INPEX CORPORATION has opened the INPEX hydrogen park in Kashiwazaki City, Niigata Prefecture, moving its blue hydrogen and ammonia demonstration effort into full operation. The site brings together several existing elements, the blue hydrogen and ammonia plant, the Kashiwazaki Hydrogen Power Plant, and the Hirai Gas Collection Station, into one coordinated facility. INPEX developed the complex to run its broad demonstration program covering hydrogen and ammonia production and their eventual use.

The INPEX hydrogen park also reflects the company’s long-running commitment to Niigata Prefecture through a “local production for local consumption” model. Natural gas from the Minami-Nagaoka Gas Field serves as the main feedstock, and CO₂ created during hydrogen and ammonia production will be directed into the reservoir beneath the Hirai area of the Higashi-Kashiwazaki Gas Field, where gas extraction has already ended. The hydrogen produced through this project will supply electricity generation at the Kashiwazaki Hydrogen Power Plant and be delivered through the grid to users in Niigata Prefecture. A portion of that hydrogen will be synthesized into ammonia for customers located in the same region.

INPEX said the purpose of the INPEX hydrogen park is to strengthen its experience across the full hydrogen and ammonia value chain and build a record of operational know-how that can support its role in these sectors both domestically and internationally. Parts of the hydrogen and ammonia production system, including CO₂ capture, are backed by the New Energy and Industrial Technology Development Organization under its “Fuel Ammonia Utilization and Production Technology’’ program. Work on subsurface CO₂ storage is being advanced with the Japan Organization for Metals and Energy Security through joint research on depleted oil and gas fields in Japan.

The initiative forms a core component of INPEX Vision 2035, released in February 2025, which sets out the company’s plans for a responsible energy transition and names CCS and hydrogen as key growth areas. INPEX noted that commissioning and the introduction of natural gas represent a major step in the project’s rollout. Running from the second half of fiscal 2022 through the end of fiscal 2025, with room for extension, the project includes blue hydrogen and clean electricity production, low-temperature and low-pressure ammonia synthesis, studies on CO₂ storage potential, enhanced gas recovery assessments, and monitoring designed to verify safe CO₂ injection.

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Air Products and Chemicals, Inc. and Plug Power, Inc. will take on major supply roles under the new NASA hydrogen contracts, as the agency locks in long-term access to nearly 37 million pounds of liquid hydrogen. NASA has finalized firm-fixed-price agreements that run from December 1, 2025, through November 2030, a schedule designed to protect the fuel needs of its rocket programs and aeronautics research. In total, the commitments cover 36,952,000 pounds of liquid hydrogen at an estimated value of about $147.2 million.

Air Products is positioned to deliver the overwhelming share of that volume. Its contract allows for as much as 36.5 million pounds of liquid hydrogen to be sent to Kennedy Space Center and Cape Canaveral Space Force Station in Florida, as well as Marshall Space Flight Center in Alabama and Stennis Space Center in Mississippi. Plug Power’s contribution, capped at up to 480,000 pounds, is earmarked for Glenn Research Center and the Neil A. Armstrong Test Facility in Ohio, at a price point of roughly $2.8 million. Together, these allocations represent the backbone of the NASA hydrogen contracts and ensure uninterrupted access to a critical cryogenic propellant.

NASA highlighted the value of the multi-year, fixed-price setup, noting how it stabilizes planning for engine testing and flight development tied to future lunar and Martian missions. The distribution between two suppliers also adds a degree of resilience to the agency’s hydrogen procurement chain. Air Products extends a relationship with NASA that reaches back to the Apollo era, while Plug Power increases its presence in aerospace fueling following its recent activity in green hydrogen production.

Liquid hydrogen has supported NASA missions for more than six decades, and the latest contracts maintain that legacy through 2030. The agency expects the secured volume to keep propulsion tests, launch operations, and aeronautics experimentation on schedule. Maintaining purity standards, managing cryogenic logistics, and scaling production will remain central challenges as NASA advances its next wave of exploration and relies on producers tied to the NASA hydrogen contracts to keep operations moving.

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The Qilu Liquid Hydrogen Project has moved into mass production, now turning out 10 tons of liquid hydrogen each day with equipment and engineering support supplied by GUOFUHEE. It marks a key moment for the Qilu Liquid Hydrogen Project, which is noted as China’s first 10-ton-class liquid hydrogen facility built entirely with domestically developed intellectual property. GUOFUHEE says the achievement reflects years of continuous technical refinement and engineering work, forming the base upon which larger-scale liquid hydrogen development in China can grow and adding momentum to the wider hydrogen energy sector.

Project records show that GUOFUHEE advanced the effort through a series of stages. In May 2023, the company completed its core equipment package after working through several challenges specific to liquid hydrogen production. By May 2024, the systems had been delivered and installed at the Qilu Hydrogen Energy base in Zibo, Shandong, where the full operating sequence was commissioned. A panel of domestic liquid hydrogen specialists reviewed the setup and gave it the go-ahead. Once the team wrapped another cycle of optimization and steady-state testing, the project shifted into steady mass production, holding to its early pledge to deliver engineered capability and industrial output on time.

Performance indicators from the Qilu Liquid Hydrogen Project provide a snapshot of how the facility is performing at scale. The comprehensive energy consumption for liquefaction is reported at under 12 kW•h/kg-LH₂. Para-hydrogen content in the product exceeds 98.5%, and the purity reaches above 7N—figures that meet or surpass recognized international thresholds. These results support lower production costs and match the needs of downstream users, including fuel cell vehicle suppliers and semiconductor-grade gas applications. The plant’s operation is built around GUOFUHEE’s multi-stage pre-cooling hydrogen expansion refrigeration technology, and both the 20K hydrogen liquefaction cold box and the hydrogen expander carry independent intellectual property rights.

GUOFUHEE notes that the equipment design, with its compact form, stable operation, and heat-exchange performance, suits larger deployment scenarios. The mass production level reached at the Qilu Liquid Hydrogen Project is seen as an early marker for the hundred-ton-class liquid hydrogen projects expected to follow. It also aligns with China’s “West Hydrogen East Transmission” strategy, supporting long-distance movement of hydrogen and offering a model for peak-shaving and storage within pipeline networks. As liquid hydrogen moves deeper into applications tied to new energy, aerospace, advanced materials, and the low-altitude economy, the project is positioned to feed into wider industrial development and a new wave of emerging growth areas.

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China has taken a major step toward greening one of its heaviest industrial emitters, as Datang Group begins commercial operations at the country’s first coal-to-chemicals complex to integrate green hydrogen. The landmark site in Duolun, Inner Mongolia, marks a pivotal moment in China’s emerging coal-to-hydrogen shift. The facility has long been part of China’s coal conversion landscape, and the new green hydrogen system is now being folded directly into its existing production processes.

Chinese regulators have formally designated the project as a National Hydrogen Demonstration Project, underscoring its strategic importance. CCTV said the site “provides a replicable model for the green transformation of the coal-to-chemicals industry,” reflecting the government’s expectation that this large-scale trial can guide similar upgrades across the sector. The broader coal chemical industry remains central to China’s domestic supply of chemicals, oil, and gas, helping reduce import dependence. But its rapid expansion has also been identified as a major obstacle to achieving the country’s 2025 carbon intensity reduction targets, making this early coal-to-hydrogen shift a critical testing ground for emissions mitigation.

The project is operated by state-owned Datang Group. Station manager Cao Guoan told CCTV that the plant is forecast to produce 70.59 million cubic meters of hydrogen annually, although current output levels were not disclosed. The facility continues to rely on coal gasification to produce syngas, a mix of carbon monoxide and hydrogen used to make ammonia, methanol, and olefins, but the new element is the integration of green hydrogen to reduce the carbon footprint of these outputs.

A dedicated 150-megawatt wind and solar farm powers the hydrogen system and sends surplus electricity to the national grid. This renewable energy supply enables the facility to produce green hydrogen instead of fossil-based hydrogen, marking the operational core of the coal-to-hydrogen shift now underway. As the plant moves into full commercial service, industry observers will be watching closely to see whether it can establish a workable blueprint for the next phase of China’s chemical-sector decarbonization.

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The European Union moved ahead in November 2025 with a Delegated Act that sets out how greenhouse-gas savings from low-carbon fuels must be calculated, marking a long-awaited step in the bloc’s effort to regulate hydrogen and other emerging energy carriers. The measure, published after months of disagreement among Member States and an extended approval period in Parliament and Council, complements the Hydrogen and Gas Market Package and will take effect 20 days after its publication. It is intended to create a clearer basis for investment in the low-carbon hydrogen market and other low-carbon fuels used in transport and industry.

The Delegated Act builds on the wider policy framework that includes the Renewable Energy Directive 2018/2001 (RED III), which already defines strict rules for renewable fuels of non-biological origin (RFNBOs). It also ties in with the June 2024 rollout of the Hydrogen and Gas Market Package, which aims to help bring both renewable and low-carbon gases and hydrogen into the European energy system.  While renewable hydrogen remains the EU’s preferred option for meeting climate goals, its production is still far from matching expected demand, making low-carbon alternatives an important short- and medium-term part of the energy transition. The new rules confirm that both renewable and low-carbon hydrogen must reach a 70% emissions-reduction threshold compared with fossil fuels, even though the renewability requirement only applies to the electricity used to produce renewable hydrogen.

The methodology in the Delegated Act mirrors the life-cycle approach used in Delegated Acts 1184/2023 and 1185/2023 for RFNBOs. It includes standard greenhouse gas emission intensity tables for material and energy inputs, and it allows hydrogen to be produced through different pathways, including electrolysis or steam methane reforming with carbon capture. For electrolysis-based hydrogen, the emission intensity of electricity is calculated at the level of countries or bidding zones. The Delegated Act also notes that emissions from renewable electricity, such as wind, solar, geothermal, or hydropower, are treated as zero. One example in the annex shows Finland with an electricity-emission intensity of 12.5 gCO₂eq/MJ in 2023, the second lowest in the EU. This gives an advantage to hydrogen projects operating in Finland, as they can more easily meet the required greenhouse gas savings.

The act leaves unresolved whether nuclear electricity can be used for low-carbon fuels, noting that the Commission will review alternative pathways, including nuclear, by 1 July 2028. It also notes that carbon captured during low-carbon hydrogen production can either be stored in geological formations or fixed into long-lasting products listed in Delegated Act 2024/2620, such as carbonated cement and concrete. Certification of low-carbon hydrogen is set out in Directive 2024/1788 and follows the same structure used for renewable fuels, with voluntary schemes permitted to carry out verification.

Member States have to bring the Delegated Act into national law by August 2026, and Finland plans to do so through its Sustainability Act, with a government proposal expected in spring 2026. As the rules take shape, the framework should give developers and investors more certainty, especially in places where grid-emission levels are low and biogenic CO₂ is readily available.  These conditions place Finnish producers in a strong position to benefit from the evolving regulatory landscape for both low-carbon and renewable hydrogen across Europe.

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The BarMar project is picking up pace. Its partners have confirmed the technical feasibility of the BarMar hydrogen pipeline connecting Barcelona and Marseille, following comprehensive geotechnical and engineering studies for the H2med project. The European corridor H2med project recently finished its first in-depth assessment of the BarMar route. Those campaigns, carried out in summer 2025 and in 2024, confirmed that the proposed corridor for the BarMar hydrogen pipeline is viable. The study found no major physical constraints on the route, and all planned infrastructure crossings were judged feasible. Seabed and terrain conditions also raised no critical concerns.

The report concludes the BarMar route is technically feasible because every identified challenge can be managed through established engineering practices. This clarity lets the partners continue making progress on the overall schedule, which is part of the future European hydrogen network planning. The schedule now sets the Commercial Operation Date (COD) for BarMar in 2032. This is the same date targeted for the CelZa project.

This update reflects the project’s technical demands and the work of the countries involved, which are all developing their own national hydrogen networks. Securing permits and synchronizing the authorization schedule is essential, as H2med is designed to be the backbone connecting all these systems. During the joint Council of Ministers on August 29th 2025, France and Germany reaffirmed their common approach to supporting the corridor’s timely implementation. Also, the progress being achieved now in cross-border governance and regulatory harmonization is truly pioneering. This diligent, laborious effort will not only ensure the success of H2med; it will help establish an essential blueprint for subsequent transnational energy projects.

The year 2025 marked a clear acceleration for H2med, which followed its designation as a Project of Common Interest by the European Commission in 2024. Key steps included the signing of Grant Agreements with the European Climate, Infrastructure and Environment Executive Agency (CINEA) for both BarMar and CelZa. The BarMar company was also created last July to advance the Barcelona–Marseille interconnection. Political backing remains strong across all involved member states, supported by the European Commission, which has called the corridor a priority “energy highway.” Industry support has also widened through the H2med Alliance, now made up of 49 organizations across the hydrogen value chain. For background on the corridor, see our previous coverage of the BarMar hydrogen pipeline and the H2med hydrogen project.

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Hyundai Motor Group will build a 1 GW green hydrogen facility and a new PEM electrolyzer factory in Korea’s southwest, putting the green hydrogen project at the center of its five-year, ₩125.2 trillion ($86 billion) domestic investment strategy. The electrolyzer site will also produce hydrogen fuel cell components for global export, a sign of how firmly Hyundai is leaning into green hydrogen for both mobility and industrial use.

Hyundai has confirmed that the 1 GW green hydrogen plant will rely on proton exchange membrane (PEM) electrolyzers, making use of the region’s renewable energy resources and its established hydrogen distribution infrastructure. The company noted that “PEM electrolyzers will be deployed at the proposed green hydrogen plant,” citing proximity to “nearby hydrogen shipment centers and refueling stations” as strategic advantages. The facility forms a key part of Hyundai’s broader effort to support Korea’s position as a global mobility hub through large-scale clean-energy production and to move this green hydrogen project from concept to industrial scale.

In parallel, Hyundai will construct a dedicated manufacturing facility for PEM electrolyzers and hydrogen fuel cell components. This site will anchor a new global hydrogen export business. The company has not provided any cost or timeline details for either the green hydrogen installation or the electrolyzer production facility, nor has it clarified whether the investment applies to a newly planned site or work already underway at another PEM manufacturing project. Hyundai’s long-term hydrogen ambitions include “building a hydrogen ecosystem” and creating an “end-to-end hydrogen value chain,” covering production, supply, storage, and utilization.

The 1 GW plant also aligns with broader provincial initiatives. South Jeolla Province (Jeonnam) is seeking ₩2.7 trillion ($1.9 billion) in national funding for a 500 MW green hydrogen project, with plans to scale it to 1 GW. The region hosts some of Korea’s most promising offshore wind resources, with 580 MW recently awarded in a government auction and long-term potential of more than 78 GW in fixed offshore wind and 546 GW in floating capacity. That kind of renewable base could help drive Hyundai’s green hydrogen plans and South Korea’s broader floating-wind ambitions, especially if national hydrogen incentives stay in place.

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Air Liquide has started operating what it describes as the first industrial-scale ammonia cracking pilot unit, a facility built to convert ammonia to hydrogen at a throughput of 30 tons per day. The unit is located at the Port of Antwerp-Bruges in Belgium. Air Liquide presents the plant as a significant step toward making large-scale ammonia-to-hydrogen conversion workable in practical industrial settings. The company links the pilot to long-standing challenges of transporting hydrogen and points to ammonia’s established position as a globally traded carrier.

Ammonia is produced from hydrogen and nitrogen and can be manufactured in regions with abundant renewable or low-carbon energy before being shipped through existing global infrastructure. Once delivered, it can be cracked back into hydrogen, creating a route that allows decarbonization efforts in the industrial and mobility sectors. Air Liquide says this configuration supports emerging low-carbon and renewable hydrogen supply chains, with the ammonia-to-hydrogen process acting as a connective element between producing regions and final users.

The company notes that the pilot incorporates new technology developments intended to broaden its portfolio for renewable and low-carbon hydrogen. The project involved proprietary work across several technical areas, including process safety, material testing, catalysis for ammonia cracking, ammonia combustion and efficient molecule separation. Air Liquide highlights the shift from laboratory research to an industrial-scale operation as an indication of its ability to advance first-of-its-kind solutions.

Armelle Levieux, member of Air Liquide’s Executive Committee with responsibility for Innovation and Technology and Hydrogen Energy activities, said: “The commissioning of our ammonia cracking pilot unit in Antwerp is a key milestone. This is a world’s first which paves the way for new low-carbon hydrogen supply chains. By proving the viability of industrial-scale ammonia cracking, Air Liquide demonstrates its capacity to innovate and provide concrete solutions for its customers, and contributing to the Energy Transition. I am immensely proud of the work and commitment of all our teams who made this achievement possible.”

Air Liquide says the pilot will be used to validate operating conditions and safety measures that would be needed for wider deployment. The company also notes that enabling ammonia to hydrogen conversions directly at a port terminal could support alternative logistics pathways by allowing ammonia shipments to be received and processed onshore. Supported by the Flemish Government through VLAIO, the project is presented as groundwork for future industrial and onshore cracking sites capable of producing hydrogen where it is required.

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The German government has made major regulatory reforms to expedite the permitting procedure for large-scale energy storage projects. New legislation aims to simplify planning regulations for facilities in non-urban areas. The German Parliament, the Bundestag, has adopted a legal modification that will define battery, heat, and hydrogen storage as privileged projects in non-urban regions, specifically under Paragraph 35 of the Federal Building Code. This crucial move aims to simplify zoning requirements and ultimately hasten the deployment of these vital facilities. While the legislation passed a critical legislative vote in the Bundestag, it still needs approval from the Bundesrat, the second legislative house of Parliament, before it can officially go into effect.

This reform is part of an “omnibus package” that simultaneously amends the Energy Industry Act (EnWG) and several related statutes. The governing parliamentary groups—CDU, CSU, and SPD—introduced the provision based on the argument that large battery systems often require access to substations and high-voltage nodes, which are rarely situated within built-up zones. The German Solar Association (BSW-Solar) confirmed that this new zoning category will remove a significant procedural bottleneck for utility-scale batteries. “This will significantly simplify planning approvals for battery and heat storage and provide greater legal certainty,” said Carsten Körnig, the association’s CEO. He added, “It removes an important barrier to the rapid scale-up of storage needed for an efficient and cost-effective energy transition.” A Bundestag statement on the vote explicitly recognized that battery systems of at least one megawatt-hour are “by their nature” typically situated outside urban areas. Granting privileged status under the BauGB is intended to offer developers a clearer, faster permitting pathway.

The German Energy Storage Systems Association (BVES) immediately welcomed the ruling, with CEO Urban Windelen stating that the legal clarification would finally provide a stable framework for siting “flexibility projects” in appropriate locations. Windelen further noted that the amendment reflects a broader shift in understanding: flexibility and resilience requirements in the modern power system can no longer be managed with rules designed for older infrastructure. “With this revision, lawmakers are taking a clear and pragmatic step in that direction, which we, as the storage sector, strongly welcome,” he said.

In a related change, the legislative package includes a separate amendment that ends a long-standing disadvantage for mixed-use storage systems—those that can charge from both the grid and renewable generators. Previously, only facilities that charged exclusively from the grid and fed all electricity back to the grid qualified for a network charge exemption. The updated rule will extend this exemption to multi-use systems, consequently improving the business case for batteries paired with PV plants or customer-side installations. Körnig commented that “Multi-use storage is particularly useful because it makes very efficient use of grid-connection capacity and reduces export and consumption peaks.” Additionally, Udo Hemmerling, Managing Director of the Federal Association of Non-Profit Land Companies (BLG), was reportedly positive about the decision, saying, with a positive surprise, “For wind, biogas and ground-mounted PV plants, it is now possible to add battery storage to the plant with less planning effort and improve revenues on the electricity market.” This move supports large-scale energy storage by reducing planning effort and improving project economics. The law will take effect once the Bundesrat grants its approval and the final text is published in the Federal Gazette (Bundesgesetzblatt).

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Engineering studies have begun on a planned facility in northwest England that would produce turquoise hydrogen as part of a wider offshore natural-gas and hydrogen storage development. The work marks an early phase in a turquoise hydrogen project that EnergyPathways intends to integrate into its broader coastal infrastructure. The company confirmed it has started design work with Hazer Group, which supplies methane-pyrolysis technology, and KBR, the project’s EPC partner. The plant is designed to generate hydrogen from natural gas while creating solid carbon rather than carbon dioxide.

According to EnergyPathways, the plant could be incorporated into the Marram Energy Storage Hub (MESH), a development that aims to store up to 50 billion cubic feet of natural gas and hydrogen about 18 km off the Lancashire shoreline. Under an agreement signed in July, Hazer’s technology could allow the site to produce as much as 20,000 tonnes of turquoise hydrogen per year using natural gas and unprocessed iron feedstocks intended for ammonia production. The partners are also assessing potential markets for as much as 60,000 tonnes of graphite produced through the process. This graphite can be directed toward several applications.

Hazer and KBR are managing the engineering design and concept-development studies, which are scheduled for completion in early 2026. The shift toward this turquoise hydrogen project marks a change from MESH’s initial vision, which had included blue and green hydrogen. As EnergyPathways explained, those earlier pathways were affected by rising production costs. CEO Ben Clube said, “With … blue and green hydrogen looking increasingly challenged by high production costs, EnergyPathways aims to develop a hydrogen production pathway and decarbonization solution that could be more affordable to Britain’s taxpayers and energy consumers.”

Methane pyrolysis is viewed as a lower-cost route to clean hydrogen due to the solid carbon it yields. Clube added, “With the UK 100% dependent on imports for its graphite needs, and China dominating global supply with over 80% of market share, the British government… [is] actively seeking to secure [its] own graphite supply chains.” Even so, the technology remains relatively early in deployment, with only a small number of operating plants.

Hazer began producing hydrogen through its process at a pilot facility in Perth, Australia, in February 2024. Commenting on the integration of its technology into the MESH plans, CEO Glenn Corrie said it represents a “genuine game-changer” for UK energy transition plans. As EnergyPathways advances this turquoise hydrogen project, the company positions the hub as a potential example of how hydrogen production and offshore storage can be paired within a single development. An earlier report from South Korea points to similar progress in turquoise hydrogen, underscoring how this production route is advancing in multiple regions.

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