Japan's KHI starts building hydrogen liquefaction plant

Spanish Market: Hydrogen
19/10/26

Japan's Kawasaki Heavy Industries (KHI) started construction of a hydrogen liquefaction facility with a capacity of 50 t/d at the Kawasaki LH2 terminal in Ogishima, Kawasaki, Kanagawa prefecture, the company said today.

The initiative forms part of the demonstration phase of the development of a liquid hydrogen supply chain. The project forms part of Nedo's Green Innovation Fund programme for the development of a large-scale hydrogen supply chain.

The plant is scheduled for completion by the end of 2028 and is intended for commercial scale demonstration from 2030.

The facility will be located within the Kawasaki LH2 terminal being developed by Japan Hydrogen Energy. Its core equipment — a hydrogen liquefier, or cold box — will cool hydrogen to –253°C to convert it into liquid form. The project aims to demonstrate technologies needed for a commercial scale liquefied hydrogen supply chain.

The facility's capacity of 50 t/d is more than three times larger than Japan's biggest publicly announced plant of 15 t/d and is expected to achieve world class liquefaction efficiency compared with facilities of similar size, the firm said.

The facility's capacity is also considered "large by global standards", a company spokesperson told Argus.

Nedo's Green Innovation Fund project seeks to establish a large scale hydrogen supply chain through developing hydrogen carriers, receiving terminals and other infrastructure, while creating demand via hydrogen fired power generation demonstrations.

The initiative targets hydrogen supply costs of ¥30/Nm³ ($0.19/Nm³) by 2030 and below ¥20/Nm³ by 2050 — levels intended to compete with fossil fuels.

The new facility is expected to boost efficiency and cut costs across the liquefied hydrogen chain, the company said. The company is considering further scale-ups of liquefaction facilities in response to future demand growth and is also targeting opportunities in major hydrogen supply regions such as Australia and the Middle East, a company spokesperson told Argus.

By Fumito Nagase

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16/10/26

Germany's Merz says France deal ends EU ICE phase-out

Brussels, 16 October (Argus) — The EU's planned phase-out of new internal combustion engine (ICE) vehicles by 2035 is "history", German chancellor Friedrich Merz said today, citing a new Franco-German agreement on future CO2 standards for cars. A draft text of the German-French proposals circulating would retain the EU's 2035 target of a 90pc reduction in CO2 emissions without offsetting, while allowing greater use of renewable fuels. The text indicates support for a new category of zero-emission vehicles powered by renewable fuels of non-biological origin (RFNBOs), sustainable EU-produced biofuels and biogas from advanced feedstocks, waste and residues listed in Parts A and B of Annex IX. "We would also enable the use of biofuels as a means of achieving carbon neutrality," Merz said, arguing that technological neutrality is needed to achieve net-zero CO2 emissions. Merz said the agreement has backing from other member states, but needs to pass the EU legislative process. The proposal was criticised by German Green MEP Michael Bloss, the group's negotiator on car CO2 standards. "Just when many people want to buy an electric car, a further weakening of EU rules creates uncertainty and hesitation," Bloss said. "China has already gone electric, and that is precisely where European manufacturers are losing substantial market share." German EPP MEP Peter Liese welcomed the proposal, saying scrapping the ban on ICE cars can be done "without missing our climate targets." Use of "climate-friendly" fuels such as E20 should be expanded, he said. Liese backed the creation of a dedicated vehicle category for climate-friendly fuels, including e-fuels. He said there is broad support in the European Parliament for the European Commission's proposal to allow 7pc green steel to count towards compliance targets. Industry group European Biodiesel Board (EBB) welcomed the agreement but wants clarity on fuels eligibility. "Leaving out any RED-compliant feedstocks would hamper solutions that are already contributing to decarbonisation," said EBB secretary general Xavier Noyon. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Co-processing SAF faces technical, cost, policy hurdles

16/10/26

Co-processing SAF faces technical, cost, policy hurdles

London, 16 October (Argus) — Co-processing bio feedstocks in conventional oil refineries to make sustainable aviation fuel (SAF) has reached commercial scale, but further growth will be challenging and costly, attendees heard at the IATA World Sustainability Symposium in Brussels this week. Around one third of Europe's oil refineries co-process feedstocks like used cooking oil (UCO) alongside crude to make a fraction of sustainable fuels for European mandates, FuelsEurope fuels executive Sebastian Hirsz said. This reflects modest early SAF demand, and rising mandates strengthen the case for investing in more capacity, he said. Co-processing ratios are capped by fuel standards such as ASTM, but pending more testing these limits could be eased over time, he said. Fragmented policy on feedstocks is a barrier because EU member states have written different co-processing rules into national law, so a feedstock allowed in one country may be blocked elsewhere, Hirsz said. The rules need "tidying up" to unlock further investment, he said. Co-processing also faces technical challenges, said Spanish refiner Moeve's senior vice president for strategy and international growth Rik Sneep. Refineries can typically cope with 5-10pc bio feedstock without problems, but blending higher ratios adds acidity that requires upgrades to the hydrocracker or metallurgy adjustments, he said. The business case varies by refinery. Upgrading older or challenging brownfield sites can see costs spiral to "two, three, or four hundred million," Sneep said. Some refineries will be "really well placed to make upgrades at relatively low cost," but for others it may be more economical to build greenfield biorefineries, he said. Refining bio feedstocks introduce more oxygen in the system and need significantly more hydrogen, which adds costs, Sneep said. Feedstocks like used cooking oil (UCO) are collected from diverse suppliers, meaning they are inherently inconsistent and challenging to work with, he said. Refineries may employ other techniques to trim lifecycle emissions of their fuels, such as co-processing a share of synthetic e-crude made with renewable hydrogen and captured CO2, said FuelsEurope's Hirsz. Using renewable hydrogen in refineries and biorefineries is also a major lever to trim the lifecycle emissions of SAF, he said. This could apply to co-processed SAF or neat biofuel SAF. The EU's SAF mandate works on a volume basis and does little to encourage SAF producers to cut emissions beyond meeting the minimum eligibility. Companies disagree about how best to incentivise renewable hydrogen in SAF. One option is categorising SAF made with renewable hydrogen as synthetic SAF (e-SAF). Refiners have urged the EU to allow this, but pure-play e-SAF companies say it would undermine their projects. The European Commission is analysing this 'e-HEFA route' but has reached no decision, said EU mobility and transport department head of aviation policy Eddy Liegeois. Such a policy would grow the hydrogen industry and help scale e-SAF, and help lower biofuels lifecycle emissions, but commission is wary of jeopardising "genuine" e-SAF projects, he said. By Aidan Lea Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

India seeks to address hydrogen standards gaps

14/10/26

India seeks to address hydrogen standards gaps

New Delhi, 14 October (Argus) — India has identified significant standards and safety gaps across parts of its hydrogen value chain as projects move closer to deployment, highlighting unresolved questions around transport, storage and end-use applications even as certification frameworks and project plans continue to develop. The India's Hydrogen Standards: Gap Assessment and Preliminary Action Framework report released last week by the ministry of new and renewable energy (MNRE) assessed 50 hydrogen sub-components across production, storage, transportation and end-use applications. It found that 12 sub-components were adequately covered by existing standards, while 15 had partial gaps and 23 lacked standards altogether. The assessment identified some of the largest gaps in hydrogen transmission pipelines, repurposed natural gas pipelines, underground storage, tube trailers and plant piping systems. It also found incomplete standards coverage in end-use applications expected to play a role in future hydrogen demand, including shipping, aviation, railways, stationary fuel cells and off-road mobility. The findings come as India's hydrogen industry begins moving beyond policy development and towards project execution . Developers including AM Green and Acme have secured export-linked renewable ammonia offtake agreements , while domestic demand programmes for fertilizer producers and refiners continue to advance. India has also introduced a national green hydrogen definition, emissions standards for hydrogen derivatives and a certification scheme . But the assessment found that standards coverage in transport, storage and several end-use applications is much more limited. India has developed more than 90 hydrogen-related standards, including more than 34 led by MNRE, according to the report. It recommends adopting international standards in areas where no established framework exists. The report also highlights international harmonisation as an important consideration for future trade in hydrogen, ammonia and related equipment. Further development Hydrogen transport infrastructure and related technical standards were frequently discussed during MNRE's recent World Hydrogen Day event in early October. India's downstream regulator Petroleum and Natural Gas Regulatory Board secretary Anjan Kumar Mishra said hydrogen blending pilots in city gas distribution networks had produced encouraging results, with no abnormal degradation observed in pipelines, valves and associated equipment at low blending levels. Four pilot projects have concluded and one remains under evaluation. Additional testing would be required before higher hydrogen blend ratios or high-pressure transmission applications could be considered, Mishra said. Dedicated hydrogen test facilities are being developed to generate data needed for future regulations governing hydrogen transport and pipeline repurposing, he added. The Bureau of Indian Standards (BIS) has adopted or developed around 61 hydrogen standards and is working on seven more, according to BIS mechanical engineering department head Srikumar Animesh. BIS generally adopts international standards where possible but modifies requirements where domestic operating conditions or regulations differ, he said. Testing and certification infrastructure emerged as another recurring theme. Risk management firm Apave's country manager for India, Nilay Ball, said India requires additional hydrogen-specific testing capability for components and systems including valves, regulators, electrolysers and fuel-cell assemblies. Developers require greater certainty around testing and certification pathways as projects move towards deployment, he added. Safety specialists also highlighted areas under development. Chitra Rajagopal, fellow at the office of the government's principal scientific adviser, said hydrogen applications outside traditional industrial facilities would require site-specific risk assessments and additional safeguards. Participants also discussed the possible creation of a hydrogen incident and near-miss reporting framework to support future standards development and operational learning. By Anmol Choubey Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Australia expands PGO scheme to biomethane

12/10/26

Australia expands PGO scheme to biomethane

Sydney, 12 October (Argus) — Australia's Clean Energy Regulator (CER) has opened applications for biogas and biomethane projects to participate in the Product Guarantee of Origin (PGO) scheme, broadening the certification framework beyond hydrogen and creating a pathway for renewable gas producers to verify the emissions credentials of their products. The regulator today updated and published participation guidance allowing companies to apply to the PGO scheme if they produce, distribute or consume biogas produced through anaerobic digestion and biomethane produced through biogas upgrading. The update also extends participation to hydrogen produced through gas reforming, hydrogen produced using solid gasification or pyrolysis, iron ore and aluminium. The PGO scheme, a voluntary framework to track emissions, was launched in November 2025 . The latest expansion follows a December 2025 consultation on expanding the hydrogen pathway and adding new products. The PGO scheme forms part of the federal government's broader Guarantee of Origin framework established under the Future Made in Australia (Guarantee of Origin) Act 2024. The expansion builds on the scheme's existing coverage of hydrogen produced through electrolysis and is intended to provide independently verified information on the emissions intensity and origin of eligible products. Under the scheme, participants must register with the CER before establishing production, delivery or consumption profiles that allow them to create and manage PGO certificates. Participants are required to provide auditable data on emissions, energy use and production volumes throughout a product's lifecycle. Biomethane facilities in Australia are already eligible to generate renewable gas guarantee of origin (RGGO) certificates under GreenPower's Renewable Gas Certification scheme, linked to their renewable gas production, with the first ever reported trade disclosed in August 2026 . By Lawrence Wen Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Amogy, GS E&C venture secures NH3 for S Korean power

08/10/26

Amogy, GS E&C venture secures NH3 for S Korean power

London, 8 October (Argus) — US technology firm Amogy and South Korea's GS Engineering and Construction (GS E&C) have agreed to buy 1,500t of renewable ammonia from Lotte Fine Chemical (LFC) for a planned 1MW power plant in Pohang, South Korea. The firms signed the deal through their Amun Energy joint venture, following an initial agreement last month. LFC will supply the ammonia over one year from 2027. The plant will sell power directly to businesses in the surrounding industrial complex. The 1,500t contain about 7,750MWh of energy on a lower heating value basis. At an electrical efficiency of 30-45pc, covering ammonia cracking combined with hydrogen engines or fuel cells, it could generate 2,300-3,500MWh, based on Argus calculations. This equates to a capacity factor of 27-40pc for a 1MW unit. Operating at full load throughout the year would require about 3,800-5,700t of ammonia. The firms have pitched the technology as a source of "round-the-clock power" for industrial sites and data centres, but the contracted volume suggests a gradual ramp-up. The partners plan to expand capacity to 10MW in 2028, with a longer-term target of up to 40MW. Scaling up the first year's contracted supply would imply ammonia demand of 15,000 t/yr and 60,000 t/yr, respectively. At full load, the 10MW plant would require about 38,000-57,000 t/yr, while the 40MW plant would need around 151,000-226,000 t/yr (see table) . A 40MW plant would generate 93-140 GWh/yr at the 1MW unit's implied utilisation, or about 350 GWh/yr at full load. Seoul plans to procure 500 GWh/yr for 2029-44 in its next clean hydrogen power tender. Dedicated ammonia-to-power plants remain eligible after the government ended support for coal-ammonia co-firing in August. LFC received the first export cargo from Envision Energy's renewable ammonia plant in Chifeng, China, earlier this year and is expanding ammonia storage at Ulsan. By Chingis Idrissov Potential ammonia demand and power output for Amun Energy's plants Capacity (MW) Ammonia demand based on first year (t/yr) Ammonia demand at full load (t/yr) Power at first year load (GWh/yr) Power at full load (GWh/yr) 1 1,500 3,800-5,700 2.3-3.5 9 10 15,000 38,000-57,000 23-35 88 40 60,000 151,000-226,000 93-140 350 Calculations assume 18.6 GJ/t ammonia lower heating value, 30-45pc electrical efficiency Argus calculations Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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