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Iraq to sign refinery deal with Japan firm: Correction

  • : Crude oil, Oil products
  • 20/07/29

Corrects company name in first paragraph

Iraq has agreed to sign a $4bn contract with Japanese engineering firm JGC to build a fluid catalytic cracking (FCC) complex at the 210,000 b/d Basrah refinery in southern Iraq.

The complex will have a capacity of 55,000 b/d and will produce refined products such as LPG, gasoline, naphtha and gasoil.

The oil ministry aims to start the project next year, and it will take four years to complete, director general of state-owned South Refineries (SRC) Husam Hussein Weli said.

Japan last year provided a 110bn yen ($1.05bn) loan to help finance the FCC complex. Japan has expanded its financial assistance to Iraq in recent years, eyeing additional upstream access.

The potential deal has now received the approval required from Iraq's cabinet.

Iraq's oil ministry has long planned to increase capacity at its Basrah refinery to 280,000 b/d following improvements on a gasoline unit and the addition of a crude distillation unit (CDU). But capacity expansion works have been repeatedly delayed, while Iraq's demand for refined products is growing.

By Rowena Edwards

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25/12/24

Viewpoint: US midcontinent uncertain over return of E15

Viewpoint: US midcontinent uncertain over return of E15

Houston, 24 December (Argus) — The US midcontinent fuel market is again poised to enter a spring driving season fraught with uncertainty over the future of 15pc ethanol gasoline (E15), which boosts demand for higher-cost, lower Reid vapor pressure (RVP) fuel. Production of E15 requires blending with more costly, lower RVP fuel because E15 does not qualify for the 1-psi Clean Air Act waiver available for E10 production, a waiver that allows blenders to use less costly, higher RVP fuel. On 17 March, non-waiver gasoline ballooned to a 19¢/USG premium against waiver fuel, as Magellan added storage for the boutique grade non-waiver fuel and market participants wondered whether the US Environmental Protection Agency (EPA) would intervene. From 17 March to 1 May, traders bought non-waiver gasoline for 10¢/USG more than in past years, before the EPA issued emergency waivers and closed the gap between the grades. Ahead of the 2026 driving season, the situation is much the same. Market participants are uncertain whether non-waiver grades will return, or whether there will be an act of Congress or additional EPA waivers to resolve any price discrepancies. Eight US states — Illinois, Iowa, Minnesota, Missouri, Nebraska, South Dakota, Wisconsin and Ohio — requested to opt out of the 1-psi waiver in 2022, a rule that was approved in 2024 and then briefly implemented in 2025, although Ohio and South Dakota deferred implementation. The states requested to opt out of the 1-psi waiver to secure access to year-round E15, which otherwise cannot be produced during summer due to volatility limits. The waiver allows for E10 to be produced at 10 RVP while E15 without the waiver needs to be blended to 9 RVP. EPA issued emergency waivers on 1 May 2025 that allowed for E15 to be made with 9 RVP gasoline. This marked the fourth consecutive year that the EPA had issued such waivers to eliminate the need for the non-waiver specification. To waiver or not to waiver When waiver/non-waiver gasoline was active from 17 March to 1 May, Magellan pipeline V grade suboctane non-waiver gasoline in the southern midcontinent, also known as Group 3, traded at an average 10.35¢/USG premium to waiver gasoline, or about 5pc higher. Conventional 91 gasoline A grade on the same pipeline averaged a 10.43¢/USG spread, or a 4.2pc premium. Chicago, in contrast, had most of its non-waiver trade focused on the West Shore/Badger system, which runs through Wisconsin and Illinois, while the Buckeye Complex trading hub in Indiana remained on waiver product. The West Shore/Badger pipeline system non-waiver CBOB averaged a 4.32¢/USG premium to Buckeye Complex's waiver CBOB, a difference of 2.1pc. Those spreads could be even wider next year, depending on the approach of the regional pipelines and the overall availability of non-waiver product. Looking ahead Participants in the US midcontinent market have expressed uncertainty about the possibility of non-waiver returning. The American Petroleum Institute (API) along with ethanol groups and fuel retailers have publicly endorsed a bill that would allow year-round E15 and curb small refiners' ability to seek exemptions from biofuel blend quotas. A provision for extending the 1-psi waiver to E15 was included in a funding bill in December 2024, but ultimately did not make it into law. Since then, the year-round E15 issue has become entangled with small refiner exemptions with API advocating for the year-round E15 bill with the caveat that the process for gaining exemptions for small refiners become more stringent. API is also seeking to avoid having larger refiners compensate for blending exemptions granted smaller refiners. Barring an act of Congress or more EPA emergency waivers, the US midcontinent is poised to enter another summer driving season that includes both waiver and non-waiver product. By Zach Appel Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Mexico's trade surplus widens in Nov

25/12/23
25/12/23

Mexico's trade surplus widens in Nov

Mexico City, 23 December (Argus) — Mexico's trade surplus widened slightly in November from the previous month, despite sharp declines in both exports and imports in the non-oil category. Mexico posted a $663mn trade surplus in November, statistics agency Inegi said, up from a $606mn surplus in October, though on lower overall trade volumes. Total exports reached $56.4bn, while imports stood at $55.7bn, compared with $66.1bn and $65.5bn, respectively, in October. The result contrasted with the $391mn deficit forecast by Mexican bank Banorte. Inegi attributed the wider surplus to an increase in the non-oil trade surplus to $2.84bn in November from $2.74bn in October, alongside a widening of the oil trade deficit to $2.18bn from $2.13bn. Within non-oil trade, manufacturing exports fell by 16pc to $52.1bn in November from the prior month, while automotive exports declined by 2.2pc to $15.8bn, following a 4.8pc increase in October. The US absorbed 79pc of Mexico's light vehicle exports from January-November, with Mexico supplying 17pc of total US auto imports over the 11-month period, according to Mexican auto industry association AMDA. The "others" component of non-oil manufacturing exports dropped by 20pc to $36.3bn in November, nearly erasing October's 23pc gain to $45.5bn. The cumulative impact of US tariffs on Mexican goods is becoming clearer. Mexican bank Banco Base estimates the US levied an effective 4.69pc tariff on Mexican goods through September — below the 25pc blanket rate due to exemptions for goods complying with the USMCA free trade agreement. "The low tariffs have allowed Mexican exports to continue growing, particularly computer equipment, which rose by 83.39pc year to date through September compared with the same period in 2024, with a tariff of just 0.17pc," the bank said. Those "contrast sharply with passenger cars, which face a 15.29pc tariff," which maintain expectations of 7pc annual export growth in 2025, according to the bank. Agricultural exports rose by 3.8pc to $1.4bn in November after increases of 7.2pc in October and 4.1pc in September. Oil-related exports totaled $1.55bn in November, down from $1.82bn in October, including $1.03bn in crude and $514mn in refined products on lower prices and volumes. Mexico's crude export basket averaged $57.66/bl, down by $0.84/bl from October and $8.09/bl lower compared with a year earlier. Crude export volumes fell to 597,000 b/d in November from 717,000 b/d in October, remaining well below the 1.088mn b/d exported in November 2024. By James Young Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Canadian heavy TMX crude to grow into Asia

25/12/23
25/12/23

Viewpoint: Canadian heavy TMX crude to grow into Asia

Houston, 23 December (Argus) — Heavy sour Canadian crude exports are likely to expand further into the Asia-Pacific market in 2026 as Canadian output increases and US west coast refinery closures weaken US demand. Around two-thirds of all Canadian crude exports from the 890,000 b/d Trans Mountain pipeline system were destined to Asia-Pacific year-to-date November 2025, with the balance heading to the US west coast. Just over three-quarters of the 375,000 b/d of Canadian heavy crude exports from Vancouver were destined to Asia-Pacific year-to-date November 2025, according to data from analytics firms Vortexa and Kpler. The balance out of the Trans Mountain system headed to the US west coast. This is up from a roughly 60/40 split in the second half of 2024 following the 540,000 b/d Trans Mountain Expansion (TMX) startup in May of that year. US west coast customers received 80,000 b/d of heavy sour Canadian crude during the first 11 months of 2025, 25pc less than the second half of 2024. This is despite total heavy exports from Vancouver averaging 27pc higher this year so far. Heavy crude exports are expected to keep growing in 2026 as increased western Canadian production meets limited southbound pipeline capacity to the US. In January 2026, Canadian pipeline operator Enbridge rejected 13pc of heavy and light crude nominations on its 3.1mn b/d Mainline to the US as Alberta production surges in the colder months. But the Trans Mountain system has accepted all crude nominations since TMX came on line in May 2024 and the system has room to export more crude. Trans Mountain reported that the pipeline ran at 87pc capacity in the third quarter of 2025 . Canadian crude and condensate production is projected to average a record-high of 4.85mn b/d in 2026, 80,000 b/d above 2025 levels, according to Argus Consulting, a division of Argus Media. China thirst for heavy grows Any increase in exports is expected to head towards the Asia-Pacific region, specifically China. Chinese interest in heavy crude is expected to grow next year as refineries bring on line increasingly advanced cracking units to improve petrochemical yields . This increase in petrochemical output will come at the expense of road fuels, as rising electric vehicle use and low construction-sector activity hit Chinese gasoline and diesel demand. Heavy Canadian crude tends to be the most competitively-priced, unsanctioned option for Chinese refiners. Asia-Pacific buyers more generally have sought Canadian heavy crude as a substitute for restrained supplies of heavy sour Venezuelan Merey and Arab Heavy. Saudi Arabia's state-owned Saudi Aramco may be keeping more heavy crude for refining, while market confidence in Merey supply is weak following a US seizure of an oil tanker off the coast of Venezuela on 10 December and the US declaring a blockage on Venezuela exports on 16 December. Meanwhile, shipments of Arab Heavy have dropped by 280,000 b/d to around 560,000 b/d this year, according to Vortexa data. As Asia-Pacific interest in Canadian crude continues to grow, US west coast demand will continue to fall. On the heels of Phillips 66 closing its 139,000 b/d Los Angeles, California, refinery, Valero is likely to shutter its 145,000 b/d Benicia refinery near San Francisco in April 2026. Valero is evaluating alternatives for its 85,000 b/d Wilmington refinery in Los Angeles. At the start of 2025, these three refineries made up 23pc of Californian refinery capacity, and combined took 30,000 b/d of Cold Lake during January-June 2025, according to EIA data. As available Canadian crude supplies grow, the ability to fully load Aframax vessels at the Westridge Marine Terminal in British Colombia will allow increased volumes to be exported. Dredging at the terminal is set to be completed by late 2026 or early 2027. Draft restrictions limit most Aframax vessels to around 550,000 bl at the terminal for heavy crude, and 600,000 bl for some lighter crudes. Post-dredging, those same ships could carry around 700,000-750,000 bl. In the long term, Trans Mountain is looking to boost pipeline flows to meet the increased shipping capacity, including the use of drag-reducing agents that should add another 85,000-90,000 b/d by 2027 to pipeline capacity, according to Trans Mountain. By John Cordner Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

UK refiners seek unused CO2 allowances after closures

25/12/23
25/12/23

UK refiners seek unused CO2 allowances after closures

London, 23 December (Argus) — UK downstream association Fuels Industry UK has urged the government to reallocate unused free CO2 allowances from two recently closed refineries to help remaining plants cope with rising emissions compliance costs. The group wants allowances granted under the UK Emissions Trading Scheme (ETS) for the 150,000 b/d Grangemouth and 105,700 b/d Lindsey refineries to be redistributed. Each allowance permits the holder to emit one tonne of CO2 equivalent. Grangemouth and Lindsey were allocated 441,925 and 541,475 allowances for 2025, respectively. It is unclear how many remain after their closures in April and August. The association warned the sector "may not survive that long" without temporary support, citing carbon costs that exceed those faced by overseas competitors until the UK's carbon border adjustment mechanism (CBAM) takes effect. ExxonMobil's 270,000 b/d Fawley refinery — the UK's largest — will spend $70mn-80mn on carbon costs this year, rising to $150mn within five years, the company's UK chair Paul Greenwood told MPs during an Energy Security and Net Zero Committee hearing in October. Fuels Industry UK chief executive Elizabeth de Jong also addressed the committee, highlighting broader cost pressures. It remains unclear whether refined fuels will be covered by the UK CBAM, which starts in January 2027. Fuels Industry UK is seeking confirmation that they be included from January 2028, and it wants additional free UK ETS allowances distributed to sectors not covered by CBAM during a "volatile" period linked to expected UK-EU carbon market linkage. Such linkage would exempt UK and EU from each other's CBAMs, but talks have yet to start. UK refiners have also missed out on government energy price support schemes during the gas price surge triggered by Russia's invasion of Ukraine, de Jong told MPs. Refiners paid market rates to power operations at their UK sites, missing out on discounts afforded to UK companies under the Energy Bill Relief Scheme, which ran between October 2022-March 2023, and then under the Energy Bills Discount Scheme between April 2023-March 2024. By contrast, US refiners access natural gas at roughly one-third of UK prices, Greenwood said. By George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

TKW-Frachtkosten steigen 2026

25/12/23
25/12/23

TKW-Frachtkosten steigen 2026

Hamburg, 23 December (Argus) — Die Kosten für den Transport von Heizöl, Diesel und Benzin per Tankkraftwagen steigen im kommenden Jahr vielerorts an. Dies ist primär auf höhere Dieselkosten infolge der steigenden CO2-Bepreisung und THG-Erfüllungskosten zurückzuführen. Auch ein stetiger Anstieg der Lohnkosten sowie Investitionen in die Flottendekarbonisierung treiben die Kosten weiter. Anbieter handeln Diesel für Januar bundesweit derzeit mit einem Aufschlag in Höhe von etwa 10 €/100l bis 13 €/100l gegenüber Dezemberware. Der Grund hierfür ist der Anstieg der CO2- und THG-Kosten im neuen Jahr. Viele Transportverträge enthalten sogenannte Floater-Klauseln, die Preisänderungen beim Kraftstoff automatisch auf die vereinbarten Frachtkosten übertragen. Somit geben Spediteure Mehrkosten durch steigende Kraftstoffpreise in der Regel an ihre Kunden weiter. Um welchen Betrag die Frachtkosten tatsächlich ansteigen werden ist aber noch unklar, denn neben dem höheren Dieselpreis belasten unter anderem auch steigende Personalkosten die Branche. Der Fahrermangel setzt sich fort und wird aktuell durch Krankheitsausfälle sowie die laufende Urlaubszeit zusätzlich verstärkt. Spediteure berichten zudem, dass die Nachwuchssuche zunehmend schwierig wird. Viele Beschäftigte werden in den kommenden Jahren in den Ruhestand gehen. Um dem entgegenzuwirken, erhöhen Speditionsunternehmen Löhne oder werben verstärkt Personal im Ausland an — Maßnahmen, die ebenfalls kostentreibend wirken. Auch Investitionen in die Dekarbonisierung der Flotten wirken sich auf die Kostenstrukturen aus. Die Anschaffung emissionsärmerer Fahrzeuge sowie zusätzliche technische Anforderungen und Dokumentationspflichten führen zu höheren Grundkosten, die in den Frachtraten berücksichtigt werden müssen. Einige Händler berichten jedoch, dass ein Anstieg ihrer Frachtkosten im kommenden Jahr bislang noch ausbleibt. Dies führen sie auf bestehende Vertragsstrukturen zurück. So verfügen manche Spediteure über längerfristige Vereinbarungen, teilweise mit Laufzeiten von mehreren Jahren, wodurch kurzfristige Kostensteigerungen zunächst abgefedert werden. Von Marcel Pott Senden Sie Kommentare und fordern Sie weitere Informationen an feedback@argusmedia.com Copyright © 2025. Argus Media group . Alle Rechte vorbehalten.

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