Australia’s H2 subsidy to bridge producers’ cost gap

Spanish Market: Hydrogen
25/05/23

Australia's federal government will start subsidising hydrogen from 2026-27 at an expected rate of A$2-4/kg, according to the A$2bn ($1.3bn) Hydrogen Headstart programme that emerged during budget estimates hearings.

Qualifying projects will need to be operational and producing hydrogen to access the subsidy with the first payments expected to be made in 2026-27, said officials from Australia's Department of Climate Change, Energy, the Environment and Water (DCCEEW). During budget estimates week senior department officials and ministers field questions from elected members of Australia's upper house of parliament, the Senate, about spending announcements such as Hydrogen Headstart.

The production credit is designed to be paid at the time hydrogen is manufactured and will bridge the gap between the price at which it is produced and the price at which it is sold. Companies with the lowest margins between production costs and market prices will have preferential access to the subsidy under a competitive tender process.

It will be designed in a similar way to the fuel security services payment, said the head of DCCEEW's adaption and new industries division Shane Gaddes. That scheme provides a maximum A¢1.8/litre for Australia's two remaining refineries when refining margins drop to A$7.30/bl, with no payments for margins of A$10.20/bl or higher. The DCCEEW agreed with a senator's assertion that Hydrogen Headstart effectively subsidised the high renewable electricity costs for green hydrogen production.

"Currently there's A$200bn to A$300bn worth of investment announced but it hasn't quite been able to reach the final investment decision because of the cost gap between the cost of producing and the market price for green hydrogen," Gaddes said.

Australia's strong potential for renewable energy production has led it to the forefront of proposed hydrogen projects internationally, with planned capital expenditure rising to A$230.4bn-302.5bn in 2022. Some companies planning green hydrogen development have pointed to electricity sales to the grid as helping to lower production costs.

By Tom Major

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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.

EU may crank up coal and steel research funds in 2027

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.

Bundeskabinett beschließt Anpassung der THG-Quote

10/12/25

Bundeskabinett beschließt Anpassung der THG-Quote

Hamburg, 10 December (Argus) — Das Bundeskabinett hat am 10. Dezember ein Gesetz zur Umsetzung der RED III in nationales Recht beschlossen. Das Gesetz wird voraussichtlich nicht vor dem 1. Januar verabschiedet, soll aber rückwirkend ab dann gelten. Damit passt der Gesetzgeber die Treibhausgasminderungsquote an und schafft die Doppelanrechnung fortschrittlicher Kraftstoffe ab. Preise für THG-Zertifikate steigen bereits. Die Gesetzesvorlage, die das Kabinett beschlossen hat, entspricht weitestgehend einem Entwurf vom 29. Oktober, der im November durchgesickert ist . So soll unter anderem die Quotenhöhe bis 2040 auf 59 % steigen. Für 2026 wird sie 12 % betragen. Flugzeug- und Schiffskraftstoffe sind von der Quotenverpflichtung ausgenommen. Das Gesetz beendet zudem die Anrechenbarkeit von Palmölprodukten, insbesondere Palmölmühlen-Abwasser (POME), auf die THG-Quote, wie bereits in einem früheren Ministerialentwurf vorgesehen. Allerdings tritt das Verbot für POME sowie die Pflicht für Kraftstoffproduzenten, Vor-Ort-Kontrollen durch eine zuständige Behörde eines EU-Mitgliedstaats zuzulassen, erst 2027 in Kraft. Damit bleibt 2026 ein Übergangsjahr. Der Gesetzentwurf bestätigt auch das Ende der Doppelanrechnung für fortschrittliche Biokraftstoffe, ein zentraler Unsicherheitsfaktor für Marktteilnehmer. Nach geltendem Recht können fortschrittliche Biokraftstoffe mit dem zweifachen ihres Energiegehalts auf die THG-Quote angerechnet werden, sofern das Mindestmandat für fortschrittliche Kraftstoffe erfüllt ist. In der Folge müssen Inverkehrbringer künftig mehr Biokraftstoffe auf dem Markt bringen oder THG-Zertifikate kaufen, um die Quote zu erfüllen. Die Änderung zur Abschaffung der Doppelanrechnung gilt jedoch für das gesamte Verpflichtungsjahr und alle Folgejahre, was bedeutet, dass sie rückwirkend ab dem 1. Januar 2026 greift. Die einzige Ausnahme gilt für Kraftstoffe, die vor dem 1. Januar 2026 in Verkehr gebracht wurden. Das Gesetz tritt am zweiten Tag nach seiner Veröffentlichung im Bundesgesetzblatt in Kraft, wobei einzelne Abschnitte aus verfahrensrechtlichen Gründen einen Tag früher wirksam werden. Der Gesetzentwurf muss nun dem Bundesrat und dem Bundestag zur Beratung vorgelegt werden. Die Zustimmung des Bundesrats ist nicht erforderlich. Der Bundestag könnte jedoch noch Änderungen einbringen. Erst nach Zustimmung des Bundestags kann das Gesetz dem Bundespräsidenten zur Unterzeichnung vorgelegt und anschließend im Bundesgesetzblatt veröffentlicht werden. Der Abschluss des Gesetzgebungsverfahrens wird im ersten Quartal 2026 erwartet. Änderungen bei Unterquoten, RFNBOs und Biomethan Das Mandat für fortschrittliche Biokraftstoffe aus Rohstoffen gemäß Anhang IX der RED III wird ebenfalls erhöht und soll bis 2040 9 % erreichen, wie bereits im Entwurf vom 29. Oktober vorgesehen. Das Mandat für erneuerbare Kraftstoffe nicht biogenen Ursprungs (RFNBOs) — wie E-Fuels und grüner Wasserstoff — fällt höher aus als im vorherigen Entwurf. Es steigt bis 2034 auf 2,5 % des Energiemixes eines verpflichteten Unternehmens, statt 1,8 % im Entwurf von Oktober, und erreicht 2040 8 % statt 4 %. Die Strafzahlung bei Nichterfüllung beträgt 120 €/GJ. Importiertes Biomethan kann auf die THG-Quote angerechnet werden, sofern bestimmte Bedingungen wie der Anschluss an das EU-Gasnetz erfüllt sind. Kleinere Anpassungen umfassen die Absenkung des Basiswerts für Emissionen von 94,1 kg CO2e/GJ auf 94 kg CO2e/GJ, um die EU-Vorgaben zu harmonisieren, sowie die Verschiebung der Frist für die Anmeldung beim Hauptzollamt vom 15. April auf den 1. Juni des Folgejahres. Markt reagiert mit Preissprung Der Markt für THG-Zertifikate reagierte sofort. Zertifikate der Kategorie "Andere" für 2025 werden am 10. Dezember rund 20 €/t CO2e höher gehandelt als am Vortag, und auch die Preise für Zertifikate für 2026 und 2027 steigen. Die Preise für 2025-Zertifikate steigen, obwohl sie von der Gesetzesänderung nicht direkt betroffen sind, da sie als Ersatz für 2027-Zertifikate gelten, weil überschüssige Erfüllung aus 2025 auf 2027 übertragen wird. Zudem könnte HVO künftig eine zentrale Rolle bei der Erfüllung der THG-Quote spielen, was die Zertifikatspreise beeinflussen kann. Die Nachfrage nach fortschrittlichem HVO könnte deutlich steigen, da es unbegrenzt auf die THG-Quote angerechnet werden kann — sowohl als Beimischungskomponente als auch als Reinkraftstoff — und in den meisten bestehenden Diesel-Fahrzeugflotten eingesetzt werden kann. Das Ende der Doppelanrechnung könnte auch die Nachfrage nach nicht-fortschrittlichen Biodiesel-Sorten wie RME (Rapsbasis) und UCOME (Altspeiseölbasis) erhöhen. Deren Anrechenbarkeit ist zwar auf einen bestimmten Prozentsatz des Energiemixes eines Unternehmens begrenzt, doch wurde diese Grenze in der Vergangenheit nicht immer ausgeschöpft. Von Max Steinhau & Chloe Jardine Senden Sie Kommentare und fordern Sie weitere Informationen an feedback@argusmedia.com Copyright © 2025. Argus Media group . Alle Rechte vorbehalten.

German cabinet passes EU RED III

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.

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

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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