IPL plans 2022 closure of Australian fertilizer plant

Spanish Market: Fertilizers, Natural gas
08/11/21

Australian fertilizer, explosive and industrial chemical group Incitec Pivot (IPL) plans to shut its Gibson Island fertilizer plant in Brisbane, Queensland in December 2022 when a prevailing feedstock gas supply contract expires.

The decision to cease manufacturing with natural gas at the end of 2022 comes as it has been unable to secure an economically viable long-term gas supply agreement. The firm will undertake a feasibility study into industrial-scale production of green ammonia at Gibson Island and this will be progressed to potentially repurpose the facility, IPL said.

The closure of manufacturing activities at the 50-year old Gibson Island plant will see IPL source urea, sulphate of ammonia and other specialty products from its existing international import supply chains to replace the manufactured products, IPL added.

IPL signed its existing agreement to buy gas from partners in the 9mn t/yr Australia Pacific LNG (APLNG) venture for its Gibson Island plant in June 2019. The planned plant closure also comes around a year after IPL announced plans to restart Queensland's Range gas project with its 50:50 partner Australian independent Central Petroleum, as part of efforts to supply gas to Gibson Island beyond the end of 2022.

The planned closure of Gibson Island comes at a time when domestic gas prices in eastern Australia are at around the same level as when IPL signed the gas agreement with APLNG. The AWX, the Argus assessment for month-ahead spot gas deliveries to Wallumbilla, was at A$9.53/GJ for December deliveries on 5 November, up by A13.5¢/GJ from A$9.39/GJ for November deliveries the previous week. The AWX assessment was around A$9.25/GJ at the start of June 2019.

Around 80pc of the gas produced in eastern Australia is either shipped as LNG or used as fuel for electricity for the three LNG plants located at the Queensland port of Gladstone. The amount of gas used by Australian manufacturers was around 6pc of the gas produced in the 2019-20 fiscal year to 30 June.

The lack of competitive gas supplies to Australian manufacturers also casts light on the Australian government's gas-led economic plan, whereby Canberra funds studies for exploration work in undeveloped basins to boost supplies to underpin domestic economic activity.

By Kevin Morrison

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03/01/25

Eni ready for FID on Mozambique’s Coral Norte FLNG

London, 3 January (Argus) — Italian energy firm Eni is ready to take a final investment decision (FID) on its planned 3.4mn t/yr Coral Norte floating liquefaction (FLNG) terminal in Mozambique, should the project receive authorisation from the country's government, the firm has told Argus . Eni said it expects the government's approval to be "imminent", although it did not provide a more detailed timeline. The firm said in June 2023 that it planned to start operations at the FLNG in the second half of 2027. Eni already operates Mozambique's 3.4mn t/yr Coral Sul FLNG, which started operations in late 2022 and is at present the country's only LNG terminal. Coral Norte is set to be installed 20km north of Coral Sul. There are also two onshore terminals planned for Mozambique — the TotalEnergies-led 13.1mn t/yr Mozambique LNG project and ExxonMobil's 18mn t/yr Rovuma LNG project. Both are located in the Cabo Delgado province and have been halted because of security concerns. TotalEnergies reached a financial close on their Mozambique project in 2019 and declared force majeure in 2021, though project partner Bharat Petroleum (BPCL) said in late October 2024 the force majeure could be lifted in January or February this year because of an improvement in the security situation. And ExxonMobil said in November last year it was planning to take FID on the Rovuma project at the start of 2026. By Cerys Edwards Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Abu Dhabi's Adnoc raises January sulphur price by $9/t

03/01/25

Abu Dhabi's Adnoc raises January sulphur price by $9/t

London, 3 January (Argus) — Abu Dhabi's state-owned Adnoc set its January official sulphur selling price (OSP) for the Indian subcontinent at $174/t fob Ruwais, up by $9/t from its December OSP of $165/t fob. Adnoc's January OSP implies a delivered price of $191-193/t cfr India, with the freight cost for a 40,000-45,000t shipment to the east coast of India having last been assessed at $17-19/t on 19 December. The announced OSP fob price has risen by $97/t in the space of a year, from $77/t fob Ruwais in January last year. By Maria Mosquera Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Brasil busca leilão de hidrovias e terminais portuários

03/01/25

Brasil busca leilão de hidrovias e terminais portuários

Sao Paulo, 3 January (Argus) — O governo federal planeja uma série de leilões de terminais portuários e hidrovias para 2025, totalizando R$8,5 bilhões. O Ministério de Portos e Aeroportos e a Agência Nacional de Transportes Aquaviários (Antaq) serão responsáveis pelos leilões, buscando parcerias público-privadas (PPPs) que aumentarão a eficiência e expandirão as opções de transporte do país. O Brasil espera realizar 21 leilões e uma concessão em 2025. Muitas áreas do país carecem de infraestrutura adequada para o transporte de grãos e fertilizantes e são altamente dependentes do transporte rodoviário para o fluxo de carga. Portos PAR14: O terminal do porto de Paranaguá, no Paraná, movimenta e armazena granéis vegetais sólidos, como soja, farelo de soja, açúcar, trigo e milho. O leilão está programado para o primeiro trimestre de 2025, com um investimento estimado de R$529,2 milhões e uma concessão de 35 anos. O terminal terá capacidade para movimentar 6,8 milhões de toneladas (t)/ano. PAR15: Esse outro terminal de Paranaguá se concentra na movimentação e armazenamento de granéis vegetais. O projeto prevê investimentos de R$293,2 milhões e terá capacidade para movimentar 4 milhões de t/ano. O período de concessão será de 35 anos e o leilão está programado para 21 de fevereiro. PAR25: Outro terminal em Paranaguá voltado para a movimentação e armazenamento de granéis vegetais. Com capacidade para movimentar 4,3 milhões de t/ano, espera-se que os investimentos cheguem a R$564,1 milhões. O terminal será concedido por 35 anos e o leilão está programado para o segundo trimestre. MCP01: Localizado no porto de Santana, no Amapá, movimenta granéis sólidos vegetais, especialmente madeira. O terminal foi objeto de um leilão realizado em 2018, mas nenhuma proposta foi apresentada e o projeto foi reavaliado. Um novo leilão está programado para o segundo trimestre, com investimentos esperados de R$84,6 milhões e um período de concessão de 25 anos. VDC29: Um terminal no porto de Vila do Conde, no Pará, com um investimento estimado de R$716 milhões. Terá capacidade para movimentar 7 milhões de t/ano, com foco na movimentação e armazenamento de granéis vegetais sólidos, especialmente soja e milho. O leilão está programado para o terceiro trimestre, com um prazo de concessão de 25 anos. POA26: No porto de Porto Alegre, no Rio Grande do Sul, será usado para movimentar e armazenar granéis sólidos vegetais e minerais. O período de concessão será de dez anos, com investimentos estimados em R$21,1 milhões. O leilão está programado para o terceiro trimestre. SSB01: O leilão desse terminal no porto de São Sebastião, em São Paulo, está programado para o quarto trimestre. O prazo da concessão será de 35 anos, com um investimento de R$544,8 milhões. Seu foco será a movimentação e o armazenamento de granéis sólidos vegetais e minerais, com uma capacidade estimada de 4,3 milhões de t/ano. IQI16: O terminal está localizado no porto do Itaqui, no Maranhão, com um leilão programado para o quarto trimestre. A área será dedicada ao armazenamento e movimentação de granéis minerais sólidos, especialmente fertilizantes. O período de concessão será de 25 anos, com um investimento estimado em R$63,9 milhões. Canal de acesso aos portos de Paranaguá e Antonina: O projeto de concessão da infraestrutura de acesso aquaviário aos portos do estado do Paraná é inédito no Brasil. O Capex é estimado em R$1,1 bilhão, com um prazo de concessão de 25 anos. O leilão está programado para o segundo trimestre. A concessão abrangerá as funções de administração portuária relacionadas à gestão da infraestrutura, expansão, manutenção e operação do canal de acesso aos portos do Paraná. Hidrovias Hidrovia do Rio Madeira: Importante para o transporte de grãos e combustíveis, tem uma extensão navegável de 1.075 km, ligando a cidade de Porto Velho, em Rondônia, a Itacoatiara, no Amazonas. A Hidrovia do Madeira movimentou mais de 10 milhões de t em 2023, mas pode movimentar mais de 25 milhões de t/ano, de acordo com a Antaq. Os termos do projeto de concessão ainda estão sendo desenvolvidos e o leilão está programado para o segundo trimestre, com um prazo de 10 a 20 anos. Hidrovia do Paraguai: A hidrovia é importante para o transporte de minério de ferro e soja. Tem 1.323 km de extensão e vai da cidade de Ponta Porã, em Mato Grosso do Sul, até a cidade de Cáceres, em Mato Grosso. A via movimentou mais de 7 milhões de t em 2023, com potencial para atingir mais de 25 milhões de t/ano, de acordo com a Antaq. A hidrovia também conecta o Brasil à Argentina, Uruguai e Paraguai. O modelo de leilão também está sendo desenvolvido e está programado para o quarto trimestre. O período de concessão seria de 10 a 20 anos. Por João Petrini Envie comentários e solicite mais informações em feedback@argusmedia.com Copyright © 2025. Argus Media group . Todos os direitos reservados.

EU sulphur shortage persists, limiting sul acid output

02/01/25

EU sulphur shortage persists, limiting sul acid output

London, 2 January (Argus) — Liquid sulphur in Northwest Europe is expected to remain short in 2025, with production limited by lower output from refineries, and demand outstripping supply. Sulphur supply curbed In the past two years sulphur output from European refineries has dropped as a result of poor refining margins and competition from imports from new mega-refineries out of region. Additionally, sanctions on Russian crude oil imports to European refineries have turned the crude slate in the region sweeter. In 2024 refinery maintenance and unexpected outages resulted in lower production of molten sulphur. These were overdue following healthy refining margins in 2023 leading refineries to run at high rates and postponing maintenance, as well as earlier pandemic restrictions also limiting maintenance. Further European refining capacity is at risk in 2025, as Petroineos' Grangemouth refinery in Scotland is expected to be converted to an import terminal, while in Germany, Shell will cease crude processing at its 80,000 t/yr Wesseling refinery. Additionally, BP has indicated plans to permanently shut down a crude unit and a middle distillate desulphurisation unit at its 210,000 t/yr Gelsenkirchen plant. Refineries could still delay some of these closures, provided that refining margins were supportive of this. Sulphur consumption is higher though risks remain Sulphur consumers were running at low rates in Europe over 2023 due to low demand and poor economics as well as high energy prices. By 2024 sulphur demand lifted, and many consumers were unable to source the larger quantity of sulphur. The shortfall of molten sulphur bolstered quarterly contract prices during 2024; in the first quarter prices stood at $103.5-119.5/t cfr, rising 49pc on a mid-point basis to reach $158.5-174.5/t cfr in the fourth quarter. Contract negotiations for the first quarter of 2025 started against a backdrop of a short market and firmer global prices weighed against competitiveness of the region's chemical industry, with consumers seeking a rollover or a smaller increase of $10-15/t cfr against suppliers pushing for a larger $25-30/t rise. In 2025 liquid sulphur is expected to continue to be short in the region, with regular liquid imports. Discussions for an additional sulphur tanker are also expected to lead to more imported product entering the region by the second half of 2025. Yara's sulphur remelter in Finland is expected to start in April 2025, but will have limited impact on the industrial cluster in the Benelux and German regions. Additionally, at least one new commercial sulphur burner is expected in Germany for a 2027 start to operations, with the Mitsui subsidiary Aglobis announcing preliminary agreements with port and logistics operators in Germany's Duisburg area. Sulphuric acid implications The shortage in liquid sulphur has resulted in a new reality sulphuric acid in Northwest Europe, resulting in a wider differential between sulphur-burnt and smelter-based acid, of up to €80/t, on the quarterly contracts. The acid contracts for the first quarter of 2025 are not fully settled, the sulphur burnt contract was heard at a further increase of €15 added to the sulphur Benelux settlement, while an increase of around €10/t was heard for smelter-based acid. Some sulphur-burners have been forced to shut down in the Benelux region, mainly due lack of liquid sulphur. Additionally, there is the risk that some end used may be pushed out of the market due to the increased cost of sourcing sulphur burnt acid. And while some demand may continue to shift to smelter-based acid, not all sulphur burners or downstream industries can easily replace liquid sulphur as a feedstock due to purity or economic implications. By Jasmine Antunes, Maria Mosquera and Lili Minton 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.

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