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EU not on track for green shipping fuel target: Study

  • Market: Biofuels, Fertilizers, Hydrogen, Natural gas, Oil products
  • 03/06/24

The EU is on course to fall short of its green shipping fuel targets for 2030, according to non-governmental organisation Transport & Environment (T&E).

Confirmed e-fuels production projects in the bloc will not reach the mandated 1pc threshold of 280,000 t/yr of oil equivalent (toe/yr) by 2031, T&E analysis found.

The organisation mapped 61 e-fuels projects in development that could supply shipping fuels, with 17 of them "specifically dedicated to the maritime sector". But total volumes from existing plants and projects that have reached a final investment decision (FID) stand at just 130,000 toe/yr, T&E estimates.

Many of the other projects are facing "likely delays" or "even total cancellation", according to T&E's shipping officer Inesa Ulichina.

T&E pointed to just a handful of shipping-dedicated projects that have reached FID, including four green hydrogen projects and two e-methanol projects, amounting to 40,000 toe/yr and 30,000 toe/yr, respectively. It did not find one shipping-dedicated e-ammonia project with an FID.

The organisation assumes that LNG, biofuels and shoreside electricity will supply the lion's share of alternative shipping fuel demand in the EU until 2030.

Under the FuelEU Maritime regulation, the European Commission can, if appropriate, propose lifting the green shipping fuels mandate to a 2pc share, or some 560,000 toe/yr, from 2034.

EU elections — set to take place this week — will not roll back green shipping fuel targets, Ulichina said. "We envisage increased ambition for mandatory e-fuels uptake post-2030," she told Argus.

In line with the commission's projected 2040 emissions cuts, Ulichina called for the shipping sector to deliver at least 80pc absolute emission reductions by 2040.

Under the revised EU Emissions Trading System (ETS), shippers have to surrender ETS allowances for 50pc of GHG emissions for extra-EU journeys. Surrender obligations for intra-EU shipping are phased in at 40pc of verified emissions reported for 2024, 70pc for 2025 and 100pc for 2026 onwards.

The bloc's FuelEU Maritime regulation requires greenhouse gas (GHG) intensity cuts for bunker fuels of 2pc in 2025, 6pc from 2030, 14.5pc from 2035, 31pc by 2040 and 80pc by 2050.


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02/05/25

Exxon sees 45V surviving, needs blue H2 offtake

Exxon sees 45V surviving, needs blue H2 offtake

Houston, 2 May (Argus) — ExxonMobil chief executive officer Darren Woods expects low-carbon hydrogen production incentives to survive a White House review, but he wants more sales commitments before making a final investment decision on a company project in Baytown, Texas. "Our expectation is that things that we need to drive low-carbon hydrogen will probably stay in place," Woods said during the company's first-quarter earnings call Friday. "But we have to see that manifested." Woods has said that the 45V hydrogen production tax credit is "critical" to establishing a market for the zero-emissions fuel that can stand on its own and compete against fossil fuels. The company is developing what it describes as the largest low-carbon hydrogen plant in the world in Baytown, designed to produce 1bn cf/d of hydrogen from natural gas with carbon capture. While the 45Q incentive is available for projects using carbon capture and sequestration to lower emissions, ExxonMobil has repeatedly indicated it is pursuing the more lucrative 45V for the massive hydrogen and ammonia production project planned on the Texas Gulf coast. In addition to certainty about federal incentives, Woods said the company also needs to secure more offtake agreements in order to make a final investment decision. "I'd say right now that's probably the long pole in the tent with respect to driving this," Woods said. "When those two things come together and we're confident that we have what we need to generate the returns that's going to be required to justify the investments, we'll move forward. Hopefully, that's later this year." Most of the project's production would be used to decarbonize operations at Exxon's 564,500 b/d Baytown refinery, while the remainder is being targeted for exports in the form of ammonia. In January, the company signed an agreement to sell ammonia to European trading firm Trammo. Japanese power producer Jera has said it is considering 500,000 t/yr of ammonia offtake as part of its plans to take an equity stake in the project. By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Mexico bets on new contract model to lift gas output


02/05/25
News
02/05/25

Mexico bets on new contract model to lift gas output

Mexico City, 2 May (Argus) — Mexico's push to raise domestic gas output to 5 Bcf/d by 2030 depends on a new shared participation model designed to attract private investment, with four strategic gas fields prioritized as tenders begin. State-owned Pemex this week released the detailed guidelines for the mixed production scheme, first introduced in February. The model guarantees Pemex at least a 40pc share of production and gives the company wide discretion to set contract terms and choose the bidding process — including no-bid awards. But interest in the new contracts is expected to center on Mexican firms with close ties to President Claudia Sheinbaum's administration, such as Carlos Slim's Grupo Carso, according to market sources. "With these guidelines, Pemex can finally pick and choose who they want, how they want," said Miriam Grunstein, a former adviser to energy regulator CRE and senior partner at Brilliant Energy Consulting. "The downside is they are likely to turn to Mexican firms that lack the technical experience for complex projects, rather than international companies with the know-how for deep-water or unconventional plays," Grunstein said. "This scheme isn't made for companies like BHP, Total, or Eni," added Eduardo Prud'homme, former technical director at Cenagas and co-partner at consultancy Gadex. "Pemex doesn't want operators as partners. Though it is perfect for Carso." A relative newcomer to the upstream sector, Carso is one of the government's most important contractors for infrastructure projects and stands to gain on future business whether or not the upstream partnerships succeed. Prud'homme doubts international majors looking for a one-off deal would be willing to take on the heavily regulated, high-risk projects when the maximum stake is 60pc. "If you fail, Pemex will not share the loss," said Prud'homme. "If you succeed, Pemex decides how much to share." Pemex management said it plans to launch 17 projects under the new scheme this year. It remains unclear how many of these will focus on gas development. Still, gas is a core focus. Pemex's 2025–2030 business plan allocates Ps238bn (US$12.1bn) to gas projects in pursuit of the 5 Bcf/d goal. Four key fields — Burgos, Quesqui, Ixachi and Bakte — are expected to provide 54pc of total projected output. Carso is already active, partnering with Pemex on the complex deep-water Lakach gas project, which is now expected to migrate from a service contract to the new mixed contract model. Slim began renegotiations in February after the model was announced. Carso has also expanded upstream, buying into the oil-rich Zama project in December. In March, Sheinbaum confirmed the government is in talks with Carso to partner on Ixachi. Turning the tide Still, gas output continues to decline. An analysis by Mexican think tank IMCO found that Pemex and its farmout partners this year posted their lowest first-quarter gas production in 15 years. In the first quarter, Pemex produced 4.408 Bcf/d of gas, down by 8pc from the same period in 2024 and 12pc lower compared with the same quarter 2023. The 367 MMcf/d annual decline marks the steepest first-quarter drop since 2018, when output fell by 536 MMcf/d year over year. On the positive side, Pemex's natural gas production in March ticked 0.3pc higher from the previous month to 4.39 Bcf/d – marking the second consecutive month of increases after February output was up 1.3pc from January. By James Young Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Chevron 'not surprised' Calif refineries shutting


02/05/25
News
02/05/25

Chevron 'not surprised' Calif refineries shutting

Houston, 2 May (Argus) — Chevron's chief executive said today he is not surprised that refineries in California are shutting down, because the state has made it "nearly impossible" to invest going forward. Independent refiner Valero on 16 April said it is planning to shut or re-purpose its 145,000 b/d refinery in Benicia, California, by April 2026. This comes as Phillips 66 is planning to shut its 139,000 b/d Los Angeles refinery later this year. "I'm not surprised to see the announcements that have come out," chief executive Mike Wirth said Friday on Chevron's first-quarter earnings call. Policies coming out of the state "make it nearly impossible to invest in California going forward", he said. The state inserting itself into operational matters like planning turnarounds is "an unwise move", Wirth said. Chevron operates two large refineries in the state — the 269,000 b/d El Segundo, refinery and the 245,000 b/d Richmond refinery. "We do not have any announcements on our refineries at this time," Wirth said. California governor Gavin Newsom last year signed into law AB X2-1, legislation authorizing the state's energy regulator to require refiners to maintain minimum gasoline inventories. The bill is part of a multi-year effort by Newsom to mitigate price spikes at the pump, authorizing the California Energy Commission (CEC) to regulate, develop and impose requirements for in-state refiners to maintain minimum stocks of gasoline and gasoline blending components. The agency is in the rule-making process for some of the regulations, but a vote on a refinery resupply rule was postponed last month to allow for more engagement with stakeholders. The closures of Valero's Benicia refinery and Phillips 66's Los Angeles refinery will eliminate 17pc of the state's crude refining capacity. PBF Energy, which also operates refineries in California, said Thursday that the shutdowns will cause a 250,000 b/d shortfall in gasoline in the state and lead to growing reliance on more expensive imports. Valero chief executive Lane Riggs said last week that California's regulatory and enforcement environment is "the most stringent and difficult" in North America due to 20 years of policies pursuing a move away from fossil fuels. California will require 100pc of in-state sales of new cars and trucks to be electric, plug-in hybrid or hydrogen models by 2035. Five days after Valero's announcement to shut Benicia, Newsom urged state regulators to work closely with refiners on short-term and long-term planning, including through "high-level, immediate engagement" to make sure Californians have access to transportation fuels, according to a letter sent to CEC vice chair Siva Gunda. Newsom ordered the CEC to work with a cross-agency task force to recommend by 1 July any changes in the state's approach that are needed to ensure adequate fuel supply during the state's energy transition. By Eunice Bridges Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Shell says can deliver solid returns below $50/bl


02/05/25
News
02/05/25

Shell says can deliver solid returns below $50/bl

London, 2 May (Argus) — Shell can pull on several levers to maintain shareholder returns in a sub-$50/bl oil price environment, including adjusting capital expenditure (capex), chief financial officer Sinead Gorman said today. Shell is facing questions about contingency plans for lower oil prices after Ice Brent crude futures briefly dipped below $60/bl in intraday trading earlier this week for only the second time in more than four years. Oil prices are not only under pressure from weakening global economic growth prospects due to US import tariffs, but also from the Opec+ group's decision to bring back production faster than previously flagged. At $50/bl, Shell's commitment to return 40-50pc of its cash flows to shareholders would mean $8bn/yr of dividends and $6bn-7bn/yr of share buybacks, while only having to pull back "a little bit" on capex, Gorman said. In a $40/bl oil price environment, Gorman expects Shell's operating cash flow to still cover the $8bn/yr in dividends. "But of course, for us, the important thing is to be able to try and maintain the buyback for as long as we can," she said. At these lower oil prices, Shell can make use of its comparatively strong balance sheet to support share buybacks. Shell's debt gearing remained below 19pc at the end of the first quarter despite the company increasing its net debt during the period. "Are we comfortable leaning on the balance sheet? Yes," chief executive Wael Sawan said. The balance sheet has been positioned so it can be used to generate shareholder value, "whether that shareholder value is best created through more buybacks, or whether that shareholder value is created through an inorganic [investment] or the like", he said. For now, Shell is sticking to its $20bn-$22bn capex budget for 2025 and expects to carry on with planned investments in projects and other commitments. But the company has demonstrated in the recent past "a strong ability to be able to pull many levers" should oil prices fall futher, Gordon said, referencing the reduction in capex to below $18bn during the Covid pandemic. "So, the flex is there, but that's not the position we're in at the moment. We don't need to do that and we see great opportunities for value," she said, pointing to the company's announcement earlier this year that it is raising its stake in the Ursa oil project in the US Gulf of Mexico. Earlier today, Shell said it is maintaining its quarterly dividend at 35.8¢/share and will continue to buy back its shares at a rate of $3.5bn/quarter, despite a 35pc drop in its first-quarter profit to $4.8bn. By Jon Mainwaring Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Shell’s 1Q European gas production up


02/05/25
News
02/05/25

Shell’s 1Q European gas production up

London, 2 May (Argus) — Shell's European gas production for sale in January-March slightly stepped up on the year, but the company expects works to limit global oil and gas production this quarter. Shell produced 24.9mn m³/d in the first quarter, up from 24.8mn m³/d a year earlier but below the 25.2mn m³/d in fourth-quarter 2024. Shell has stakes in UK and Dutch fields, as well as a 17.8pc share in Norway's Ormen Lange field and an 8.1pc stake in the giant Troll field. Output from the two Norwegian fields was down on the year in January-February, the latest months for which data are available. Ormen Lange produced 19.8mn m³/d in January-February, down from 22.6mn m³/d a year earlier. Troll production averaged 123.6mn m³/d over those two months, also down from 126.2mn m³/d a year earlier. Shell's integrated gas business was the company's top performing segment with profits of $2.8bn, slightly higher on the year. Lighter maintenance at the Pearl gas-to-liquids plant in Qatar supported production, but unplanned works and weather constraints in Australia left the company's LNG volumes at 6.6mn t in January-March from 7.6mn t a year earlier, Shell said. Meanwhile, Shell's upstream division posted $2.1bn in profit, down 8.5pc on the year earlier but double compared with the fourth quarter 2024. The segment was hit with a $509mn tax bill related to the UK's Energy Profits Levy in the first quarter, partially offset by gains from asset sales. Across the entire company, Shell reported first-quarter profits adjusted for inventory valuation effects and one-off items of $5.6bn, surpassing analysts' expectations of $5.3bn . Shell's first-quarter worldwide oil, liquids and gas production was 2.84mn boe/d, down from 2.91mn boe/d a year earlier but up from 2.82mn boe/d in the previous quarter. The company expects lower oil and gas production this quarter in a 2.45mn-2.71mn boe/d range because of maintenance across its integrated gas portfolio and an absence of volumes from its SPDC business in Nigeria, which Shell sold off in March. By Aleksandra Godlewska and Jon Mainwaring Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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