reduce their combined output by an average of 263,000 b/d over the 15 months to June next year (see table) . This is to compensate for exceeding their production targets by a cumulative 4.203mn b/d between January 2024 and February 2025. This figure does not represent a monthly average, but rather the sum of the monthly volumes by which the group's overproducers have surpassed their respective output ceilings. It works out to an average monthly overproduction of 300,000 b/d in the same period. If implemented fully, these compensation related cuts would partly offset a plan by these seven members plus Algeria to return 2.2mn b/d of voluntary production cuts starting in April over 18 months. In fact, the scheduled output increases for April and May would be entirely wiped out. But there is no guarantee the compensation related cuts will be delivered. Some members, Iraq and Kazakhstan in particular, have largely failed to deliver on past commitments to reduce output to below their production targets. By Aydin Calik Opec+ overproduction compensation plan* Iraq Kuwait Saudi Arabia UAE Kazakhstan Oman Russia Total Mar-25 116 15 38 5 25 199 Apr-25 116 8 9 5 53 7 51 249 May-25 135 15 6 10 57 10 76 309 Jun-25 130 23 10 72 12 102 349 Jul-25 120 30 10 66 14 127 367 Aug-25 115 38 10 81 18 152 414 Sep-25 120 27 10 85 20 173 435 Oct-25 120 10 90 13 233 Nov-25 120 20 84 224 Dec-25 120 20 49 189 Jan-26 123 33 39 195 Feb-26 123 33 38 194 Mar-26 123 33 40 196 Apr-26 123 50 38 211 May-26 125 55 42 222 Jun-26 125 56 36 217 Average reduction 262.7 *the amount by which members pledge to produce below their existing targets each month Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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