Asia currencies drop as dollar gains raise import costs

Market: Crude oil
26/09/22

Asia-Pacific currencies fell further against the dollar in Asia trading today, adding to costs for the region's big importers of oil and other commodities, while the UK pound slumped by almost 5pc to a near 40-year low.

The Korean won, Japanese yen and Indian rupee all weakened against the dollar in early trading, extending multi-year lows.

The Chinese yuan weakened to above Yn7.15 to the dollar. That prompted China's central bank to intervene to prop up the yuan by raising the cost of shorting the currency, which weakened to more than Yn7 to the dollar earlier this month for the first time in over two years.

Aggressive moves by the US Federal Reserve to raise interest rates have boosted the value of the dollar against rival currencies in recent months. Oil and other commodities are priced in dollars, so a stronger US currency adds to costs for importers.

The biggest declines were recorded by the UK pound. Sterling dropped by 4.7pc against the dollar in early trading to as low as $1.03, before recovering slightly to just under $1.06 at 10.30am Singapore time (02:30 GMT), still down by around 2.6pc.

The UK government's plans to cut taxes, announced by the country's new chancellor Kwasi Kwarteng last week, have accelerated a sell-off in sterling.

Oil prices were largely steady, with the Ice front-month November Brent contract edging higher to $86.36/bl at 10.30am Singapore time. The contract slumped by almost 5pc to close at $86.15/bl on 23 September.

By Kevin Foster

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

News

03/01/25

Viewpoint: US sour values poised to maintain support

Houston, 3 January (Argus) — US sour crude prices are poised to maintain recent highs if increased US Gulf coast refinery runs continue to meet market expectations of a tight market. US Gulf medium sour Mars is averaging a near 30¢/bl premium to the Nymex-quality WTI benchmark for the February US trade month to date, and held a roughly 65¢/bl premium during the January trade month, the highest level since July. January Mars averaged around $2.40/bl below March Ice Brent, marking its narrowest average discount to Ice Brent two months forward since the August trade month. US Gulf sours reached multi-year highs on 18 December supported by tight supply and high demand. Refinery runs have increased with improving margins, tightening the supply of sour crude in the US and further boosting differentials. Refinery runs nationwide rose last week by 39,000 b/d to 17mn b/d but were 89,000 b/d lower than the same week in 2023, according to the Energy Information Administration (EIA). Companies were also heard short-covering US sours in an already tight market, likely exacerbated by end-of-year inventory drawdowns for tax purposes. Recent higher prices follow much lower relative values for Mars starting in the fall when refinery runs fell because of unfavorable margins, maintenance and US Gulf coast hurricane-related outages combined with lower export demand. Mars exports have been limited by competitive Middle Eastern term pricing for shipments to Asia-Pacific and European destinations, despite the continuation of Opec+ production cuts tightening supply. Also, blending has emerged in China for TMX-sourced Canadian heavy crude with light Murban as a Mars replacement . Offshore pipeline maintenance in October also pushed typically Texas-delivered volumes over to the Louisiana Gulf coast, adding pressure to the medium sour crude market in the region. But increased US Gulf refinery demand is leading to higher heavy Canadian crude prices at the US Gulf coast, alongside support from Trans Mountain Expansion (TMX) pipeline exports and higher US midcontinent refinery demand tightening supply. Western Canadian Select (WCS) Houston averaged around a CMA Nymex -$4.00 for January trade. The January WCS Houston discount to Mars averaged about $4.60/bl but was inside $4/bl for November and December volumes. The higher Canadian crude prices are making it less economical for US refiners to blend heavy low-TAN imports with Permian WTI as a cheaper alternative substitute for Mars or other medium sours. Tax-related end-of-year inventory draw downs had tightened the market heading into the new year, but this was exacerbated by the US Strategic Petroleum Reserve (SPR) being slated to receive 2.5mn bl of domestic sour crude deliveries in the first three months of 2025 . However, LyondellBasell's plan to begin shutting down its 264,000 b/d Houston, Texas, refinery starting in January and stop refining crude completely by the end of the first quarter will reduce Gulf coast sour demand. Between May and September, the facility imported just under 200,000 b/d on average, with roughly 80pc being Canadian and Colombian sour crudes. Offshore US Gulf production is also expected to increase, which could ease a tight market and weigh on differentials. Chevron brought production from its 75,000 b/d Anchor platform into the Mars system in 2024, while Southern Louisiana Intermediate (SLI) and Texas-delivered SGC and HOOPS flows will receive crude from new facilities in the coming year. But EIA forecasts show total US Gulf production essentially flat from 2023 as new output is offset by natural declines. Other price-influencing factors in the coming year are less certain. Concerns surrounding the potential impact of US president-elect Donald Trump's plan to impose a 25pc tariffs on all imports from Canada and Mexico have bolstered sour crude prices in the US over recent weeks. Additionally, US medium sour crudes have been supported by Opec production cuts, with the recent decision to delay unwinding those cuts yet again, adding to the January value boost. The next Opec and Opec+ meetings are scheduled for 28 May. By Mykah Briscoe and Amanda Smith Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Find out more

News

Viewpoint: Med may take more Mideast crude in 2025

03/01/25

News

03/01/25

Viewpoint: Med may take more Mideast crude in 2025

London, 3 January (Argus) — The Mediterranean region's capacity to absorb returning sour crude output in 2025 will hinge on nimble pricing strategies by Saudi Arabia and Iraq. The Mediterranean imported around 4.67mn b/d of crude in 2024, down from 4.92mn b/d in 2023, Vortexa data show. The drop follows heavy spring refinery maintenance, unplanned refinery outages and weak product margins that prompted some refiners in the region to cut crude runs. But competitive pricing by Mideast Gulf crude producers could help entice Mediterranean buyers during the seasonal uptick in demand for transport fuels this summer, and the scheduled completion of repairs at Motor Oil Hellas' 180,000 b/d Corinth refinery in Greece in the third quarter could help absorb a planned production increase from Opec+. Eight Opec+ members ꟷ Saudi Arabia, Iraq, Russia, Kuwait, the UAE, Kazakhstan, Algeria and Oman ꟷ agreed last month to postpone the return of 2.2mn b/d of production cuts for a third time to April 2025. They now intend to return this over an 18-month period rather than the previously planned 12-month period. Saudi Arabia has accounted for 1mn b/d of this 'voluntary' production cut since July 2023, but Saudi crude deliveries to the Mediterranean still edged up to 241,000 b/d in 2024, from 238,000 b/d in 2023. State-controlled Aramco's consistent cuts to its formula prices in recent months left its December 2024 prices for Mediterranean customers on average $2.13/bl cheaper than its January 2024 prices. Comparatively, Aramco's Mediterranean formula prices rose on average by nearly $5/bl across 2023 when sour crude was in short supply but demand was higher. This adaptive pricing strategy has helped Aramco retain market share in the Mediterranean at a time of overall weaker demand. Deliveries of Iraq's Basrah crude to the Mediterranean region declined by 27pc on the year to average 409,000 b/d in 2024, largely due to longer journey times around South Africa to avoid Yemen-based Houthi attacks on shipping in the Red Sea. But Mediterranean interest in 2025 could increase should Basrah be forced out of Asia-Pacific, where Canada's Trans Mountain Expansion has enabled increased Chinese purchases of Canadian heavy sour Cold Lake and Access Western Blend, which require lighter crudes for blending. The EU embargo on seaborne imports of Russian crude has cut off Europe's access to medium sour Urals, with the exception of non-EU member Turkey. Northwest European buyers can turn to Norway's Johan Sverdrup grade but Mediterranean buyers have been left without a local medium sour crude since Kirkuk exports, from Turkey's Ceyhan port, were halted in March 2023 by a dispute between Iraq and the Kurdistan Regional Government. Even if Kirkuk exports resume in the coming months, it is unclear if these will return to previous levels of around 500,000 b/d, given upstream challenges in Iraqi Kurdistan and Iraq's Opec+ commitments. In the absence of local rivals, Saudi Arabia and Iraq are well poised to direct more supply into the Mediterranean, with competitive pricing. Aramco's ability to ship from Egypt's Mediterranean Sidi Kerir port has increased its appeal as it delivers supplies within days. Rebuilding confidence in Libya Libya's recent two-month blockade, sparked by a leadership crisis at the central bank, again shone a light on the country's fragile politics. Although output has recovered since force majeure ended on 3 October, confidence in Libya's ability to reliably supply crude has waned, diminishing its appeal in an oversupplied market. Spot assessments for Libya's largest grade, Es Sider, averaged a $1.46/bl discount to the North Sea Dated benchmark in November, and state-owned NOC set the grade's November formula price at a $2.25/bl discount for term customers. Both were the lowest since December 2022, as sellers aimed to entice buyers and allay reliability concerns. But Libyan production has proven resilient over the past decade, quickly rebounding after armed conflict and several politically-motivated disruptions. NOC reported crude and condensate output at a near 12-year high of 1.4mn b/d in early December. By the end of last month, the company said it had increased to 1.47mn b/d. And foreign producers are still keen on the country, with Italy's Eni, BP, Austria's OMV and Spain's Repsol resuming exploration campaigns , the first since 2014. By Melissa Gurusinghe Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

News

US crude output at record 13.46mn b/d in Oct: EIA

31/12/24

News

31/12/24

US crude output at record 13.46mn b/d in Oct: EIA

Calgary, 31 December (Argus) — US crude production in October rose to a record high 13.46mn b/d on sustained strength in Texas and New Mexico, the Energy Information Administration (EIA) said today in its Petroleum Supply Monthly report. Output rose from 13.2mn b/d in September and from 13.15mn b/d in October 2023. The prior record of 13.36mn b/d was set in August. Texas, home to 44pc of the country's crude production, pumped out a record 5.86mn b/d in October, up from 5.8mn b/d in September and up from 5.57mn b/d in October 2023. New Mexico, which shares the prolific Permian basin with Texas, produced 2.08mn b/d in October, ticking down by 5,000 b/d from record highs set in August and September but up from 1.8mn b/d in October 2023. US offshore crude output in the Gulf of Mexico rebounded to 1.85mn b/d in October after hurricane activity in September cut production to 1.57mn b/d. Still, US Gulf of Mexico output was down from 1.94mn b/d in October 2023. Monthly production changes inland were mixed, with North Dakota falling to 1.16mn b/d in October from 1.21mn b/d in the month prior. Bakken shale basin producers had to contend with wildfires during the month and effects are still lingering for some, state officials said earlier this month. Colorado output rose in October to the highest in more than four years at 499,000 b/d. This was up from 476,000 b/d in September and the highest level for the state since March 2020. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Viewpoint: 2025 Hardisty heavy diffs may remain strong

31/12/24

News

31/12/24

Viewpoint: 2025 Hardisty heavy diffs may remain strong

Calgary, 31 December (Argus) — Heavy crude spot differentials in Alberta are expected to remain strong into next year, even with growing oil sands production and possible US import tariffs. After years of cost-overruns and construction delays, the 590,000 b/d Trans Mountain Expansion (TMX) commenced on 1 May, nearly tripling the capacity of crude able to reach Canada's Pacific coast and providing Alberta oil sands producers with increased access to buyers on the US west coast and Asia-Pacific. Extra egress capacity for Alberta crude westward has pulled previously apportioned volumes away from Enbridge's 3mn b/d Mainline system — Canada's main method of export to ship crude south to US refiners in the midcontinent and Gulf coast. In the fourth quarter, apportionment averaged just over 1pc for both light and heavy crude on the Mainline, significantly lower than the average apportionment of 21pc for lights and heavies in the fourth quarter last year. While president-elect Donald Trump's looming blanket tariff on all Canadian imports would re-direct more Albertan crude westward via TMX to Asia- Pacific buyers, many believe the tariff would be too harmful to US midcontinent refiners for Trump to actually carry out his threat. Prior to TMX's commencement, high apportionment combined with rising crude production heading into the winter months forced more crude onto railcars, which typically requires a $15/bl to $20/bl spread between Western Canadian Select (WCS) at Hardisty Alberta, and Houston, Texas, for uncommitted shippers to profit. With the redirection of apportioned volumes to buyers in the west, Canadian heavy spot differentials in Alberta have strengthened in a quarter when discounts have generally widened in recent years. Argus's WCS Hardisty assessment averaged a $12.08/bl discount to the CMA Nymex WTI during fourth quarter Canadian trade cycle dates, $11.52/bl stronger than the $23.61/bl discount averaged in the fourth quarter a year prior. Yet, crude output in Alberta's key oil sands is expected to rise heading into 2025, with production levels reaching record-high levels this year. Alberta crude output was 4.2mn b/d in October, according to the latest Alberta Energy Regulator (AER) data, up by 9.4pc year from a year earlier and the second highest monthly production on record. Alberta oil sands producers, meanwhile, have increased their crude production guidance for next year. Suncor expects to pump out 810,000-840,000 b/d across its upstream sector in 2025, up by 5pc from 2024. Cenovus expects to increase production next year by 4pc to between 805,000-845,000 b/d of oil equivalent (boe/d), and Imperial Oil plans to boost upstream production by 2pc to 433,000-456,000 boe/d. Egress capacity remains ample despite rising production heading into 2025. Total crude pipeline egress capacity out of Alberta is expected to be over 4.6mn b/d in 2025, with shippers still yet to utilize uncommitted space on the 890,000 b/d Trans Mountain pipeline. About 712,000 b/d or 80pc of the system is reserved for contracted shippers, with the remaining 20pc available for uncontracted shipments. With unconstrained egress capacity expected to persist, Suncor and Cenovus have both assumed WCS at Hardisty will average a strong $14/bl discount to WTI in 2025. In the near term, Trump's plans to impose a blanket 25pc tariff on all Canadian imports would threaten some US demand for Canadian crude. Yet, while some traders are pricing in the reality of US tariffs, most market participants are skeptical of whether Trump's tariff plans would extend to Canadian crude due to the co-dependency between Albertan producers and some US refiners. US midcontinent refiners, many of whom were financial backers of Trump's 2024 presidential campaign, are dependent on Canadian crude given a lack of access to alternative heavy sour crudes suited for their refineries. Canadian grades represent approximately 70pc of the US midcontinent refinery feedstock, with the remainder largely sourced in the US. US importers may take more crude from countries including Saudi Arabia, given the country has plenty of spare capacity to increase the production of heavy sour crude favored by US midcontinent refiners. However, replacing Canadian crude with waterborne supplies would result in a substantial increase in tanker demand. In August, only around 370,000 b/d of the 3.8mn b/d of Canadian crude imported by US refiners moved on tankers, Vortexa data show. Even if US refiners can replace Canadian and Mexican heavy crude, they are expected to face higher landed costs and, potentially, less reliable supplies. By Kyle Tsang Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

News

Viewpoint: US Supreme Court tees up more energy cases

31/12/24

News

31/12/24

Viewpoint: US Supreme Court tees up more energy cases

Washington, 31 December (Argus) — The US Supreme Court is on track for another term that could significantly affect the energy sector, with rulings anticipated in the new year that could narrow environmental reviews and challenge California's authority to set its own tailpipe standards. The Supreme Court earlier this month held arguments in Seven County Infrastructure Coalition v Eagle County, Colorado , a case in which the justices are being asked to decide whether federal rail regulators adequately studied the environmental effects of a proposed 88-mile railway that would transport 80,000 b/d of crude. A lower court last year found the review, prepared under the National Environmental Policy Act (NEPA), should have analyzed how building the project would affect drilling and refining. Business groups want the Supreme Court to issue an expansive ruling that would limit NEPA reviews only to "proximate" effects, such as how rail traffic could affect nearby wildlife, rather than reviewing distance effects. The court recently agreed to hear a separate case that could restrict California's unique authority under the Clean Air Act to issue its own greenhouse gas regulations for newly sold cars and pickup trucks that are more stringent than federal standards. Oil refiners and biofuel producers in that case, Diamond Alternative Energy v EPA , say they should have "standing" to advance a lawsuit challenging those standards — even though they could now show prevailing in the case would change fuel demand — based on the alleged "coercive and predictable effects of regulation on third parties". These two cases, likely to be decided by the end of June, follow on the heels of the court's blockbuster decision in June overturning the decades-old "Chevron deference", a foundation for administration law that had given federal agencies greater flexibility when writing regulations. Last term, the court also limited agency enforcement powers and halted a rule targeting cross-state air pollution sources. This term's cases are unlikely to have as far-reaching consequences for the energy sector as overturning Chevron. But industry officials hope the two pending cases will provide clarity on issues that have been problematic for developers, including the scope of federal environmental reviews and the ability of industry to win legal "standing" to bring lawsuits. Two other cases could have significant effects for the oil sector, if the court agrees to consider them at a conference set for 10 January. Utah has a pending complaint before the court designed to force the US to dispose of 18.5mn acres of "unappropriated" federal land in the state, including oil-producing acreage. Utah argues that indefinitely retaining the land — which covers about a third of Utah — is unconstitutional. In another pending case, Sunoco and other oil companies have asked for a ruling that could halt a series of lawsuits filed against them in state courts for alleged damages from greenhouse gas emissions. President-elect Donald Trump's re-election could create complications for cases pending before the Supreme Court, if the incoming administration adopts new legal positions. Trump plans to nominate John Sauer, who successfully represented Trump in his presidential immunity case, as his solicitor general before the Supreme Court. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more