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Asia to pull in more US, European bitumen
Asia to pull in more US, European bitumen
London, 7 October (Argus) — A price rally in Asia bitumen, supported by particularly tight supply from Singapore and South Korea, is drawing in much cheaper arbitrage cargoes from both Europe and the US. Price spreads between Asia and the rest of the world are now at multi-year highs, while tight supply in export hubs Singapore and South Korea looks set to continue through until at least the end of October, while Mideast Gulf supply remains heavily restricted by US sanctions and shipping limitations through the strait of Hormuz. Singapore bitumen prices had a premium of $263/t over Mediterranean cargoes and $361/t over US Gulf exports as at 2 October (see chart). Disruptions to crude supply via the strait of Hormuz have limited suitable crude feedstock for refiners in Asia, while a major Singapore refinery will further reduce supply this month as a result of maintenance. In the Mediterranean differentials to high-sulphur fuel oil (HSFO) have been falling through September as more supply became available, particularly from Greek, Italian and Spanish export points, while regional demand has been weaker on funding issues and some pushback on high outright prices after US-Iran tensions increased. Greek premiums to HSFO were around $30/t in August, but now Argus assessments stand at $7.50/t above HSFO. September and October would usually be among the busiest months for the European export market, before a winter slowdown when road works are reduced, but this year poorer funding and high outright prices have slowed demand. US Gulf prices are now particularly attractive and with seasonal paving and roofing demand starting to fall there — and with supplies ample — prices look set to remain weak. Strong margins have also led many US refiners to run at high rates and produce more bitumen, along with higher value products. Earlier this year the arbitrage to Asia also briefly opened , but now with the price premium in Asia higher, more cargoes are expected into the region through until at least November, according to traders. Import demand from Oceania and southeast Asian markets is expected to remain firm in the coming months because the peak road-paving season is now under way. Importers are actively seeking supply alternatives as traditional producers Singapore and Thailand have limited output. Argus assessed the fob Singapore ABX 1 at $830/t on 2 October, up by $26.50/t from the previous week. Singapore bitumen prices have climbed consistently since early September, thanks to firmer import demand from southeast Asian importers, particularly in Vietnam, as well as supply tightness. The fob South Korea ABX 2 assessment stood at $815/t on 2 October, up by $32/t on the week. ABX 2 prices have been climbing steadily since mid-August , owing to firmer buying interest from key consumer east China, where higher domestic offers and tight domestic output have supported the market. Movements include the 17,779 deadweight tonne (dwt) White Allegra heading from Greece, having loaded 11 September, and set to arrive at Singapore on 8 October, according to vessel tracking data. The 36,771 dwt Asphalt Synergy loaded in the US Gulf in mid-September and is expected to Tauranga, New Zealand on 15 October. The 36,754dwt White Pearl loaded a multi-port cargo from Tarragona, Spain, on 7 August, and made its final stop at Napier, New Zealand, on 6 October. The 13,265dwt Jin Zhou Wan is also expected to move to Oceania and loaded in the US Gulf on 26 September, while the 12,972 dwt Da Hua Shan arrived at Geelong in Australia on 3 October having loaded in Louisiana, US, in mid-August. By Jonathan Weston and Claire Ng Bitumen prices $/t Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Mexico price cap squeezes private gasoline imports
Mexico price cap squeezes private gasoline imports
Mexico City, 6 October (Argus) — Mexico's private gasoline imports fell by 34pc on the year in August as delivered gasoline prices rose by 45pc, while state-owned Pemex's pricing structure and the government's Ps24/liter ($5.06/USG) retail agreement continued to leave private suppliers with little room to compete. Energy ministry data show that private imports of gasoline, combining regular and premium, fell to 105,200 b/d in August from 159,600 b/d a year earlier. Their share of total gasoline imports dropped to 26.5pc from 36.2pc. Pemex's own imports rose by 4pc to 291,800 b/d, while total gasoline imports fell by 10pc to 397,000 b/d. Private imports rose by 80pc on the year in February and by 67pc in March, reaching 202,500 b/d and 190,300 b/d, respectively. They then fell below year-earlier levels, declining by 22pc in April and by 42pc in May. Volumes remained 33-40pc lower on the year from June to August, indicating that the post-March decline was not simply seasonal. Still, the January-August average was down by only 3pc, because of the high February and March volumes. The downturn coincided with a sharp rise in the US Gulf coast 87-octane waterborne delivered price for Mexico's east coast. The average price climbed from $1.85/USG in February to $3.13/USG in May, then eased to $2.88/USG in August, according to Argus assessments. The August price was still 45pc higher than a year earlier. Private importers and terminal operators have told Argus that Pemex's regular gasoline prices have at times been artificially low and difficult to compete with. Terminal operators also said volumes handled at their facilities had fallen well below customary levels as private companies imported less fuel. Pemex partly offset the decline in private supply. Its gasoline imports rose by 13pc on the year in May and by 42pc in June, while total gasoline imports were nearly unchanged in May and increased by 9pc in June. That points to a shift in the composition of imports, rather than an equivalent decline in imported supply overall, even as Pemex's refining output has increased. The tax-inclusive cost of 87-octane gasoline delivered to Mexico's east coast averaged Ps20.45/liter from January to 14 September, up by 8pc from the same period in 2025, according to Argus calculations. It reached Ps21.58/liter on 14 September, close to Pemex's regular terminal price of Ps21.68/liter. This left only Ps2.42/liter below the retail agreement before inland logistics and retail margins. Pemex sells regular gasoline at its more than 70 terminals at a single terminal price of Ps21.68/liter regardless of purchase volume. Premium is priced differently across terminals and carries a volume-based surcharge, with larger buyers paying lower increments. Private suppliers can still compete in premium gasoline, but its market is much smaller. Pemex's domestic premium sales averaged 143,500 b/d in January-August, down by 7pc on the year, while regular gasoline averaged 585,200 b/d, up by 16pc. In August, premium sales fell by 15pc and regular sales rose by 24pc from a year prior. Energy ministry import figures do not separate regular from premium, and Pemex's internal sales do not represent total national demand. The data therefore cannot quantify how much of the private import decline came specifically from regular gasoline. Still, the data show private suppliers losing share as Pemex raised its own imports and regular gasoline sales. By Antonio Gozain Mexico's private gasoline imports fall as prices spike Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
US red-dye diesel waiver offers limited relief
US red-dye diesel waiver offers limited relief
Houston, 6 October (Argus) — US president Donald Trump's order to temporarily allow on-road use of red dyed diesel is unlikely to significantly cut prices at the pump, despite claims the measure will help truckers and consumers. Market participants said the waiver does little to tackle the main cause of diesel's recent price rise — tight supply. The measure adds no new diesel production, imports or inventories, instead allowing a wider group of consumers to draw from existing off-road stocks. Trump's 5 October executive order permits dyed diesel, normally reserved for off-road use, to be used in highway vehicles . The order defers the federal 24.4¢/USG excise tax on diesel until year end and suggests Congress pass legislation to "eliminate the obligation to pay" the deferred tax. "This targeted action will put money directly in the pocket of American farmers, truckers, and workers," Trump said in the order. But any savings may be smaller than advertised — or not materialize at all — since the federal diesel tax is being deferred rather than cancelled. Although the administration has directed Treasury officials to explore ways to write off the obligation, no such relief has been enacted. The policy's reach is further constrained by state rules. While some states, including Texas, have eased restrictions for on-road use of dyed diesel, most still ban the practice and impose heavy fines, so uptake is expected to vary widely across the country. Distribution logistics form another barrier. Red dyed diesel typically moves through wholesale channels serving agricultural, construction and heating markets rather than retail filling stations. Increased highway demand could tighten off-road supplies and raise costs for farmers and other consumers without adding to total diesel availability. Price data suggest the waiver will fall far short of offsetting the jump in diesel costs. Prices for ultra-low sulphur heating oil (ULSH), often used as a proxy for dyed diesel, are more than double year-earlier levels. US Gulf coast Colonial ULSH averaged $4.43/USG over the past four weeks, nearly 109pc higher than the $2.12/USG average in the same period last year. Some truckers and fuel retailers are also wary of using dyed diesel because of compliance concerns. Industry participants cite uncertainty over how long traces of red dye may remain detectable in storage tanks and fuel systems after use, creating potential issues once the waiver ends. Interstate operators face an added risk if trucks fueled in a state that allows dyed diesel later enter one that prohibits it, where heavy penalties still apply. Since the waiver does nothing to boost refinery output, imports or inventories, the president's move appears more likely to shift demand between fuel pools than to meaningfully cut consumers' diesel costs. By Craig Ross Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Q&A: DCC Energy urges support for BioLPG in RED IV
Q&A: DCC Energy urges support for BioLPG in RED IV
London, 6 October (Argus) — Renewable liquid gases such as bioLPG could play a greater role in decarbonising heating and industry, particularly in sectors where electrification is difficult or costly, but stronger demand signals and long-term policy certainty are needed to support investment and production growth, according to Dublin-based LPG distributor DCC Energy. Argus' Evelina Lungu spoke with Emmanuel Mannooretonil, director of sustainable gas at DCC Energy and a board member of Liquid Gas Europe, about bioLPG supply growth, renewable heating policy and the outlook for renewable liquid gases in Europe. Edited highlights follow. To what extent does the current Renewable Energy Directive (RED) framework support investment in renewable liquid gases, and where are the remaining gaps? RED III sets clear and ambitious targets for renewable energy in transport fuels, which have facilitated significant investment in production over recent years. However its provisions for renewable liquid and gaseous fuels in buildings and industry are framed more as indicative targets for member states. The challenge has been to translate these targets into predictable market signals, ideally at European level, while giving member states sufficient flexibility to deploy the solutions best suited to their national circumstances, including renewable liquid and gaseous fuels. Greater long-term certainty around the role of these fuels would help support investment in large-scale production projects. As well as demand-side policy, supply-side incentives — such as the UK's Revenue Certainty Mechanism being designed for sustainable aviation fuel (SAF) producers — will also be necessary in order to de-risk investment for producers. This is especially true when considering production growth from technologies not yet available at commercial scale. How do you see BioLPG fitting into the EU's broader decarbonisation strategy for heating and industry, particularly alongside the strong policy push towards electrification? We strongly believe that electrification will be a key pathway for decarbonisation of heating, and indeed DCC Energy is rapidly growing its presence in this segment, including through our solar offer for commercial and industrial customers in multiple European markets. However there are LPG market segments, such as heating for buildings off the gas grid and industries requiring high temperature process heat, where electrification may not be the most practical or cost-effective decarbonisation solution. In these cases bioLPG is an alternative to electrification which can be deployed rapidly, with no changes required to existing equipment and distribution infrastructure. It can deliver greenhouse gas reductions of 80pc or more compared to fossil LPG, and recent research by Frontier Economics found that this can come at a Total Cost of Ownership which is comparable to or even better than electrification. In parallel bioLPG, when produced from locally sourced feedstocks, will contribute to reducing Europe's dependence on imported fossil fuels. European policy should therefore not fall into the trap of focusing on electrification alone as it risks making decarbonisation less accessible for many of the millions of households and thousands of businesses in Europe who rely on LPG today for heating, cooking and hot water. Supply is often cited as a constraint for BioLPG — what progress have you seen in scaling production, and how quickly can volumes realistically grow? Currently most bioLPG is produced as a byproduct of hydrotreated vegetable oil (HVO) and SAF production, and so as production of these grows in response to RED III and ReFuelEU Aviation mandates, production of bioLPG will also grow. We however see that, in the absence of firm demand signals for bioLPG, refiners may see stronger incentives to consume bioLPG internally rather than releasing to market, which can limit availability for consumers. Liquid Gas Europe's 2025 analysis finds that supply of renewable liquid gases in Europe could reach between 2mn t and 7mn t by 2040, all derived from locally available feedstocks. These could substitute up to 50pc of current LPG consumption, but reaching these levels is highly dependent on the level of policy support available. Ireland's experience with biomethane policy highlights some of the challenges around EU rules — what lessons should governments take when designing national support schemes? DCC Energy fully supports policy design centred around technology neutrality and equal access for producers of renewable fuels to markets across the EU. However a ‘one size fits all' approach may not be the right solution for all markets, especially those at early stages of development. For example, it is currently uncertain whether biomethane imported into Ireland via the connected UK gas grid will be recognised as counting towards the forthcoming Renewable Heat Obligation (RHO). This means that domestically produced biomethane may be the only eligible substitute for natural gas under the RHO. In this case, the proposed certificate multiplier for domestically produced biomethane would have been a significant factor in the rapid scale up of Ireland's nascent local production to achieve the RHO's objectives. We would urge national governments and the EU to take full account of specific local circumstances in policy design and seek creative and pragmatic solutions which can remove roadblocks to scaling renewable fuels while respecting the principles of technology neutrality and the integrity of the single market. The recently leaked RED IV impact assessment appears to move away from post-2030 heating and cooling sub-targets in favour of technology-specific indicators for heat pumps, geothermal and solar thermal, while a broader heating fuel obligation was discarded. How does DCC Energy view this direction of travel? We see the lack of firm demand signals as the most significant factor holding back investment in and growth of renewable liquid gas production. We recognise that the impact assessment does not necessarily present a final legislative proposal, and believe that there remains a strong case for the commission to revisit the role that renewable liquid and gaseous fuels can play in heating beyond 2030 to complement those technologies named in the leaked impact assessment. Renewable Heating Obligations remain a key part of our recommended approach, whether set at EU level or by national governments — such as are already under development in Ireland and Germany — but we would welcome other measures which create credible demand for renewable liquid and gaseous fuels in applications where electrification is difficult or disproportionately costly. Demand-side measures will also need to be complemented by enabling measures, such as targeted production cost support. Updates to mass-balance and chain-of-custody rules would also be required to recognise the highly decentralised nature of liquid gas supply chains and facilitate the scaling of renewable fuels across the single market — while maintaining robust tracking and certification of sustainability credentials. Providing this combination of long-term demand certainty, national flexibility and robust market rules through RED IV and related policy instruments will be important if Europe is to realise the potential of renewable liquid gases to contribute to its 2040 decarbonisation objectives. Are there specific technologies — such as bioLPG, DME, or waste-to-energy — that you are prioritising with capital allocation, and why? DCC Energy is not an energy producer, but together with SHV Energy we have been collaborating with multiple technology providers and developers to identify production pathways for renewable liquid gases which have the potential to be deployed at scale and made available for long-term offtake by distributors. These might include renewable DME via gasification of biogenic wastes and bioLPG via alcohol-to-fuel processes. We believe that a few different pathways will be required to achieve the industry's growth potential, building on the availability of bioLPG via HVO and SAF production. By Evelina Lungu Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
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