Shell's Dutch H2 plant to meet 10pc of Pernis demand

Market: Hydrogen
10/06/22

Shell's planned 200MW Rotterdam electrolyser project will only meet around 10pc of hydrogen demand from its nearby 420,000 b/d Pernis refinery, the firm's commercial manager of hydrogen assets Katharina Gruenberg has said.

The capacity of the Hydrogen Holland 1 project — which Shell expects to be the largest in Europe when it comes online in 2024 — and demand from the connected refinery demonstrates the magnitude of the scale-up task facing the hydrogen industry, which was repeatedly stressed by delegates at Reuters' Hydrogen 2022 Conference in Amsterdam this week.

Shell has said the plant would produce 50,000–60,000 kg/d, implying hydrogen demand from the refinery of around 500-600 t/d.

Low-carbon hydrogen may need to displace 40mn t/yr of hydrogen consumed globally by the refining sector, with almost all current supply derived from fossil fuels with unabated carbon emissions. Refineries use hydrogen to remove impurities from fuels and break heavy molecules into gasoline, diesel and kerosene.

The global hydrogen market of around 90mn t/yr may grow five- or six-fold by 2050, according to the International Energy Forum, with existing demand from refining, fertilisers, and chemicals potentially compounded by need from hard-to-abate industry and mobility sectors. Hydrogen from low-carbon sources would need to increase by 500- to 600-fold, as it accounts for less than 1pc of production today.

Shell is also looking at hydrogen from natural gas with carbon capture and storage (CCS), as it seeks to use all available routes to meet the expected massive demand.

"We need to look at CCS for our [refining and chemical] assets anyway," Gruenberg said.

The scale of hydrogen projects is increasing. Shell last year launched a 10MW electrolyser in Cologne, Germany, and a 20MW electrolyser in China's Hebei province. It expects to make a final investment decision on the 200MW Rotterdam electrolyser in the coming weeks, to allow first production in 2024. And it is considering gigawatt-scale production from the North Sea by 2030, Gruenberg said.

By Aidan Lea

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16/12/25

EU eases ICE phase-out with 2035 CO2 car target: Update

Adds details on credits, transport commissioner comment in paragraphs 4-6 Brussels, 16 December (Argus) — The European Commission has proposed a new 90pc cut in car fleet emissions by 2035, replacing the previously agreed 100pc target that would have effectively phased out the sale of internal combustion engine (ICE) vehicles from that date The plan would allow some new ICE vehicles to remain on sale beyond 2035, alongside plug-in hybrids, range extenders and mild hybrids, as well as electric and hydrogen cars. The remaining 10pc of emissions would need to be offset through low-carbon steel, e-fuels or biofuels, according to the commission. The proposals need to be adopted by a majority in the European Parliament and among EU states. Automakers could also "bank and borrow" credits between 2030-32 to help meet the existing 2030 target of a 55pc cut from 2021 levels. Under the new proposals, manufacturers using these flexibilities would only need to achieve a 40pc fleet-average reduction, down from a previously planned 50pc. The commission indicated that credits for greenhouse gas (GHG) savings from e-fuels and biofuels can compensate up to 3pc of manufacturers' reference targets for 2035 and low-carbon steel credits can compensate for a further 7pc. Transport commissioner Apostolos Tzitzikostas said the credit system will boost uptake of sustainable fuels. "This is a clear signal than other technologies than battery electric vehicles (BEV) can be put on the market after 2035," said Tzitzikostas. Expanded carbon-neutral criteria would allow sustainable biofuels to help meet the targets that currently require 0g/km from 2035. EU renewable ethanol group ePure said emissions from ethanol were 79pc lower than fossil fuels in 2024, in line with previous years. The European Biodiesel Board reported savings of 77-81pc for biodiesel, using the official fossil fuel comparator of 94g of CO2e/MJ. German MEP Peter Liese criticised the original ICE ban, but said industry problems stem from market shifts, not from Brussels. "The industry must stop shifting the blame for its own mistakes and for market developments, for example in China, onto Brussels," he said, adding that he will push for green steel recognition before 2035. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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EU may crank up coal and steel research funds in 2027

11/12/25

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11/12/25

EU may crank up coal and steel research funds in 2027

London, 11 December (Argus) — The European Commission could fund a much larger share of research in the coal and steel industry from 2027, according to a staff working document published yesterday. The EU Research Fund for Coal and Steel (RFCS) would fund 70pc of corporate research and 100pc of academic research into green initiatives if the EU moves forth with the proposal. It currently funds 50pc of both corporate and academic research projects, but has struggled to attract participants or meet its spending targets, noting that the "underspending of the project is rooted in a lack of attractiveness of certain aspects of the programme". RFCS spent 57pc of its €43mn ($50mn) budget for large coal projects and only 31pc of its €208mn budget for steel research from 2021 to 2024. Brussels, troubled by a lack of applications, consulted companies and academics this year and found that its spending requirements were the largest barrier. Most were unable or unwilling to fund 50pc of large research projects themselves. RFCS has supported a number of groups hoping to repurpose old coal mines for clean energy. GreenJOBS and Mine-TO-H2, two funding recipients, both plan on making green hydrogen from mine water, while GrEnMine received pilot funding worth €3.5mn to research new ways to store gravitational energy in abandoned mines. Others, such as REM and GI-mine, are working on new methods to capture methane from coal mines. In the steel sector, RFCS has awarded funds to hydrogen power projects such as ProSynteg and HYDREAMS and research groups such as BIOCODE, which hopes to replace up to 10pc of the coal in coke ovens with biomass. The EU dissolved the European Coal and Steel Community (ECSC) — an agency tasked with making a common European steel market, which eventually led to the creation of the EU — in 2002. The EU used revenues from ECSC assets to launch and fund the RFCS in the same year, and boosted the programme in 2021 by tapping into the assets themselves. By Austin Barnes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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German cabinet passes EU RED III

10/12/25

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10/12/25

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.

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Q&A: GH2 Solar outlines gaps slowing India’s H2 plans

09/12/25

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09/12/25

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.

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Oman stays upbeat on long-term green H2 prospects

02/12/25

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02/12/25

Oman stays upbeat on long-term green H2 prospects

Muscat, 2 December (Argus) — Oman remains committed to its long-term renewable hydrogen ambitions, although the pace of global developments has slowed and some companies have withdrawn from project plans in the country, delegates heard at the Green Hydrogen Summit Oman in Muscat on 1 December. Speakers at the event widely praised Oman's abundant potential for renewable power generation and commended the government for its efforts to streamline support for the sector. But the perception of a "reality check" that has been felt in many parts of the world following the inflated expectations for renewable hydrogen in the early 2020s has also reached Oman. The current state of the industry is challenging globally, especially around costs, regulations and supply chains, said Oman's minister of energy and minerals Salim Al Aufi. Developers may need more support to realise their projects as "some of them will stumble" and "some of them will want to leave", he said. Some firms have already withdrawn their plans. BP and a consortium led by France's Engie and Posco have shelved large renewable hydrogen and ammonia projects in the country, state-owned hydrogen company Hydrom's managing director Abdulaziz Al Shidhani said. Seven major projects are still planned in the country and could between them produce some 1mn t/yr of renewable hydrogen by 2030-31, Al Shidhani said. But Al Aufi acknowledged that reaching the country's target of producing at least 1mn t/yr by 2030 will be an uphill battle. "We have to mobilise more than 40mn solar panels in about three years' time, we have to mobilise more than 2,000 [wind] turbines, more than 6,000-9,000 wind blades and we haven't done any of that yet," Al Aufi said. The slower pace of developments globally is therefore a "blessing in disguise," Al Aufi said. "It is allowing us to do things at a fast-enough pace" but without the "hype" that created "a lot of heat" across different parts of the value chain, such as equipment manufacturers and contracting firms. There is "a lot of noise" that is making Oman and some of its partners "a little bit uncomfortable". But this is a "very short-term noise" and the focus must be on the long-term plans, Al Aufi said, noting that "no one at all" is questioning whether hydrogen in general is the right path to pursue for Oman. "I think we are doing exactly what we should have been doing and we are on the right track." Numerous developers highlighted that Oman's decision to designate so-called "national champions" for different parts of the value chain stands out as a key advantage globally. Hydrom has been set up as the entity in charge of land allocations and as a single point of contact for issues such as permitting, while various subsidiaries of state-owned energy company OQ have been put in charge of developing common user infrastructure like pipelines and storages and electricity transmission systems. And despite the prevailing challenges, Oman has the first tangible results to show for its efforts. Indian firm Acme has started construction of the first phase of a renewable ammonia project in Duqm , backed by financing support from the Indian government and an offtake deal with Norwegian fertiliser giant Yara. Meanwhile, Acme's compatriot Jindal Steel has started construction on a direct reduction iron plant that will transition to renewable hydrogen use in the future. The government is hoping that an incentive package unveiled in August can help more projects towards realisation. Among other measures, the incentives include reduced land fees in early development stages and the trimming of royalties over 15 years. Between them, the different measures represent a commitment of around $3.6bn-4bn to the hydrogen sector, Hydrom's Al Shidhani said. By Stefan Krumpelmann Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Shell's Dutch H2 plant to meet 10pc of Pernis demand

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EU eases ICE phase-out with 2035 CO2 car target: Update

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