Korea updates laws to promote biofuels, energy security

Spanish Market: Biofuels, Hydrogen
10/01/24

South Korea passed amendments to its laws on 9 January which will make it easier to produce biofuels via co-processing, refiners said.

Refiners will no longer need to get government approval for co-processing, as biofuels feedstocks that were previously not officially registered as feedstock to oil refineries have now been so registered, they said.

Refiners now have the green light to supply co-processed biofuels domestically and internationally, and can use those fuels to meet South Korea's national biofuels mandates.

The Korean National Assembly passed an amendment to the Petroleum and Alternative Fuels Business Act on 9 January. This was to encourage more investment from the domestic oil industry in eco-friendly fuels — namely biofuels and renewable synthetic fuel — as well as achieve carbon neutrality.

The amendment will be promulgated after being transferred to the government and approved by the State Council, and implemented six months later.

It will allow the input of "eco-friendly refining raw materials" designated by the ministry of trade, industry and energy (Motie) into the oil refining process and help establish a stable supply chain of environmentally-friendly fuels.

New regulations have also been established to allow the use of waste plastic pyrolysis oil, waste lubricants and biomass in the refining process. These will also encourage private-sector investment in biofuels.

There was a meeting held with authorities and companies in the biofuels space to gather industry feedback on the amended laws on the afternoon of 10 January, sources from two South Korean companies said. The agenda included discussions on bio marine fuels and supply difficulties, challenges in using B100 biodiesel, and challenges related to greenhouse gas emissions from different feedstocks under the International Maritime Organisation's (IMO's) Carbon Intensity Indicator (CII) ratings.

Energy security, CCUS legislation

South Korea has also passed legislative acts to enhance energy and mineral supply security.

The country passed the Special National Resource Security Act, given "the trend of resource weaponisation in major countries and geopolitical crises such as the Russia-Ukraine war and the Israel-Hamas crisis", according to Motie on 9 January, especially since South Korea relies on imports for over 90pc of its energy.

The act designates oil, natural gas, coal, hydrogen, key minerals, as well as materials and components used in new and renewable energy facilities as "core resources". It also includes the stockpiling of resources, analysing supply chain vulnerabilities, operating early warning systems, as well as supporting the expansion of domestic and overseas production.

South Korea also passed an act on carbon capture, utilisation and storage (CCUS) to "prepare the legal foundation needed to respond to the climate crisis and foster the CCUS industry", Motie said. The act lays out the process for securing and operating CO2 storage, as well as special provisions for CO2 supply, among others. It also includes various regulations aimed at supporting corporate research and development.

The CCUS Act will be promulgated after receiving approval from the State Council, and implemented a year after its promulgation.

"The enactment of the CCUS Act has contributed to carbon neutrality and laid the basis for administrative and financial support for CCUS-related technology development and industrial development," energy policy officer Choi Yeon-woo said.

By Sarah Giam and Yong Li Tng

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03/01/25

US 45V update opens door to more H2 from natural gas

Houston, 3 January (Argus) — The US Treasury Department's updated requirements for hydrogen production tax credits amends the way upstream emissions are calculated, potentially making it easier for natural gas producers to qualify for the lucrative subsidy. Previous guidelines used fixed assumptions about the rate of methane leaked from wells and pipelines rather than accepting data from individual projects. The industry argued that using uniform figures under the existing GREET model to calculate emissions would unfairly penalize companies that had taken steps to reduce methane leakage. In final rules released Friday , the Treasury Department creates a pathway for companies to submit project-specific emissions data, an amendment that had been advocated for by ExxonMobil and the American Petroleum Institute, among others. Without this change, some companies considering ammonia export projects along the US Gulf Coast said they would instead consider applying for 45Q tax credits for carbon sequestration, which cannot be used in conjunction with 45V. Previous guidance only provided a pathway for renewable natural gas (RNG) produced from landfills to qualify for lucrative tax credits. The new rules include wastewater treatment, animal manure and coal mine methane. By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US relaxes rules for H2 production tax credits: Update

03/01/25

US relaxes rules for H2 production tax credits: Update

Adds information on state-specific additionality rules in paragraphs 6-8. Houston, 3 January (Argus) — The US Treasury Department has issued long-awaited tweaks to 45V hydrogen production tax credit (PTC) guidelines, relaxing rules in a bid to make it easier for producers to benefit from the subsidy. The final guidance released today retains the fundamental approach from the preliminary rules set out in December for the tax credits of up to $3/kg. The "three pillars" of additionality, temporal matching and regional deliverability remain in place for electrolytic hydrogen, but the Treasury has tweaked certain aspects. The additionality rule prescribes that hydrogen production facilities can only use electricity from clean power generation capacity that predated them by 36 months or less to encourage a further build-out of such capacity. But under the final rules, hydrogen made with power from existing nuclear plants can qualify for the credits under certain circumstances. 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"Electricity generated in states with robust greenhouse gas emissions caps paired with clean electricity standards or renewable portfolio standards" that meet specific criteria will automatically be considered as additional, the Treasury said. This is because in these states "the new electricity load" from electrolysers "is highly unlikely to cause induced grid emissions," it said, adding that rules on temporal matching and regional deliverability still apply. For now, "California and Washington are qualifying states under these final regulations," but other states could qualify in the future, according to the Treasury. Hourly matching — which prescribes that hydrogen has to be made from clean power produced within the same hour to avoid increased grid emissions — will now be required only from the start of 2030 onwards rather than from 2028. Annual matching will continue to apply until the end of 2029. The new phase-in date for hourly matching at the start of 2030 brings it in line with EU rules , although the bloc requires monthly rather than annual matching before then. US industry participants have repeatedly argued that the hourly matching rules drive up production costs and stymie the nascent industry's development, while environmentalists have warned that strict rules are necessary to curb greenhouse gas (GHG) emissions. The regional deliverability rules require electrolysers to source clean power from within their operating region — as defined by the Department of Energy — to avoid grid congestions between regions resulting in use of emissions-intensive power for hydrogen production. But the final guidelines would allow for direct "cross-region delivery" of power for hydrogen production where this "can be tracked and verified… on an hour-to-hour or more frequent basis". Under certain circumstances, US hydrogen producers could now even be eligible for the tax credits if they use electricity generated in Canada or Mexico, the Treasury said. ‘Significant improvements' A lobbying group representing the interests of hydrogen producers called the updated guidance "significant improvements" and said it would allow the industry to move forward to the next planning stage. "After years of strategic engagement and persistent advocacy, the issuance of this final rule now affords project developers the basis for evaluating opportunities to scale clean hydrogen deployments," Fuel Cell and Hydrogen Energy Association chief executive Frank Wolak said. A raft of hydrogen projects were announced in the US after President Joe Biden announced billions of dollars in funding and tax credits for hydrogen with the 2022 Inflation Reduction Act. But much of that euphoria fizzled out during the long wait for clarity on the rules and concerns that the Treasury's guidelines would be too strict to allow competitive production. Many would-be producers paused or cancelled US plans in 2024 because of widespread uncertainty over which projects would qualify for PTC, leaving companies unable to make long-term investment decisions. By Jasmina Kelemen and Stefan Krumpelmann Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US relaxes rules for H2 production tax credits

03/01/25

US relaxes rules for H2 production tax credits

Houston, 3 January (Argus) — The US Treasury Department has issued long-awaited tweaks to 45V hydrogen production tax credit (PTC) guidelines, relaxing rules in a bid to make it easier for producers to benefit from the subsidy. The final guidance released today retains the fundamental approach from the preliminary rules set out in December for the tax credits of up to $3/kg. The "three pillars" of additionality, temporal matching and regional deliverability remain in place for electrolytic hydrogen, but the Treasury has tweaked certain aspects. The additionality rule prescribes that hydrogen production facilities can only use electricity from clean power generation capacity that predated them by 36 months or less to encourage a further build-out of such capacity. But under the final rules, hydrogen made with power from existing nuclear plants can qualify for the credits under certain circumstances. Hydrogen producers can access the credits if nuclear power companies demonstrate that adding hydrogen production to their revenue stream extends the life of reactors otherwise slated for shutdown. Companies such as utility Constellation Energy have argued that using some of their nuclear capacity for hydrogen would provide a pathway for future relicensing of their reactors , but that this would hinge on access to the tax credits. The final guidelines now also consider existing fossil fuel-based power plants where carbon capture capabilities have been retrofitted within the 36-month window prior to starting up hydrogen production as additional capacity. This makes hydrogen output using electricity from these plants eligible for the tax credits. Hourly matching — which prescribes that hydrogen has to be made from clean power produced within the same hour to avoid increased grid emissions — will now be required only from the start of 2030 onwards rather than from 2028. Annual matching will continue to apply until the end of 2029. The new phase-in date for hourly matching at the start of 2030 brings it in line with EU rules , although the bloc requires monthly rather than annual matching before then. US industry participants have repeatedly argued that the hourly matching rules drive up production costs and stymie the nascent industry's development, while environmentalists have warned that strict rules are necessary to curb greenhouse gas (GHG) emissions. The regional deliverability rules require electrolysers to source clean power from within their operating region — as defined by the Department of Energy — to avoid grid congestions between regions resulting in use of emissions-intensive power for hydrogen production. But the final guidelines would allow for direct "cross-region delivery" of power for hydrogen production where this "can be tracked and verified… on an hour-to-hour or more frequent basis". Under certain circumstances, US hydrogen producers could now even be eligible for the tax credits if they use electricity generated in Canada or Mexico, the Treasury said. ‘Significant improvements' A lobbying group representing the interests of hydrogen producers called the updated guidance "significant improvements" and said it would allow the industry to move forward to the next planning stage. "After years of strategic engagement and persistent advocacy, the issuance of this final rule now affords project developers the basis for evaluating opportunities to scale clean hydrogen deployments," Fuel Cell and Hydrogen Energy Association (FCHEA) chief executive Frank Wolak said. A raft of hydrogen projects were announced in the US after President Joe Biden announced billions of dollars in funding and tax credits for hydrogen with the 2022 Inflation Reduction Act. But much of that euphoria fizzled out during the long wait for clarity on the rules and concerns that the Treasury's guidelines would be too strict to allow competitive production. Many would-be producers paused or cancelled US plans in 2024 because of widespread uncertainty over which projects would qualify for PTC, leaving companies unable to make long-term investment decisions. By Jasmina Kelemen and Stefan Krumpelmann Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Q&A: EU biomethane internal market challenged

02/01/25

Q&A: EU biomethane internal market challenged

London, 2 January (Argus) — The European Commission needs to provide clearer guidance on implementing existing rules for the cross-border trade of biomethane to foster a cohesive internal market as some EU member states are diverging from these standards, Vitol's Davide Rubini and Arthur Romano told Argus. Edited excerpts follow. What are the big changes happening in the regulation space of the European biomethane market that people need to watch out for? While no major new EU legislation is anticipated, the focus remains on the consistent implementation of existing rules, as some countries diverge from these standards. Key challenges include ensuring mass-balanced transport of biomethane within the grid, accurately accounting for cross-border emissions and integrating subsidised biomethane into compliance markets. The European Commission is urged to provide clearer guidance on these issues to foster a cohesive internal market, which is essential for advancing the EU's energy transition and sustainability objectives. Biomethane is a fairly mature energy carrier, yet it faces significant hurdles when it comes to cross-border trade within the EU. Currently, only a small fraction — 2-5pc — of biomethane is consumed outside of its country of production, highlighting the need for better regulatory alignment across member states. Would you be interested in seeing a longer-term target from the EU? The longer the visibility on targets and ambitions, the better it is for planning and investment. As the EU legislative cycle restarts with the new commission, the initial focus might be on the climate law and setting a new target for 2040. However, a review of the Renewable Energy Directive (RED) is unlikely for the next 3-4 years. With current targets set for 2030, just five years away, there's insufficient support for long-term investments. The EU's legislative cycle is fixed, so expectations for changes are low. Therefore, it's crucial that member states take initiative and extend their targets beyond 2030, potentially up to 2035, even if not mandated by the EU. Some member states might do so, recognising the need for longer-term targets to encourage the necessary capital expenditure for the energy transition. Do you see different interpretations in mass balancing, GHG accounting and subsidies? Interpretations of the rules around ‘mass-balancing', greenhouse gas (GHG) emissions accounting and the usability of subsidised biomethane [for different fuel blending mandates] vary across EU member states, leading to challenges in creating a cohesive internal market. When it comes to mass-balancing, the challenges arise in trying to apply mass balance rules for liquids, which often have a physically traceable flow, to gas molecules in the interconnected European grid. Once biomethane is injected, physical verification becomes impossible, necessitating different rules than those for liquids moving around in segregated batches. The EU mandates that sustainability verification of biomethane occurs at the production point and requires mechanisms to prevent double counting and verification of biomethane transactions. However, some member states resist adapting these rules for gases, insisting on physical traceability similar to that of liquids. This resistance may stem from protectionist motives or political agendas, but ultimately it results in non-adherence to EU rules and breaches of European legislation. The issue with GHG accounting often stems from member states' differing interpretations of the IPCC Guidelines for National Greenhouse Gas Inventories. Some states, like the Netherlands, argue that mass balance is an administrative method, which the guidelines supposedly exclude. Mass balancing involves rigorous verification by auditors and certifying bodies, ensuring a robust accounting system that is distinct from book and claim methods. This distinction is crucial because mass balance is based on verifying that traded molecules of biomethane are always accompanied by proofs of sustainability that are not a separately tradeable object. In fact, mass balancing provides a verifiable and accountable method that is perfectly aligned with UN guidelines and ensuring accurate GHG accounting. The issue related to the use of subsidised volumes of biomethane is highly political. Member states often argue that if they provide financial support — directly through subsidies or indirectly through suppliers' quotas — they should remain in control of the entire value chain. For example, if a member state gives feed-in tariffs to biomethane production, it may want to block exports of these volumes. Conversely, if a member state imposes a quota to gas suppliers, it may require this to be fulfilled with domestic biomethane production. No other commodity — not even football players — is subject to similar restrictions to export and/or imports only because subsidies are involved. This protectionist approach creates barriers to internal trade within the EU, hindering the development of a unified biomethane market and limiting the potential for growth and decarbonisation across the region. The Netherlands next year will implement two significant pieces of legislation — a green supply obligation for gas suppliers and a RED III transposition. The Dutch approach combines GHG accounting arguments with a rejection of EU mass-balance rules, essentially prohibiting biomethane imports unless physically segregated as bio-LNG or bio-CNG. This requirement contradicts EU law, as highlighted by the EU Commission's recent detailed opinion to the Netherlands . France's upcoming blending and green gas obligation, effective in 2026, mandates satisfaction through French production only. Similarly, the Czech Republic recently enacted a law prohibiting the export of some subsidised biomethane . Italy's transport system, while effective nationally, disregards EU mass balance rules. These cases indicate a deeper political disconnect and highlight the need for better alignment and communication within the EU. We know you've been getting a lot of questions around whether subsidised bio-LNG is eligible under FuelEU. What have your findings been? The eligibility of subsidised bio-LNG under FuelEU has been a topic of considerable enquiry. We've sought clarity from the European Commission, as this issue intersects multiple regulatory and legal frameworks. Initially, we interpreted EU law principles, which discourage double support, to mean that FuelEU, being a quota system, would qualify as a support scheme under Article 2's definition, equating quota systems with subsidies. However, a commission representative has publicly stated that FuelEU does not constitute a support scheme and thus is not subject to this interpretation. On this basis, FuelEU would not differentiate between subsidised and unsubsidised bio-LNG. A similar rationale applies to the Emissions Trading System, which, while not a quota obligation, has been deemed to not be a support scheme. Despite these clarifications, the use of subsidised biomethane across Europe remains an area requiring further elucidation from European institutions. It is not without risks, and stakeholders require more definitive guidance to navigate the regulatory landscape effectively. By Emma Tribe and Madeleine Jenkins Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Pure green steel costs almost double NW EU HRC price

02/01/25

Pure green steel costs almost double NW EU HRC price

London, 2 January (Argus) — Zero emission hydrogen-fed electric arc furnace-produced crude steel would currently cost almost double the price of northwest EU hot-rolled coil (HRC), according to data launched by Argus today. The opex cost of green hydrogen-fed direct reduced iron/electric arc furnace (EAF) route steel was €1,074/t at the end of December, compared to a northwest EU HRC price of €558.25/t ex-works. That is also €544/t more than the cost of blast furnace/basic oxygen furnace (BOF)- produced crude steel, showing genuinely green steel would require a much higher finished product price than current blast furnace-based output, assuming a similar cost structure to today. Most current green offerings from EU mills are still produced via the blast furnace, with emissions reductions achieved through mass balancing, offsetting, or by reductions achieved elsewhere in the supply chain. Buy-side desire to pay premiums for this material has been limited, particularly given the downturn in the European market in the second half of 2024. This has contributed to the market for premiums remaining immature, illiquid and opaque, and complicated by the lack of a commonly agreed definition for green steel. Automakers have shown the most interest in greener steel, given their need to reduce emissions from the wider supply chain, as well as vehicle tailpipe emissions. Some automotive sub-suppliers suggest certain mills have been willing to reduce their green premiums to move tonnes — one reported paying a €70/t premium for EAF-based cold-rolled coil for a 2025 contract, but this was not confirmed. Europe's largest steelmaker, ArcelorMittal, said over the second half of last year it would pause its direct reduced iron (DRI) investment decisions ahead of the European Commission's Steel and Metals Action Plan, and as it called for an effective carbon border adjustment mechanism and more robust trade defence measures. Market participants largely agree that natural-gas fed EAF-based production is the greenest form of output currently available to EU mills, substituted with imports of greener metallics and semi-finished steels from regions with plentiful and competitively priced energy. Argus ' new costs show BOF steel is currently just over €31/t more expensive than scrap-based EAF production fed with renewable energy. Europe's comparatively high cost of energy is one key issue for transitioning to DRI/EAF fed production. Last month, consultancy Mckinsey said mills could rely on "green iron" hubs going forward, with iron-making decoupled from production of crude steel, enabling DRI production to be located in regions with low-cost gas and ore, and raw steel production in regions with access to renewable energy. The range of production costs, launched today, include five crude steel making pathways and are calculated using consumption and emissions data provided by Steelstat , in combination with Argus price data, including hydrogen costs. By Colin Richardson Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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