IEA sees long oil demand plateau after peak

: Crude oil
23/10/24

Global oil demand peaks towards the end of this decade at around 102mn b/d then remains broadly at that level for the following two decades, according to the IEA's baseline scenario in its latest World Energy Outlook (WEO).

The IEA's Stated Policies Scenario (STEPS), which is based on prevailing policies worldwide, sees global demand — excluding biofuels — rising from 96.5mn b/d in 2022 to 101.5mn b/d in 2030. This is 900,000 b/d below last year's scenario for 2030. From then on oil consumption begins a long but slow decline, falling by just over 4mn b/d to 97.4mn b/d in 2050.

The IEA puts the downward revision from last year's WEO mainly down to the "astounding rise in electric vehicle sales" which is now affecting oil demand for road transport. While demand for use in petrochemicals, aviation and shipping continues to grow up to 2050, this is not enough to offset falls in demand for road transport, along with the power and buildings sectors, the IEA said.

The IEA's baseline scenario is in stark contrast to that of Opec, which earlier this month massively raised its global oil demand projection up to 2045.

The WEO explores two other scenarios — the Announced Pledges Scenario (APS) assumes government targets on emissions are met in full and on time, and the Net Zero Emissions by 2050 Scenario (NZE) lays a path to limit global warming to 1.5°C.

In APS, oil demand falls to 92.5mn b/d by 2030 and 54.8mn b/d by 2050, led by sharper declines in oil demand for road transport with "EVs accounting for more than 75pc of passenger car and truck sales in 2050." In NZE, oil demand falls to 77.5mn b/d by 2030 and 24.3mn b/d in 2050.

On the supply side, the STEPS scenario sees US tight oil output increasing by 2mn b/d between 2022 and 2030, to around 9.5mn b/d. Output peaks soon after and falls to around 8.5mn b/d by 2050. Other major additions come from Brazil and Guyana, with the latter boosting output to 2mn b/d by the mid 2030s. Opec production rises by just 1mn b/d by 2030, as African members' contributions fall by 1.5mn b/d. Opec's share of global oil production rises from 36pc in 2022 to 42pc in 2050.

Russian production falls by around 3.5mn b/d between 2022 and 2050 "as it struggles to maintain output from existing fields or to develop large new ones."

Tense Middle East

The IEA said some of the immediate pressures from the global energy crisis had eased, but it called attention to "unsettled" energy markets, geopolitics and the global economy.

"A tense situation in the Middle East is a reminder of hazards in oil markets a year after Russia cut gas supplies to Europe," the IEA said. "This underscores once again the frailties of the fossil fuel age."

The agency said oil and gas investment now is almost double the level required under the NZE scenario. It expects this to come in at around $800bn in 2023, broadly in line with the level needed in STEPS to 2030, that "industry today does not see a significant near-term reduction in demand as likely."

STEPS sees energy-related CO2 emissions peaking in the mid-2020s but emissions remain high enough to increase global average temperatures to around 2.4C in 2100.

"Bending the emissions curve onto a path consistent with 1.5C remains possible but very difficult," the IEA said.

By Aydin Calik

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24/12/30

Viewpoint: Trump tariffs may shift crude flows to USWC

Houston, 30 December (Argus) — President-elect Donald Trump's proposed 25pc tariff on Canadian and Mexican imports could redirect key imported oil grades from the US west coast, opening avenues for displaced Latin American crudes to reappear. The tariffs, which Trump announced on 25 November, could displace about 9pc of the crude US west coast refiners import. Canadian crude flows from the newly expanded 890,000 b/d Trans Mountain pipeline system, which recently have drawn purchases in the US west coast, would force barrels to Asia-Pacific . Mexican crude sellers would divert crude to other outlets as well, like Europe or Asia-Pacific. Refiners on the US west coast increased purchases of Canadian grades after the May startup of the Trans Mountain Expansion (TMX). Cheaper prices and closer proximity to Vancouver, British Columbia, where TMX crude loads, allowed the heavy sour crudes to find favor along the US west coast. But the proposed tariffs could raise landed TMX prices, no longer making it the cheapest heavy sour option. US west coast buyers would pay a 25pc import tariff to US Customs and Border Protection on TMX crude once it has entered port. US west coast refiners received around 169,000 b/d of crude from the Vancouver area since the pipeline came on line in May, up from less than 40,000 b/d a year earlier, data analytics firm Vortexa shows. Around 60pc of Mexico's crude exports in 2024 went to the US, mostly to the US Gulf coast, according to Vortexa data. Tariffs could lead to a drop in prices to adjust to a tariffed American market or for Mexican crude going more often to other destinations such as Europe or Asia-Pacific. Spain, South Korea and India, were the second, third and fourth most common destinations for Mexican crude exports in 2024, respectively. Mexico's crude production and export infrastructure is concentrated on the country's east coast, making exports to Asia-Pacific difficult. Mexico would need to invest in building exporting infrastructure from the west coast to improve trade routes to Asia, market participants say. But Mexico's state-owned oil company Pemex plans to continue cost-cutting measures, led by recently elected President Claudia Sheinbaum, so infrastructure expansion is unlikely. Other Latin crudes could also experience a rise after being displaced by the commencement of TMX in May. Since then, heavier crudes from countries such as Colombia, Ecuador and Argentina have found more frequent routes to the US Gulf coast and Asia-Pacific. Market participants believe lighter Brazilian grades could find routes to the US west coast as TMX supply increases in China. China imported 683,000 b/d of Brazilian crudes in 2024, c ompared with 180,000 b/d of imports to the US west coast from Brazil, according to Vortexa. Sources say the tariffs are a bargaining chip by the incoming administration, and participants are skeptical they will be implemented by the Trump administration. Instead, the tariffs could exclude crude and other commodities. More than $3.3bn of goods and services cross the US-Canada border each day, according to Canada's Fall Economic Statement (FES), which notes Canada is the largest market for 36 US states. Market participants are vocally against the proposed tariffs. Tariffs on crude and refined products "will not help our industry compete, nor will they support US energy dominance and affordability for consumers," the American Fuel and Petrochemical Manufactures said on 27 November . Cenovus is also trying to explain to policy makers in the incoming Trump administration how tariffs on Canada could impact the energy system in North America. But the incoming administration shows no sign of backing off the tariffs for 2025. By Rachel McGuire and João Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: MEH-Midland spread to remain wider in 2025

24/12/26

Viewpoint: MEH-Midland spread to remain wider in 2025

Houston, 26 December (Argus) — WTI Houston's premium to WTI in Midland, Texas, is set to hold at 50¢/bl or wider in 2025, boosted by swelling volumes headed toward the Gulf coast as Houston grows in importance as a center for price discovery. The locational spread between WTI Houston and Midland rose steadily throughout 2024, averaging 49¢/bl year-to-date and widening as high as $1.41/bl during the June trade month as the 1.5mn b/d Wink-to-Webster pipeline was taken offline for repairs. In 2023, the spread averaged 21¢/bl. Trading activity for WTI at Oneok's Magellan East Houston (MEH) terminal — both in the physical and financial markets — climbed to all-time highs in 2024. Reported trade month volumes for WTI Houston swelled to 1.26mn b/d during the December trade cycle, a high for the year, and just 0.8pc below its previous record. On 16 December, WTI Houston trade closed the day at 153,000 b/d for the January trade cycle, the highest single-day trade volume in the history of Argus assessments of the grade. In financial markets, WTI Houston trade activity broke records in 2024, with open interest on CME's WTI Houston futures contract climbing to an all-time high of 412,519 lots — each 1,000 bl — on 21 November. MEH demand up despite export slowdown Trading activity broke records even as US crude exports slowed in the latter half of 2024 on Chinese economic woes that dampened Asian demand. New Chinese stimulus initiatives, namely relaxed fiscal and monetary policy , are meant to reverse that trend, but it remains to be seen if the efforts will work. Further challenges weighing on the US export market are a strengthening dollar combined with a high degree of uncertainty surrounding president-elect Donald Trump's proposed tariff plans, which feature ratcheting-up trade tensions with China even more. Multiple projects to add Permian takeaway capacity at the Texas Gulf coast are in various stages of planning, which could eventually open the window for ever-larger WTI export volumes, and further support WTI Houston against Midland. But industry participants have grown skeptical of the need for new export terminals or other projects. Midstream companies showed little enthusiasm for pitching new coast-bound pipelines from the Permian basin in their end-of-year investor reports . Key firms previously sought more takeaway capacity before the Covid-19 pandemic, when WTI Houston premiums to WTI in Midland consistently topped $1/bl, which would help recoup pipeline construction costs. As it stands, the roughly 3mn b/d total available pipeline capacity from the Permian basin to the Houston area is likely to remain static in coming years. This status quo for onshore infrastructure will help prop open the Houston-Midland WTI premium for the coming year, even if export demand fails to picks up in 2025. By Gordon Pollock WTI Houston-WTI Midland spread Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US tariffs may push more Canadian crude east

24/12/26

Viewpoint: US tariffs may push more Canadian crude east

Singapore, 26 December (Argus) — Canada may divert crude supplies from the US to Asia-Pacific via the Trans Mountain Expansion (TMX) pipeline in 2025, should president-elect Donald Trump impose tariffs on Canadian imports. Trump has declared that he will implement a 25pc tax on all imports originating from Canada after he is sworn into office on 20 January. This will effectively add around $16/bl to the cost of sending Canadian crude to the US, based on current prices, and impel US refiners to cut their purchases. The US imported 4.57mn b/d of Canadian crude in September, according to data from the EIA. Canadian crude producers are expected to turn to Asian refiners in their search for new export outlets. This is especially after Asian refiners gained easier access to such cargoes following the start-up of the 590,000 b/d TMX pipeline in May. The new route significantly shortens the journey to ship crude from Canada to Asia. It takes about 17 days for a voyage from Vancouver to China, compared with 54 days from the US Gulf coast to the same destination. China has become the main outlet for Asia-bound shipments from Vancouver, accounting for about 87pc of the 200,000 b/d exported over June-November, according to data from oil analytics firms Vortexa and Kpler (see chart). But even if the full capacity of the TMX pipeline is utilised to export crude to Asia from Vancouver, it will still only represent a fraction of current Canadian crude exports to the US. Vancouver sent just 154,000 b/d via the TMX pipeline to US west coast refiners over June-November, Vortexa and Kpler data show. Meanwhile, latest EIA figures show more than 2.63mn b/d of Canadian crude was piped into the US midcontinent in September, while US Gulf coast refiners imported 469,000 b/d. This means Canadian crude prices will likely come under downward pressure from higher costs for its key US market, should Trump's proposed tariffs come to pass. This will further incentivise additional buying from Chinese customers, as well as other refiners based elsewhere in Asia-Pacific. India, South Korea, Japan, and Brunei have already imported small volumes of Canadian TMX crude in 2024. A question of acidity But other Asian refiners have so far been reluctant to step up their heavy sour TMX crude imports because of concerns over the high acidity content. China has been mainly taking Access Western Blend (AWB), which has a total acid number (TAN) as high as 1.6mg KOH/g. Acid from high-TAN crude collects in the residue at the bottom of refinery distillation columns where it can corrode units, which deters many refineries from processing such grades. But Chinese refiners have been able to dilute the acidity level by blending their AWB cargoes with light sweet Russian ESPO Blend, allowing them to save costs compared to buying medium sour crude from the Mideast Gulf. Cold Lake, the other grade coming out of the TMX pipeline, has a lower TAN and is currently popular with refiners on the US west coast. But higher costs from potential tariffs could prompt Cold Lake exports to be redirected from the US to buyers in South Korea, Japan, and Brunei — which had all bought the grade previously. Canadian crude appears to have so far displaced medium sour grades in Asia-Pacific, and this trend is expected to continue should TMX crude flows to the region climb higher in 2025. More Canadian crude heading to Asia may displace and free up more Mideast Gulf medium sour supplies to buyers in other regions, including US refiners looking for replacements to their Canadian crude imports. This will also limit the flows of other arbitrage grades like US medium sour Mars crude to Asia-Pacific, which has already seen exports to Asia dwindle in 2024. Opec+ is also due to begin unwinding voluntary production cuts in April 2025, which means Canadian producers will likely have to lower prices sufficiently to attract buyers from further afield. By Fabian Ng TMX exports from Vancouver (b/d) Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Crude production resumes at Karoon’s Brazil Bauna field

24/12/24

Crude production resumes at Karoon’s Brazil Bauna field

Sydney, 24 December (Argus) — Australia-listed oil producer Karoon Energy has restarted its Bauna project offshore Brazil, the firm said today. Output resumed late on 22 December local time, Karoon said. This followed the repair of one of two mooring chains tethering its floating production, storage and offloading (FPSO) vessel, which failed on 11 December , leading the company to cut its 2024 guidance to 27,600-28,100 b/d of oil equivalent (boe/d), down from an earlier 28,700-29,500 boe/d. The second mooring chain is expected to be repaired by mid-January, Karoon said. An investigation into the failure will be jointly undertaken with FPSO owner and operator Ocyan, and its joint-venture partner Altera Infrastructure. Bauna production was about 24,500 b/d before the shutdown, with Karoon expecting to reach this level again in the coming days. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Europe’s refiners eye support from closures

24/12/23

Viewpoint: Europe’s refiners eye support from closures

London, 23 December (Argus) — Another tranche of European refining capacity will close for good next year, but the reprieve for margins in the region may only be temporary. Nearly 400,000 b/d of capacity, around 3pc of Europe's total, is scheduled for permanent closure in 2025, comprising Petroineos' 150,000 b/d Grangemouth refinery in Scotland, Shell's 147,000 b/d Wesseling refinery in Germany and a third of the capacity at BP's nearby 257,000 b/d Gelsenkirchen refinery . Around 30 refineries have closed in Europe since 2000. Among the most recent was Italian firm Eni's 84,000 b/d Livorno refinery in northern Italy earlier this year. And only this month, trading firm Gunvor announced it is mothballing its small upgrading refinery in Rotterdam . The Rotterdam facility had already stopped processing crude in 2020, leaving it peculiarly exposed to the margins between intermediate feedstocks and finished fuels. The refinery has been hit by a 25pc increase in operating costs in the last four years and a squeeze on margins, the latter the result of competition from new refineries outside the region, Gunvor said. Outside Europe, the world has added more than 2.5mn b/d of crude distillation capacity in the last three years. Three brand new refineries have come on stream in the Middle East in that time — Saudi Arabia's 400,000 b/d Jizan, Kuwait's 615,000 b/d Al-Zour with Oman's 230,000 b/d Duqm refineries. More recently, Nigeria's 650,000 b/d Dangote refinery, Mexico's 340,000 b/d Olmeca refinery and Yulong Petrochemical's 400,000 b/d refinery in China's Shandong province started up, all of which are likely to ramp up throughput in 2025. Refinery closures tend to support margins for those that remain. But European refiners' costs continue to rise while demand for their products falls, which means next year's closures are unlikely to be the last. Simpler and smaller refineries are prime candidates for closure as they usually achieve weaker margins. Europe also has plenty of refineries built before 1950 that are still running. These older plants can be more at risk of accidents and breakdowns. And repairs can sometimes cost so much that they tip a refinery into the red. An ongoing concern for European refiners is the trend towards lighter and sweeter crude slates , driven by supply-side dynamics, which is resulting in higher naphtha yields at a time when demand for naphtha from Europe's petrochemical sector is under pressure from a contraction in cracking capacity. But many in the market expect the greatest pressure in 2025 will fall on those coastal refineries in Europe that were built to maximise gasoline output. If, as expected, Dangote continues to shrink Nigeria's demand for gasoline imports , these refineries will be hit hardest. Any refinery that cannot desulphurise all of its gasoline output to the 10ppm required for UK or EU usage will be under intense pressure, as west Africa is presently among the only outlets for European high-sulphur gasoline. Strike support One of the strongest supports for European refining margins in 2025 could come in the form of industrial action if new capacity cuts or closures were to be announced. Refinery workers in the region have shown willing and able in the past to organise large-scale strikes, most emphatically in France. The highest diesel refining margins Argus has ever recorded came in October 2022, when the entire French refining system was shut down by strikes. Another trend to watch out for next year is the continuing shift in the ownership structure of Europe's refining sector. The large integrated oil companies that have dominated the industry for so long have been steadily selling European refining assets to independents and trading firms. The latter are nimbler and able to cut costs more ruthlessly. And with many of them not publicly listed, they are less susceptible to pressure regarding their environmental footprints. There could be more instalments in this story in 2025. Sweden's Preem started accepting bids for its Swedish refining assets in the summer of 2024 and Russia's Lukoil is considering bids for its Burgas refinery in Bulgaria. By Benedict George Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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