German draft RED III bill to raise GHG quota

: Biofuels, Emissions, Hydrogen
25/06/19

Germany's economy and climate ministry has published a draft bill to amend the Federal Immission Control Act, aiming to implement the EU's Renewable Energy Directive (RED III) into national law. The proposal includes sweeping changes to the country's greenhouse gas (GHG) reduction quota.

The draft sets out a gradual increase in the GHG quota to 53pc by 2040, up from the previous target of 25.1pc in 2030. The trajectory to 2030 has also been slightly adjusted. The proposal meets a long-standing demand from the biofuels industry for a scaled-up quota increase.

The draft includes a mechanism to raise the quota two years later if over-compliance occurs — triggered when total compliance in a given year already meets the quota set for two years ahead.

It also proposes abolishing the double-counting option for biofuels classified as advanced, while increasing their minimum sub-quota to 3pc by 2030, up from 2.6pc. Many market participants had anticipated the removal of the double-counting option, which would increase the volume of compliance options needed to meet the mandate.

Renewable fuels would only be eligible if state inspectors can conduct on-site inspections of production facilities — a measure aimed at reducing the potential for fraud in biofuel accounting.

The draft also revises which fuels can be used to meet the quota. Soy- and palm oil-based fuels will no longer be eligible, including fuels derived from palm oil by-products such as palm oil mill effluent (Pome) oil. Pome oil-based fuels had previously qualified for the advanced sub-quota under a clause that allowed single-counting despite their classification as advanced. This regulation will take effect immediately once the legislative amendment is enacted.

Caps for food-and-feed-crop-based and waste-based fuels will also be adjusted. The limit for food-and-feed-crop-based fuels will fall to 3pc of the energy supplied by an obligated party by 2030, down from 4.4pc. The cap for feedstocks listed in Annex IX Part B of RED — such as used cooking oil (UCO) — will rise to 2.8pc by 2039, up from 1.9pc.

The legislation would introduce a minimum quota for renewable fuels of non-biological origin (RFNBOs), measured by energy content. This would start at 0.1pc in 2026 and rise to 12pc by 2040. RFNBOs include synthetic fuels such as power-to-liquid (PtL) e-fuels and green hydrogen.

The draft extends the scope of the GHG quota to the aviation sector, which previously had a separate quota for renewable fuels. Maritime transport is now also subject to the GHG quota. But fuels used in shipping that would be creditable for road transport cannot be used to meet the quota. This prevents companies from completely shifting their compliance obligation from road transport to shipping.

The draft is now under consultation with industry associations. The bill is expected to be submitted to parliament for debate in October, following adjustments based on feedback. A member of the environment committee said at a panel discussion on 4 June that the bill should ideally come into force on 1 January 2026. The draft proposes that changes to the GHG quota take effect at the start of a new compliance year to avoid market distortions that could occur if the law were to change mid-year.

By Svea Winter & Max Steinhau

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26/04/02

ARA crop-based Fame cheaper than diesel for first time

London, 2 April (Argus) — European crop-based biodiesel benchmarks traded below underlying gasoil prices for the first time as the US-Israel war on Iran and resulting supply disruptions in the Middle East have pushed conventional diesel values to multi-year highs. Fame 0 trade was initiated on price discovery platform Argus Open Markets at a discount of $25-78/t to Ice gasoil, for loading between 9 and 30 April. Rapeseed OME traded at discounts between $5-35/t in the same period. But it is difficult to increase purchases of crop-based Fame in the largest European markets because biodiesel blending for road fuel is restricted at 7pc of diesel under the EU's fuel quality directive. And biodiesel is one of the cheaper options for meeting increasingly higher biofuel mandates, and so many buyers already blend biodiesel at the maximum rate possible. There are a few options for where biodiesel demand could crop up. Companies can agree to use B100, or pure biodiesel. This is limited by the size of the compatible vehicle fleet. Some countries may not be hitting the 7pc blend wall, including non-EU European countries without biofuel mandates. These could voluntarily increase biodiesel blending — something also recently suggested by the European commission as a supply protection measure. Countries outside of Europe could also start using biodiesel, although logistics and transport costs could erode much of the discount. Biodiesel is often blended at higher rates in warmer climates. Biodiesel could go into industrial or power generation, although these sectors are typically less familiar with liquid biofuels than the transport sector. Higher blends can also be used in marine bunker fuel, possibly the easiest pivot given the growing role of bio-bunkers following the expansion of the EU ETS to shipping and the implementation of FuelEU maritime. However, crop-based biodiesel is less appealing in the maritime sector, because it does not qualify for FuelEU maritime compliance — FuelEU requires that biofuels be made from wastes or residues. But crop biodiesel can still be zero-rated in the EU ETS. When including ETS costs, waste-based biodiesel has been cheaper than marine gasoil for several weeks already, but buying has not significantly increased . Some say shipowners and buyers are hesitant to make significant changes to their procurement strategy based on an acute price spread, or are wary of using biodiesel in their engines. By Simone Burgin Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Carbon - In focus: UK ETS widens discount to EU in Q1

26/04/02

Carbon - In focus: UK ETS widens discount to EU in Q1

London, 2 April (Argus) — The benchmark front-year contract under the UK emissions trading scheme (ETS) significantly widened its discount to the EU throughout the first quarter of this year, as scant signs of progress on efforts to link the two systems reduced previous optimism of an impending price convergence, and the UK supply-demand balance remained more relaxed than the EU's. The UK ETS front-year contract closed on average around £14.75/t of CO2 equivalent (CO2e) below its EU counterpart in Argus assessments over January-March, having widened from a low of £6.85/t CO2e in mid-January to a high of £25/t CO2e this week. This compares with an average discount of £13.50/t CO2e in the fourth quarter of last year, within a narrower range of £8.80-17.70/t CO2e, and is the widest average discount for any quarter since the first quarter of last year's £21.80/t CO2e. Linkage plans squeeze spread The UK's discount to the EU began to narrow significantly after the UK government said in a statement in March 2025 that it was "actively considering" linking its ETS back to the EU's, a position confirmed by both sides as part of their common understanding agreement concluded between the UK and EU at a summit in May last year. The markets separated in 2021 as part of Brexit, and while the EU-UK trade and co-operation agreement signed as part of that process committed the two sides to giving "serious consideration" to linking the schemes, no meaningful steps towards a link had previously been taken. The news dramatically narrowed the spread between the two markets, with the UK front year's discount to the EU squeezed to an average of £9.90/t CO2e in the second quarter of 2025. A linkage would logically lead to a convergence of UK and EU ETS prices, as the allowances issued under the two schemes would be fungible. Momentum on the issue continued over the remainder of the year and early 2026, as the European Commission set out in July its recommendation for the legal basis for linkage negotiations, approved by member states in November , and the first round of negotiations kicked off in January . But while the EU and UK said that they aimed to complete talks on the linkage before the next UK-EU summit in 2026, no date for the meeting has been set, and updates on negotiations have in recent months been notable by their absence. Recent events have likely pushed ETS linkage down the political agenda, whether on the domestic front — Keir Starmer's position as UK prime minister came under pressure in February — or internationally, most notably as the US-Iran war sparked a renewed energy crisis. EU supply-demand balance tightens Changes to key fundamentals have also tightened the EU ETS supply-demand balance this year in a way that hasn't been seen in the UK ETS, further widening the spread between the markets. Both the maritime and aviation sectors will have to pay for 100pc of their 2026 emissions covered by the EU ETS, after shipping was phased gradually into the system over the previous two years and free allocations for airlines were phased out. Free allocations for industrial sectors covered by the EU's carbon border adjustment mechanism (CBAM) are also scheduled to start decreasing from this year alongside the measure's introduction, and some CBAM-exposed firms have begun purchasing EU ETS allowances to hedge their expected costs. The UK also ended free allocations for aviation under its ETS this year. But the maritime sector will not be included at all until July this year, and then will only apply to domestic voyages until at least 2028. And the UK CBAM does not launch until 2027. The UK ETS authority also opted late last year not to introduce a supply adjustment mechanism to the scheme, which could otherwise have reduced allowance auction volumes if the total number of allowances in circulation surpassed a certain level. Short-term fundamentals diverge The US-Iran war has prompted further divergence between the markets. EU ETS prices rallied in tandem with natural gas prices on the expectation that more coal plants would come on line, increasing the carbon intensity of the bloc's generation mix and therefore compliance demand for allowances. The UK, by contrast, has no operational coal-fired units. This has seen carbon costs even for power generators become consistently cheaper in the UK than the EU for the first time since February last year, despite the UK's additional £18/t CO2e carbon price support (CPS) charge on the sector. The discount of the UK ETS to the EU including the CPS stood at an average of around £3.25/t CO2e in March. UK ETS prices could find some support over the coming weeks from last-minute buying in the run-up to the scheme's annual compliance deadline on 30 April, upward pressure that will not be seen in the EU ETS with its 30 September deadline, which could narrow the spread between the markets in the short term. But participants will otherwise be awaiting more clarity on linkage. And with the Middle East conflict dragging on, the approach of local elections in the UK and the planned EU ETS review in July, plenty of factors could slow completion of the talks. By Victoria Hatherick EU, UK ETS front-year contract £/t CO2e Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Kansas will not join states ensuring E15 access

26/04/01

Kansas will not join states ensuring E15 access

New York, 1 April (Argus) — Kansas will not move to join a group of farm states transitioning next year to a boutique summer gasoline blend, which would have ensured continued access to a higher-ethanol blend in the state. Seven Midwestern states have approval to eventually move a lower-volatility summertime fuel that would allow retailers to keep selling both typical 10pc ethanol gasoline (E10) and blends with up to 15pc ethanol (E15). Kansas governor Laura Kelly (D-Kansas), frustrated by an impasse about federal biofuel policy, said earlier this year that she would give "strong consideration" to submitting a request by 1 April to join those states starting in 2027. But much has since changed in fuel markets. The US-Israel war with Iran has sent pump prices sharply higher, and President Donald Trump's administration has tried to contain the fallout by issuing emergency waivers that streamline summertime fuel rules across the country. Those waivers allow year-round sales of E15 in areas where it would have otherwise been limited while also effectively delaying the Midwestern states' fuel change — first planned for 2025 and then for 2026 — to next year. "With the granting of the temporary E15 waiver, E15 will continue to be sold through 2026", Kelly's office said. "While the governor strongly considered the permanent opt-out, she recognizes that it would not take effect until 2027 and felt that it is a decision best left to the next administration." A new governor will take office next year in Kansas. The Clean Air Act exempts E10 from summertime smog rules that would otherwise prevent its sale but does not extend the same treatment to E15 despite similar air quality impacts. The Midwestern bloc as a workaround had won approval to opt out of the special treatment for E10, effectively putting E10 and E15 on equal footing by requiring less-volatile but costlier blendstocks for both. The farm-state governors saw the workaround as a way to ensure continued E15 access no matter how federal policy changes. But the transition also threatened higher pump prices during peak summer driving season, a political risk even before the war. Kansas deciding not to join the other opt-out states comes despite a lack of progress in Congress on permanently exempting E15 from summertime smog rules, leaving decisions around access each summer to regulators. A task force of US lawmakers has struggled for months to reach agreement on biofuel legislation that would allow E15 sales year-round, in part because some oil refiners have objected to earlier proposals that would restrict their ability to win exemptions from biofuel blend mandates. E15 is typically cheaper than E10, although the blend is not sold at the vast majority of US fuel stations. Advocates blame the lack of availability on regulatory uncertainty deterring retailers from investing in higher ethanol blends. By Cole Martin Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Indian ethanol producers call for government support

26/04/01

Indian ethanol producers call for government support

Mumbai, 1 April (Argus) — Ethanol producers in India are urging the government to support the sector as lower demand and tight margins persist, particularly as global crude oil uncertainty creates an opportunity to prioritise sustainable fuels. The ethanol industry is calling for the diversification of ethanol usage, increases in blending mandates, and higher prices. The war in the Mideast Gulf has been a "wake up call," director of Shree Renuka Sugars, Atul Chaturvedi told Argus on 26 March. The government should use domestically produced ethanol wherever possible to ensure steady demand, he said. Chaturvedi particularly stressed considering ethanol for industrial use, including using ethanol burners for domestic and industrial cooking applications. Unlike for gasoline blending requirements, India does allow ethanol imports for non-blending purposes. India's ethanol production capacity has exceeded its fuel-blending requirements, creating a structural surplus which could be directed toward industrial applications, he added. But prices for domestic ethanol are regulated by the government, rendering it less competitive, while imported ethanol is consistently cheaper than its domestic counterpart. This regulation reduces the allure of domestic ethanol to be purchased for industrial use. The average price of domestic ethanol stands at $1,102/t according to the oil ministry's latest data, significantly higher than Argus ' last cfr Mumbai ethanol assessment of $770/t on 31 March. Most ethanol India imports for industrial use is from the US, which is typically the world's lowest-cost producer. Domestic fuel ethanol industry also faces pricing challenges Adding to a structural surplus, Indian ethanol producers are grappling with squeezed margins as costs have been rising, while ethanol sales prices remain capped. Sugar prices rose sharply in March after shipping disruptions at the strait of Hormuz pushed crude prices higher. Elevated crude prices typically push sugar mills to boost ethanol production and limit sugar output. But this price lift did not extend to sugarcane based ethanol in India, where prices are fixed through government tenders. Producers sell ethanol to oil marketing companies (OMCs) for gasoline blending at fixed prices even when production costs increase, creating a significant opportunity cost compared with selling sugar. The sugar industry has been asking the government to price ethanol from different feedstocks at parity for a long time, Chaturvedi said. The sugarcane-based ethanol prices should align with the fair and remunerative price at which maize ethanol is produced, he said. Grain-based distilleries benefit from lower raw material costs, making maize-based ethanol comparatively more advantageous under current conditions. The government price of C-heavy molasses-based ethanol, which is derived from sugarcane, is 57.97 rupee/litre ($895/t). Maize-based ethanol is priced at Rs71.86/litre ($1,110/t). Corn accounts for 31pc of ethanol feedstock, with sugar contributing 49pc and the rest coming from surplus rice and damaged foodgrain. Prices of ethanol from maize command a premium over sugarcane-derived grades, further destabilising the sector and reducing purchases from sugar mills that use molasses. India's accumulating unused ethanol stocks pose an economic challenge as the country's production capacity grows, Indian Federation of Green Energy (IFGE) Sugar Bioenergy Forum co-chairman Dilip Patil told to Argus . Without government involvement, ethanol plants become financially unviable. Infrastructural challenges and the lack of flex-fuel vehicle promotion are hindering the expansion of higher blending mandates such as E30, despite ongoing government discussions. Flex-fuel vehicles can run on a variety of ethanol-gasoline blends, typically ranging from E20 to E100. India's ethanol lobby has been urging the government to promote fuel flex vehicles even before the current conflict. Using ethanol for diesel blending could be another solution to manage the surplus, Chaturvedi added. This mirrors a recommendation from the All-India Distillers Association (AIDA) to the government last month for diesel blend to cut down fuel imports. International and domestic trials have already shown that low volumes of ethanol can be blended into diesel without major engine modifications, AIDA said. By Nikhil Sharma Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Bulk terminals firm HES prepares for energy transition

26/03/31

Bulk terminals firm HES prepares for energy transition

Paris, 31 March (Argus) — Bulk terminal company HES International operates 14 facilities in four European countries and anticipates important changes to its operations as the energy transition and hydrogen market evolve. Argus spoke with new energies business development director Otto Waterlander and chief commercial officer for HES Med Terminal Firas Ezzeddine about how an infrastructure player must adapt to serve customers. Edited highlights follow: What does HES do and what is its role in decarbonisation? Ezzeddine: We are an essential and critical part of the logistics value chain for the industrial heart of Europe. Our value proposition is that we are located in deep sea ports in close proximity to industrial zones, meaning that we are well positioned to serve strategic European industries and their logistical needs. Waterlander: We are purely an infrastructure player; we do not normally have a stake or exposure to the commodities that we manage through our terminals. Our customers tend to be carbon-intensive and they all are struggling with the question of decarbonisation. For HES, it is both a necessity and an opportunity. It is a necessity because classic flows of commodities will phase out over time. And an opportunity because of the energy transition... new things are happening, for example, [development of a] CO2 [market]. Today, we are not involved in handling CO2, but it is going to become a commodity in the future. What are the main challenges related to energy transition activities? Ezzeddine: I see challenges in three buckets. The first is timing: there is a bit of a lag between project deployment and when the infrastructure should be ready to facilitate flows. These are generally not well aligned. The second challenge is around financing. We see from both private and public sector a bit of a risk averseness in terms of investing in the infrastructure for the future. The final challenge is regulation regarding both the new flows of commodities and the actual development of infrastructure. Waterlander: There is also a question about what the utilisation of new infrastructure will be like, particularly in the early years. What you see in the industry is that often projects get delayed, either because they are not economic or because their utilisation challenges create an [unfavourable] economic situation. A recent example is the CO2 transport pipelines. They require large volumes to make it economic and those volumes are not there yet. You need to factor in some long periods of underutilisation of the infrastructure. H ow are you addressing this last challenge, for example for CO 2 infrastructure? Waterlander: We believe that the key to unlocking the market is to go smaller and create optionality. For example, with regard to CO2 terminal activities, we are advancing in Wilhelmshaven and Rotterdam. We already have infrastructure there to receive tankers and we have dedicated jetties to handle the unloading or loading of vessels. We just need to adjust them so that we can also move CO2. We believe that we can actually get our terminals economically viable at about 1.5mn or maybe 2mn t/yr of CO2 handling, when most of the projects will look at 10mn t/yr plus. If we could develop a smaller size terminal to begin with and then grow to larger sizes, we can help the market to come to grips with those volumes. And then gradually over time, volumes will move into pipelines as well. Will the CO 2 be liquefied at the HES terminals? Waterlander: There are two models. In one we have pipeline transport of gaseous CO2, then HES will liquefy the CO2 at its site before it goes onto the ships. That is the most efficient way because otherwise each player would have to have their own liquefaction. But before we have the gaseous pipelines, we will see customers installing their CO2 capture facilities, liquefy it on site, load it into rail tankcars or into barges on the Rhine, for example, to Rotterdam. In this case we receive it in liquid form already. We are planning to have CO2 infrastructure in place by 2029. In the first year, that is only for a small volume, but by 2030 it starts to become significant. We will launch an open season for our first two CO2 terminals in the coming weeks and we are aiming to analyse more specific capacity bookings through these. In France's Fos-sur-Mer, you are working with the Gravithy green iron initiative . What additional infrastructure is needed for that? Ezzeddine: We will be managing the inflow of material for them, which is the iron ore, and the export of their hot briquetted iron [HBI] production. What that entails, in essence, is having some cranes and conveyor belt infrastructure from and to their facility. For the iron ore side, it is not different from the infrastructure that we have for other sites. But the HBI requires dedicated infrastructure because of the nature of the product. What we are doing now is designing a conveyor belt network going from our terminal to theirs, which is around 2km away, where we send iron ore and we receive HBI, and we dedicate a specific slot on our terminal land where we have specific storage for them. Does GravitHy need to book capacity in advance to enable the expansions? Ezzeddine: We have a specific planning and demand forecasting system where we input the potential volumes going in and out. When a new client comes in, they add their inflow and outflow requirements to the model. Then we see whether that is feasible or not given the current infrastructure and the land capacity that we have. The client, in this case GravitHy, tells us they have a need for ‘X' million tonnes of throughput in our terminal, and it is up to us to design the optimal inflow and outflow process. We update the model quite frequently so that we have visibility on what is needed by when, especially because some projects require infrastructure that takes years to build. What are HES' plans for e-methanol? Waterlander: We're working on an e-methanol import project where it will be brought from across the Atlantic into Germany. We have a storage site in Germany that is a former refinery and has liquid storage facilities. We still have an element of the refinery operational that provides security of supply today. We're discussing with a partner the construction of a synthetic aviation fuel (e-SAF) facility as well, which they would locate on our premises. What about other hydrogen carriers or hydrogen-based fuels? Waterlander: We're very proactive on following everything in the hydrogen space. We had discussions about liquid hydrogen imports. We are also into advanced project steps on imports of ammonia into Germany and are in project definition for imports of liquid organic hydrogen carriers. For our Wilhelmshaven site, we already have signed a letter of intent with grid infrastructure company OGE to be connected to the hydrogen network. Ammonia in particular is rather expensive because you need crackers. Is HES planning to develop ammonia crackers? Waterlander: It depends, it is still such early days. If we do it, it would not be at our sole risk, that is clear. Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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German draft RED III bill to raise GHG quota

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