EU: Bund darf Rosneft Deutschland übernehmen

Market: Oil products
20/02/26

Die EU Kommission hat am 20. Februar entschieden, dass die Bundesrepublik die alleinige Kontrolle über Rosneft Deutschland erwerben darf. Die Kommission hat eine entsprechende Anmeldung bereits am 28. Januar erhalten. Ob eine Übernahme tatsächlich stattfinden wird ist jedoch noch unklar.

Die Entscheidung betrifft die Rosneft Deutschland GmbH sowie die RN Refining & Marketing GmbH und somit auch die Anteile, die die deutschen Töchter des russischen Staatskonzerns an den Raffinerien Bayernoil (215.000 bl/Tag) — an der Rosneft 28,57 % hält — Miro (310.000 bl/Tag; 24 %) und PCK (204.000 bl/Tag; 54,17 %) hält. Insgesamt kontrolliert Rosneft Deutschland nach Argus Berechnungen rund 14,3 % der deutschen Raffineriekapazitäten.

Rosneft Deutschland steht seit 2022, kurz nach dem Beginn des Konfliktes gegen die Ukraine, unter Treuhandverwaltung durch das Bundeswirtschaftsministerium BMWE. Die Treuhand wurde bisher halbjährlich verlängert und gilt aktuell bis zum 10. März 2026. Im Januar verabschiedete die Bundesregierung eine Novelle des Außenwirtschaftsgesetzes, in welcher die Dauer der Treuhand an die Sanktionen der USA gegen Rosneft geknüpft wurde. Das US-Finanzministerium bestätigte im Oktober zwar eine Ausnahmeregelung für die beiden deutschen Töchter von Rosneft, allerdings läuft diese am 29. April aus. Die Bundesregierung bindet sich laut Aussagen des BMWE derzeit in Gesprächen mit dem US-Finanzministerium bezüglich einer Verlängerung der Ausnahmeregelung.

Noch ist unklar, ob die Bundesregierung nun tatsächlich vorhat, Rosneft Deutschland zu übernehmen. Das BMWE war für Fragen nicht zu erreichen.

Von Max Steinhau

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22/10/26

Q&A: JetBio to produce renewable diesel from ethanol

Sao Paulo, 22 October (Argus) — Sustainable aviation fuel (SAF) producer JetBio has redesigned its first planned plant, to be built in Paulinia, in Brazil's southeastern Sao Paulo state, to include renewable diesel production from ethanol. The company's chief executive, William Moore, said the project will be the first facility in the world capable of producing renewable diesel from ethanol at a commercial scale. The project will use Honeywell UOP's technology to convert ethanol into those two renewable fuels. The new model will allow the plant to switch from maximum sustainable aviation fuel (SAF) production to maximum renewable diesel production, both with no co-products, and the switch can be made within a few hours, according to Moore. At maximum SAF output, the facility would produce close to 770,000 metric tonnes (t)/yr from approximately 1.4mn t of ethanol (31,068 b/d). In maximum renewable diesel mode, output would be closer to 700,000 t/yr. JetBio plans to invest $2bn in the project, with a final investment decision expected in the first quarter of 2027 and start-up potentially from mid-2030. Edited highlights from the interview follow. Is JetBio planning to direct renewable diesel output primarily to Brazil's domestic market, or is it also eyeing international markets? We are applying to create a ZPE (Brazilian free-trade zone) and the requirement is 80pc of our product has to be exported. We are going to be living within those constraints, but even in that 20pc for both SAF and renewable diesel, we think there is strong demand in Brazil for both. The beauty of renewable diesel, while it may be a little bit more expensive, you can still get to greater than 66pc GHG reduction all the way down to 95pc-100pc, depending on what ethanol we are sourcing and if we are using biomethane instead of natural gas for heat and hydrogen. It offers the decarbonization benefits to the local market in Brazil without those companies having to make big capital investments to change over their fleets to burn ethanol or change over their bunkering infrastructure or their fueling infrastructure in order to utilize it. So far, we have seen strong interest from maritime — that would be bunkering in Santos and Paranagua —, from mining, heavy on-road transportation and agriculture. Brazil imports fossil diesel, and there is a strong argument that why would Brazil want to import all that fossil diesel when they could use locally produced renewable diesel that has a much lower carbon footprint? Now it all comes down to price, but our goal is to be the lowest-cost producer of SAF and now renewable diesel in the world at the lowest carbon intensity that has access to Brazilian markets and export markets. When we are in service, we think that Brazilian ethanol will be the most competitive green molecule in the world. And we're just converting it into two other products that can be utilized by hard-to-abate industries. Have ethanol producers shown interest in this part of the project? One thing that we are talking to ethanol producers about is would they be interested in a tolling model where they would supply the ethanol to our plant in Paulina, and for an upgrading fee we would deliver back to them renewable diesel or sustainable maritime fuel that they could sell directly to consumers that they have already established a relationship with. It has just been transformed into a much more energy-dense and pure drop-in fuel that does not require any blending and does not have storage limitations. It is a perfect replacement for the fossil diesel that they are already consuming. Is this technology adaptation driven by a change in the outlook for the SAF market? Are you seeing any bottlenecks in that market? Our view has not changed on the SAF market. We are just excited that we can access the renewable diesel market as well. We see the world being structurally short of SAF, especially non-HEFA SAF, in 2030 and beyond. I think what you have to remember here is this is the largest biorefinery of its kind that is going to be built anytime soon. From an addressable market standpoint, this just gives us an additional optionality that we can provide. By Maria Lígia Barros Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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Kuwait's crude exports near pre-war levels: KPC

22/10/26

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22/10/26

Kuwait's crude exports near pre-war levels: KPC

Dubai, 22 October (Argus) — Kuwait's crude exports are at levels seen before the US-Iran war, according to state-owned KPC chief executive Sheikh Nawaf al-Sabah. Speaking to Bloomberg TV, Sheikh Nawaf said KPC, which oversees all Kuwait's hydrocarbons production, is meeting all its obligations to all of its crude customers. "On the crude oil side, we are exporting basically what we had been doing before the war began," he said. Kuwait's crude exports, including its share from the Saudi-Kuwaiti Neutral Zone, averaged around 1.45mn b/d in January-February, before the war and the disruptions to shipping through the strait of Hormuz. These pushed Kuwait's crude exports to near zero in April and May and led KPC to significantly scale back production. Exports began to recover in June, as Kuwait, like several other Mideast Gulf producers, began delivering crude on its own tankers and selling through ship-to-ship (STS) transfers outside the strait of Hormuz. Kuwait's third-quarter crude exports averaged just below 1mn b/d. Preliminary Kpler data show Kuwaiti exports at 884,000 b/d in the first three weeks of October, around 550,000 b/d below pre-war levels. Many tankers transiting the strait are doing do with AIS tracking switched off, so these numbers can be — and typically are — revised up. The export increase has allowed Kuwait to lift its crude production to "well over 2mn b/d," Sheikh Nawaf said. Argus estimated Kuwaiti crude output in September at 1.79mn b/d. Oil product exports are still below pre-war levels, Sheikh Nawaf said, primarily because of a lack of available tankers. "On product, shipping is more constrained, and that's where we've had to restrain some of our refining capacity," Sheikh Nawaf said. "You're seeing the result of that in international diesel and jet fuel prices." By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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Iran claims end to gasoline imports despite shortfall

22/10/26

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22/10/26

Iran claims end to gasoline imports despite shortfall

Dubai, 22 October (Argus) — Iran's president said this week that the country no longer needs to import gasoline to meet domestic demand, thanks to a renewed push by the authorities to curb fuel consumption. But refinery outages and continued fuel smuggling cast serious doubt on those claims. President Masoud Pezeshkian said that "fuel conservation and management measures" had ended the country's need for gasoline imports, saving it $12bn/yr. The measures Pezeshkian referenced rest largely on a tiered pricing system that Tehran has tightened in stages since December, cutting subsidised allocations and raising prices for the heaviest users (see table) . The latest change, introduced in early September, doubled the price of gasoline bought above the subsidised quota to 100,000 rials/l ($0.04/l) from IR50,000/l. The higher prices do appear to have curbed consumption. Domestic demand has fallen to around 134mn l/d this month from about 144mn l/d in August-September, according to state-owned products distributor NIOPDC. Part of the decline reflects a shift towards compressed natural gas (CNG). Daily CNG consumption rose to 16.7mn m³ in October from 14.7mn m³ in August, displacing an estimated 2mn l/d of gasoline demand, according to Iranian officials. At the same time, domestic gasoline production increased. Output averaged 135mn l/d in late August and early September, according to official figures, up from an average of 122mn l/d in the first five months of the Iranian year, corresponding to late March to late August. The increase resulted from higher refinery runs and reconfiguration projects, NIORDC head Mohammad-Sadegh Azimifar said last month. These included sending surplus naphtha from the Persian Gulf Star (PGS) condensate splitter to underused gasoline units at the 375,000 b/d Isfahan, 220,000 b/d Tehran and 110,000 b/d Tabriz refineries. Even at those elevated levels, production remained about 10mn l/d below peak summer demand of 145mn l/d, although it would have broadly matched current demand. Refinery outages, however, have since reduced production capacity. An explosion at the 700,000 b/d Abadan refinery in late September cut gasoline production capacity to about 8mn l/d from 11mn l/d, with repairs expected to take at least two months. The disruption added to broader supply losses, including at the 55,000 b/d Lavan refinery, which lost about half of its 3mn l/d gasoline capacity after it was hit on the first day of the US-Iran ceasefire in April, forcing other plants to raise runs. Iran also continues to face a chronic smuggling problem, with subsidised fuel diverted to neighbouring countries where prices are significantly higher. Tehran has responded by introducing identity checks for motorists using emergency fuel cards at filling stations. The cards previously allowed anonymous purchases and accounted for 40-45pc of refuelling transactions, well above the government's 5pc ceiling. But Iranian officials estimate that around 25mn l/d of petroleum products continue to be smuggled across the country's borders, with diesel accounting for most of the illicit trade. Limited options Iran also has little scope to raise gasoline production further. Feedstock availability is already under pressure following damage sustained during the early stages of the US-Iran war to facilities linked to the South Pars gas field, which supplies condensate to PGS. And two new splitters, the South Adish and Mehr Persian Gulf units, are not expected to start operations before the end of the Iranian year in March at the earliest. Against that backdrop, market participants say Iran still needs to import between three and seven Medium Range (MR) gasoline cargoes a month to cover its near-term supply gap. This is equivalent to around 0.9mn-2.1mn bl/month, or 4.7mn-11mn l/d. But sanctions and the US naval blockade imposed on Iran since July make those volumes difficult to secure. Market participants say some gasoline is being transferred between vessels off Shinas, Oman, before US-sanctioned tankers carry it through the strait of Hormuz to Iran. The trade, however, is constrained by a shortage of ships willing to take part in the transfers and deal with sanctioned tankers serving Iranian ports, one shipbroker said. By Rithika Krishna Iran gasoline quota and price changes liters Effective Tier 1 quota Price (IR/l) Tier 2 quota Price (IR/l) Total quota (l/mo) Above-quota price (IR/l) Dec-25 60 15,000 100 30,000 160 50,000 Mar-26 60 15,000 70 30,000 130 50,000 Jul-26 60 15,000 50 30,000 110 50,000 Sep-26 60 15,000 50 30,000 110 100,000 Price in Iranian rials/litre (IR/l) Source: Ministry Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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'Real PdV' to appoint new Citgo board: Attorney

21/10/26

News

21/10/26

'Real PdV' to appoint new Citgo board: Attorney

Houston, 21 October (Argus) — Venezuela's state-owned oil company PdV is working to appoint a new board of directors for US refiner Citgo and its parent company PdV Holdings, a lawyer for the company said today. "The real PdV authorities are working to effectuate their appointment" of a new board of directors to PdV Holdings and Citgo, attorney Katherine Wellington said at a hearing of the US Court of Appeals for the Third Circuit in Philadelphia, Pennsylvania. "US recognition of President [Delcy] Rodriguez's government means that that the real PdV authorities now appear before this court." The court is hearing challenges from Venezuela, PdV and other parties to the choice of Elliott Investment Management affiliate Amber Energy's $5.9bn bid as the winner in the pending auction. It covers Citgo's three US refineries, its lubricant plants and midstream and retail assets to satisfy debt defaults and expropriations owed by PdV Holdings. Amber's bid included a separate agreement to settle litigation claims with 75pc of a group of PdV bondholders for $2.13bn. The situation in Venezuela has taken a sharp turn since a US federal judge in November affirmed Amber's bid as the winner. The US ousted former president Nicolas Maduro on 3 January, subsequently lifted sanctions on Venezuela's oil exports and recognized interim president Delcy Rodriguez's government in March. Although the US recognizes the Rodriguez-led government, Washington has yet to allow the Caracas-based PdV to reassert control over Citgo which has operated under a board appointed by the Venezuelan opposition and vetted by the US government since 2019, after the US rejected Venezuela's 2018 presidential election as illegitimate. The US Treasury Department on 14 September updated a general license that in January set out conditions for PdV's oil sales and business transactions with the US and other companies. It added an explicit prohibition against changing the governing structure of Citgo and its parent companies PdV Holding and Citgo Holding. The US administration earlier this month declined to give the appeals court a comment on the Citgo case after a third request from the court for the US to weigh in. The US "has no views to express at this time concerning this litigation", the Department of Justice said in a 13 October filing. The hearing on Wednesday examined various issues in the Citgo case including whether the lower court had authority to conduct the auction, the valuation of Citgo and alleged conflicts of interest of court-appointed special master Robert Pincus and his advisors. Pincus has refuted the conflict of interest allegations and the lower court rejected motions to remove him. Wellington joined the Citgo case in August after previous lawyers for PdV withdrew from the case. They cited a directive from the general legal counsel for PdV Alejandra Torrealba to refrain from acting on behalf of PdV before US courts, according to documents filed to the US Court of Appeals for the Third Circuit. The Citgo sale is also subject to regulatory approvals, including by the US Treasury Department's Office of Foreign Assets Control. Citgo owns and operates three US refineries — the 471,000 b/d Lake Charles refinery in Louisiana, the 165,000 b/d Corpus Christi plant in Texas and the 188,000 b/d Lemont refinery in Illinois. By Eunice Bridges Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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TMX pull on Canadian crude stronger than US Gulf

21/10/26

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21/10/26

TMX pull on Canadian crude stronger than US Gulf

Houston, 21 October (Argus) — Exporting Canadian crude through the 890,000 b/d Trans Mountain (TMX) pipeline system is more profitable for shippers compared to alternative routes into the US, as ample Latin American supply weighs on Western Canadian Select (WCS) Houston. December-injection cargoes of high-TAN Canadian heavy crude traded around a $13.33/bl discount to December CMA Nymex fob Vancouver over 5-19 October, around a $14/bl premium to assessments for high-TAN crude at the start of TMX in Edmonton, Alberta. This is the widest spread between the prices for a single cycle since the 540,000 b/d Line 2 Expansion came online in May 2024. This wide premium between selling the same crude at Edmonton and Vancouver implies strong profit margins for shippers on TMX, given current interim tariffs for committed shippers to ship heavy crude to the Westridge terminal in Vancouver range from $7.70/bl to $9.13/bl. This assumes fixed and full variable costs are paid. If variable costs are lower, then shipping margins widen. Making larger minimum commitments to ship on pipelines means operators are often willing to offer lower shipping tolls. Historically, Canadian shippers looked to maximize exports to the US Gulf coast as refiners there have strong demand and high refining margins for heavy crude. Argus Consulting estimates the US Gulf runs around 1.7mn b/d of coking capacity — more than double the second-highest global region in China. But with the breakout of the Iran war and the return of Venezuelan barrels, the arbitrage from Alberta to the US Gulf has been challenging for most shippers and TMX crude has become the premium export route. Heavy sour WCS in Houston, Texas, averaged around a $17/bl discount to December CMA Nymex over 5-19 October, or around an $8.74/bl premium to November-delivery WCS at Hardisty, Alberta, over the same period. Tariffs to ship heavy crude from Hardisty to the US Gulf coast range from $8.68-$9.85/bl, leaving the journey profitable only for shippers with the largest commitments and closed for most uncommitted shippers. Strait constraints Asia-Pacific markets have borne the brunt of pain from disruptions to crude flow through the strait of Hormuz, and refiners there have been scrambling for alternative crudes. Asian buyers have generally been willing to pay up for heavy sour Canadian TMX crude, despite quality concerns. Reduced supply of Iranian barrels has also forced independent Chinese refiners, mostly based in Shandong province, into the market and seen fob prices skyrocket. Some traders noted the profitable shipping economics on TMX have increasingly drawn in uncommitted shippers who pay the highest tolls. Canadian barrels out of Vancouver also offer a comparatively short haul option of around three weeks to ship to China, compared to six weeks for most Atlantic basin grades. TMX barrels have benefited from a reliability factor, given elevated tension in the Mideast Gulf and infrastructure issues that plague rival Latin American heavy producers such as Ecuador, Mexico and Venezuela. And despite the recent doubling of freight costs, Pacific basin demand for TMX crude has remained robust throughout the war. High shipping costs have also helped to keep Venezuelan and Colombian heavy crude in the Atlantic basin. Canadian heavy crude differentials have generally widened through the November trading cycle, with bellwether WCS at Hardisty averaging around a $25.70/bl discount to November CMA Nymex over 5-19 October, the widest since November 2023. Argus Consulting forecasts record fourth quarter crude and condensate production of 5.15mn b/d, straining the Canadian pipeline export system. Enbridge rejected 16pc of heavy crude nominations on its 3.1mn b/d Mainline for November, up from 4pc in October, which signals a tight egress environment despite historically low Canadian heavy crude differentials. By John Cordner and Matthew LaFrance Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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