Hydrogen
Overview
Hydrogen is an increasingly important piece in the decarbonisation puzzle. Industrial players are seeking ways to take carbon emissions out of their hydrogen production processes, while green hydrogen producers see the gas as a viable outright alternative to hydrocarbons.
Future production routes range from methane reformation with carbon capture to pyrolysis, waste gasification and electrolysis, powered by renewable energy or fossil fuels. Combinations of processes and energy being used to produce hydrogen presents existing users of industrial heat and key chemicals a challenging landscape to navigate.
The Argus Hydrogen and Future Fuels service has been designed to provide industrial power, chemicals and energy users with crucial information to help them make well informed decisions. It covers the upstream for projects, midstream for transportation and storage, and downstream for ammonia and methanol. It also covers the latest technological developments and policy news on hydrogen from across the globe.
Latest hydrogen news
Browse the latest market moving news on the global hydrogen industry.
German cabinet passes EU RED III
German cabinet passes EU RED III
Hamburg, 10 December (Argus) — The German cabinet on 10 December approved legislation to implement the EU's Renewable Energy Directive (RED III) into national law. This will adjust the greenhouse gas (GHG) reduction quota and abolish double counting of advanced fuels from 2026. But it is unlikely to pass remaining legislative processes in time for the EU's 1 January deadline. The bill passed by the cabinet largely follows a draft dated 29 October that was leaked in November. The overall quota level will rise to 59pc by 2040. Aviation and marine fuels are exempt from the quota obligation. The law will end the eligibility of palm oil products, most notably palm oil mill effluent (Pome), for compliance towards the GHG quota. This exclusion, and a requirement for fuel producers to allow on-site audits, will not come into effect until 2027, leaving 2026 as a transitional year. The end of double counting for advanced biofuels removes a key point of market uncertainty. Under current rules, advanced biofuels can be counted as twice their energy value towards the GHG quota, provided the minimum sub-mandate for advanced fuels has been met. But the change to end double counting will apply to the entire compliance year and all subsequent years, meaning it will be retroactive to 1 January. The only exception is for fuels supplied prior to 1 January 2026. The law will enter into force on the second day after publication in the Federal Law Gazette, with selected sections taking effect a day earlier for procedural reasons. Before that can happen, the bill must be submitted to the Germany's lower and upper parliaments for debate. The lower house's approval is not required, and the upper house could initiate changes. The bill can only be submitted to the Federal President for his signature once the upper house has given approval. This process is likely to conclude in the first quarter of 2026. Changes to sub-quotas, RFNBOs, biomethane The sub-mandate for advanced biofuels, made from feedstocks listed in Annex IX of RED III, will rise to 9pc by 2040. The mandate for renewable fuels of non-biological origin (RFNBOs) — such as e-fuels and green hydrogen — is higher will rise to 2.5pc of an obligated company's energy mix in 2034, and then to 8pc in 2040. The penalty for non-compliance is €120/GJ. Imported biomethane can be counted towards the GHG quota, provided it meets certain conditions, such as a connection to the EU gas grid. The baseline emissions value is 94kg CO2e/GJ, aligned with the rest of the EU. The registration deadline with the main customs office is 1 June. The market for GHG certificates reacted immediately. Other certificates for 2025 are trading around €20/t CO2e higher than the previous day, and prices for 2026 certificates are rising. Prices for 2025 certificates are rising, although they are unaffected by the change. They are seen as a substitute for 2027 certificates because excess 2025 compliance will be carried over. Hydrotreated vegetable oil (HVO) could now play a central role in meeting the GHG quota, which can influence certificate prices. Demand for advanced HVO could increase significantly, as it can be counted without limit towards the GHG quota as a blending component and as a pure fuel and can be used in most of the existing diesel vehicle fleet. The end of double counting could increase demand for non-advanced biodiesel grades, such as rapeseed-based RME and used cooking oil-based Ucome. Although the eligibility of these is capped to a certain percentage of a company's energy mix, this limit has not always been fully utilised in the past. by Max Steinhau and Chloe Jardine Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Q&A: GH2 Solar outlines gaps slowing India’s H2 plans
Q&A: GH2 Solar outlines gaps slowing India’s H2 plans
Mumbai, 9 December (Argus) — Indian renewable energy firm GH2 Solar recently began construction of an alkaline electrolyser manufacturing plant in Madhya Pradesh, with an initial capacity of 105 MW/yr that it aims to expand to 500 MW/yr. The plant is developed with South Korea's AHES and UK-based Rhizome2, and received roughly 1.6bn rupees ($17.8mn) under India's second electrolyser manufacturing subsidy round. GH2 Solar also plans to build its own renewable hydrogen production facilities, having secured three-year subsidies for 10,500 t/yr of output. Argus spoke with managing director Anurag Jain and vice-president of business development and corporate strategy Sanjeev Sharma about the company's plans, views on Indian policy and localisation of key components for electrolysers. Edited highlights follow: What are the main challenges that GH2 Solar and other Indian companies face in bringing hydrogen and electrolyser projects to fruition? The challenges are quite multifaceted. For GH2 Solar, and most other Indian developers, the biggest hurdle is project bankability. The policy direction is clear, but long-term offtake certainty and stable price signals are still evolving, making lenders cautious. These are highly capital-intensive projects that combine renewable generation, balance-of-plant and storage, which means long financing cycles. Another issue is the intermittency of renewable energy, which affects electrolyser efficiency and utilisation. Managing that through batteries, round-the-clock power or hydrogen storage adds cost and complexity. India still imports critical components such as membranes and catalysts, so building a resilient domestic supply chain will take time. Add to that the need for skilled manpower, unified standards and insurance frameworks — it's a steep but achievable learning curve. How do you view India's tenders? Are they effective in driving adoption? The tenders have created momentum. The production-linked incentives (PLIs) and the National Green Hydrogen Mission bids have drawn strong private participation and signalled government commitment. But we must recognise they are first-generation schemes. Some frameworks expect immediate commercial viability and deep localisation, which can be unrealistic early on. We need longer offtake tenors, payment security mechanisms and phased localisation milestones. But the direction is right. The tenders have put India firmly on the global hydrogen map. What additional policy or regulatory measures could accelerate the sector? India should move quickly to introduce contracts for difference (CfDs) or carbon CfDs to bridge the cost gap between grey and green hydrogen. That single mechanism can transform project bankability. A national hydrogen exchange or government-anchored offtake pool would aggregate demand and provide transparent price discovery. We also need a payment security fund, harmonised pipeline and grid codes, and continued fiscal support for electrolyser research and development, especially for membranes and catalysts. What are the biggest challenges for developing a fully indigenous electrolyser manufacturing ecosystem in India? True localisation goes far beyond assembly. The challenge lies in mastering advanced materials — membranes, coated bipolar plates and catalysts — and building high-precision chemical and metallurgical capabilities. Domestic demand must scale enough to justify the capital intensity of these facilities. We also need accredited testing and certification centres in India to validate stack life and performance so that Indian-made systems are globally bankable. How can project financing for green hydrogen become more viable? Financing will follow predictability. Mechanisms such as CfDs, minimum-volume guarantees or sovereign-backed payment windows can provide stable revenue floors. Blended finance — mixing concessional debt and DFI [development finance institutions] participation — will lower the cost of capital. Allowing hydrogen assets to earn ancillary-service revenue from the grid can also enhance project economics. And finally, standardised project templates and due-diligence protocols will shorten financial-closure timelines. Offtake remains a bottleneck. What measures could resolve this? We need an aggregated demand framework. A government-backed platform that bundles demand from refineries, fertilisers, city-gas networks and even corporate buyers could issue unified offtake tenders. Sectoral mandates — such as blending targets in piped natural gas or compressed natural gas and substitution quotas in refineries — will anchor baseline demand. Tradeable green-molecule certificates would let corporates purchase decarbonisation credits even if they don't consume hydrogen physically. Internationally, India should also participate in global offtake auctions with the EU, Japan and Korea. What is GH2 Solar's long-term strategy for green hydrogen and its derivatives? Our strategy is to create an end-to-end green hydrogen ecosystem — from renewable electrons to green molecules. We're setting up a 105 MW/yr electrolyser manufacturing facility in Madhya Pradesh. Civil works are progressing, equipment orders are being worked out and pilot production is planned for late 2026, with full-scale operations set for 2027. We are simultaneously developing green hydrogen production facilities. In the short term, our focus is on domestic decarbonisation — supplying green hydrogen to refineries, fertiliser and industrial clients. In the medium term, we will expand into green ammonia — we have already announced a 100,000 t/yr green ammonia facility with two partners — and e-methanol and SAF [sustainable aviation fuel], especially for export markets. What is your view on the use of Chinese electrolysers in Indian projects? It is a pragmatic bridge. Chinese systems are currently cost-competitive and available quickly, which helps early adopters prove the business case. But India must avoid long-term dependence. Every import should come with localisation and technology-transfer clauses so that we can build domestic capability over the next 3-5 years. Our goal should be cost parity and self-reliance, not permanent import dependence. GH2 Solar was awarded the support for the electrolyser capacity with high local-value-addition (LVA) targets. How will you achieve these? We have created a detailed localisation roadmap. In the first year, we will source and assemble all balance-of-plant, frames, power electronics and casing domestically, importing only few specialised components, achieving 80pc LVA. From year two onwards, we will indigenise stack components through technology partnerships with Indian material suppliers, reaching more than 90pc localisation. Which components still need to be imported? At present, we still need to import membranes, catalysts and coated bipolar plates — the high-tech core of the stack. Domestic production of these components should start in the next 18-36 months through our joint venture and targeted PLI support. With consistent policy and demand visibility, India can achieve full indigenous capability within five years. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Singapore sets green power rules for new data centres
Singapore sets green power rules for new data centres
Singapore, 2 December (Argus) — Singapore has opened applications for at least 200MW of new data centre capacity, with adoption of novel green energy sources as a key criteria, the city-state's Economic Development Board and Infocomm Media Development Authority said on 1 December. The city-state is looking to host more cloud computing services against a backdrop of increasing competition in southeast Asia, while keeping the industry's power and emissions footprint in check. Applicants should have at least 50pc of proposed data centre capacity powered by "eligible green energy pathways", according to the Economic Development Board and Infocomm Media Development Authority. The pathways include biomethane, low-carbon ammonia, low-carbon hydrogen and novel fuel cells with carbon capture and storage. Solar panels are also listed, including advanced "building-integrated" variants where photovoltaics are built into new premises. Singapore launched a 300MW biomethane import trial in September and will appoint power generators as trade aggregators in early 2026. The city-state also has an ongoing low-carbon ammonia bunkering and 55-65MW power generation pilot. Singapore announced a 700MW data centre park at its energy and petrochemical hub Jurong Island in November, to expand on the over 1.4GW of existing cloud computing infrastructure. Data centre applicants under the latest exercise should meet "best in class" efficiency standards, including a power usage effectiveness of at most 1.25 at full load. Applications close at the end of March 2026. By Liang Lei Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
UK's Cadent delays HyNet H2 network for policy clarity
UK's Cadent delays HyNet H2 network for policy clarity
London, 28 November (Argus) — UK gas network operator Cadent has halted its planning application for the HyNet North West hydrogen pipeline, citing uncertainty about government timelines and subsidy allocation under the hydrogen transport business model (HTBM), which will not be finalised until spring 2026. Cadent had aimed to submit a development consent order (DCO) by end of 2025 after public consultations and front-end engineering design work, targeting a final investment decision (FID) in 2026 if government support materialises. But the firm said it will pause the DCO process, although environmental surveys and routing assessments will continue. Cadent said the government has confirmed it will finalise the HTBM and start the process for one hydrogen pipeline in spring 2026. The government said in July that the first regional hydrogen transport and storage network should start up by 2031. The operator said in June it plans to have the network operational in the early 2030s, probably to align with Essar Energy Transition's plans for its Stanlow site, and carry hydrogen from there. The plant's second phase will supply regional customers, while initial output will serve Essar's refinery. UK operators like Cadent are also waiting for clarity on hydrogen blending into existing gas grids as a fallback when industrial demand is low. Cadent has submitted evidence supporting up to 20pc blending in pilots. The delay adds uncertainty to the project, which may compete for HTBM support with other developers, potentially pushing back FID. Cadent did not respond to requests for comment. The HTBM is designed to make early-stage pipeline projects viable by guaranteeing returns. It combines a regulated asset base model — where operators earn a capped return on infrastructure costs — with government subsidies to cover revenue shortfalls while demand builds up. This gives investors long-term certainty needed for FID. HyNet's 125km pipeline network would link Stanlow to industrial users and blending points. The CO2 element of HyNet is progressing, with Eni reaching financial close on its storage site and Eni and Essar securing DCO approval for the CO2 pipeline. By Chingis Idrissov Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
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