Korean refiners see worst over for crack spreads

Market: Crude oil, Oil products, Petrochemicals
31/10/19

South Korean refiners said profit margins in their core fuel production businesses will continue to widen in this year's final quarter after recovering during July-September amid rising demand and maintenance-related supply disruptions in Asia-Pacific.

The region's variable cost margin benchmark, the Singapore gross refining margin, rose to an average of $3.90/bl in the third quarter from a decade low of $1/bl in the previous quarter. The margin was up by 22pc from the year-earlier average of $3.20/bl and marked the highest level for the benchmark since the first quarter of 2018.

S-Oil said profits were helped by seasonal demand gains, tight supplies and an inventory build in preparation for the International Maritime Organisation (IMO) cap on sulphur in marine fuels from 1 January next year. These same factors will help drive further margin gains in the current quarter, the company said, with regional oil product demand projected to rise by 700,000 b/d from a year earlier.

SK Innovation said third-quarter profit margins on gasoline averaged $7.90/bl, up by 39pc from April-June, helped by a temporary fall in Saudi Arabian exports. The average crack spread on diesel widened to $16.20/bl, up by 25pc on the previous quarter and a 5.2pc gain from a year earlier. Even high-sulphur fuel oil margins firmed in the latest quarter amid low inventories, SK said. But these spreads will weaken again in the current quarter and head into next year as the IMO rules kick in.

Refinery turnarounds in the US and Europe will further boost fourth-quarter profit margins on middle distillates, and the upwards momentum for diesel crack spreads will continue and strengthen early next year, SK said. Gasoline margins will be little changed or down slightly amid seasonally lower demand as 2019 winds down, the company said, but these spreads will widen next year as supplies are reduced by lower plant utilisation.

Hyundai Oilbank said it sees gasoline spreads strengthening even in the current quarter because of lower supplies and solid demand in such countries as Indonesia and Vietnam.

S-Oil said paraxylene (PX) profit margins dropped to $300/t in the third quarter, down by 39pc from a year earlier, and will remain weak during October-December after Chinese capacity additions created oversupply. Supply cuts by the weakest PX producers will do little to help because downstream plants are having turnarounds, the refiner said.

Benzene spreads, which plummeted earlier this year, largely recovered in the latest quarter as Asia-Pacific supplies were reduced. Hyundai Oilbank said it expects renewed weakness in benzene margins in the current quarter as US prices drop and downstream maintenance disruptions reduce demand.

Spreads on naphtha-derived olefins were weaker than a year earlier in the July-September quarter. Polypropylene (PP) margins averaged $518/t, down by 6pc, and propylene oxide (PO) profits fell by 24pc to $642/t. But S-Oil said it expects an improvement in the fourth quarter as maintenance cuts supplies and demand for home appliances and packaging rise. Delays in PO capacity expansions also are seen helping. Regional PP capacity additions will exceed demand growth again in 2020 and 2021, the company said.

S-Oil's returned to profit in the third quarter after posting a loss during July-September, but operating earnings fell by 27pc from a year earlier to 230.7bn won ($198.6mn). Profit from its refining business dropped by 42pc the previous year to W99.7bn, while the petrochemical segment posted a 22pc fall to W79.4bn.

SK's operating profit slid by 61pc from a year earlier to W330.1bn, led by an 84pc plunge in its refining segment to W65.9bn. Operating profit from petrochemicals fell by 44pc to W193.6bn.

Hyundai Oilbank's operating profit fell by 34pc to W157.8bn. Profit dropped by 56pc in its core refining business to W88.2bn, while its largest petrochemical unit posted a 92pc gain in operating earnings to W48.2bn.

GS Caltex has yet to report its third-quarter results.

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19/12/24

Viewpoint: Politics, economy key to bitumen recovery

London, 19 December (Argus) — Political change and uncertainty will come to dominate the European bitumen market more than usual in 2025, while demand could decline further than it did in 2024. Market participants are trying to pin down the bottom of the market for bitumen demand, after falling for several years in most of Europe. And support for demand seems far from certain in 2025 given spiralling public debt, political uncertainty and a lack of funding for road maintenance and projects in most European countries. But there could be some positive economic news as interest rates start to fall and inflation returns to more normal levels, while the outlook for oil prices in 2025 is less bullish than previously with plentiful supply forecast. Increased supply and lower crude prices would tend to pressure lower bitumen prices, which could support consumption, given road budgets can be stretched further. Politics seems more unpredictable than ever, with various elections and other changes expected in 2025, often shifting to the right or populist wing in Europe. The necessity of road maintenance and project work to support economies is plain to see for governments, but there is uncertainty on the priority they will be given by some new political forces emerging. Bitumen production is still going to be plentiful in the new year, despite some refinery closures and problems in the past year and more. Issues at both Greek and Turkish refineries, which are powerhouses for Mediterranean bitumen exports, will not have a major impact given the weaker demand in much of north Africa and the lack of available arbitrage routes. Outlets to the US and east of Suez are closed at present and show little sign of re-emerging strongly in the period ahead. Spring maintenance, particularly a February to May shutdown at Algerian Sonatrach's 198,000 b/d Augusta refinery in Sicily, will also limit supply just when demand starts to seasonally rise. In the last viewpoint Argus expected a weaker year for 2024 demand, while also looking at pricing and how differentials to high-sulphur fuel oil (HSFO) could go negative. As winter approaches at the end of 2024 this has happened in the north of Europe and fob cargo discounts have been seen in the eastern Mediterranean all year. Bitumen market fundamentals have drifted further away from those of crude and HSFO in the last year, although a relationship still exists with HSFO maintaining a persistent standing as a price marker for inland bitumen markets for weekly or monthly calculations and for export waterborne prices as the basis with a differential. But Argus expected that traders would seek more arbitrage movements from the European Mediterranean, and this did not come to fruition in 2024, with little seen moving to the US and even less to the Asia-Pacific region. There is not much indication this will change in 2025 with lower prices and plentiful supply in Asia and US supply points. Poorer refining margins may have an impact in 2025 after the strength post-Covid, which will put more renewed pressure on older and simpler refiners to close. These facilities are more likely to produce bitumen. Instead traders will rely on large new ships to feed supply and move bitumen longer distances, a trend already well underway with a number of new ships entering service. Freight costs should stay at elevated levels given the ETS scheme comes into fuller effect in 2025 after first being implemented in 2024. The inclusion of shipping in this EU scheme will oblige shipowners and charterers of vessels from 5,000 gross tonnes to purchase carbon allowances, rising from 40pc of carbon emissions in 2024, to 70pc in 2025, before 100pc in 2026. From uncertainty can come opportunity and with the worst of the economic outlook now behind us then perhaps 2025 can be the beginning of the end in the downtrend for bitumen demand and we start to see vital road maintenance work and infrastructure projects get the funding they need. By Jonathan Weston Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Viewpoint: Nigeria Dangote to affect WAF crude in 2025

19/12/24

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19/12/24

Viewpoint: Nigeria Dangote to affect WAF crude in 2025

London, 19 December (Argus) — The ramp up of operations at Nigeria's 650,000 b/d Dangote refinery, likely to occur next year, will affect west African crude trade flows in 2025. The refinery remains well below full capacity for now — with estimated deliveries averaging just under 260,000 b/d since March — but Nigerian operator Dangote Group is aiming for 350,000 b/d of throughput in a first phase of operations. When this takes place, and Dangote makes full use of its 385,000 b/d monthly allocation deal with state-owned NNPC, it will affect the amount of Nigerian crude left to be exported to the country's key outlet — the European market. Although NNPC only supplied around 202,000 b/d in December, the total volume under the deal is equivalent to around a quarter of Nigeria's crude and condensate exports monthly exports. The deal will eventually bring support to Nigerian crude differentials when European demand is stronger — or at least cushion the decline when demand is weaker. As Dangote ramps up operations, the refiner could widen its crude slate, which could also affect crude trade flows. The refinery will take receipt of a 2mn bl cargo of US light sweet WTI bought from Chevron via a tender that closed November, after a three-month hiatus related to credit issues. Dangote has so far run exclusively on Nigerian crude and WTI, but Nigerian banks eased restrictions on provision of trade finance to the refiner, which could open the door for possible purchases of non-Nigerian west African crude. Sources close to the refinery point to Angolan heavy and medium sweet grades as likely to become part of the refinery's basket intake. Market participants also pointed that the recent WTI tender might signal Dangote's attempt to increase run rates. Meanwhile, NNPC, in order to satisfy both Dangote and already existing commitments, will seek to increase its crude production, which has been severely constrained by theft and vandalism over the past few years. But recent efforts by the government appear to be paying off, with upstream regulator NUPRC reporting that volumes lost to theft and vandalism over the past year averaged 15,000 b/d, compared with over 100,000 b/d in 2021. West African output NNPC is targeting crude output of 2mn b/d by the end of 2024, while the country's president Bola Tinubu has set a crude production goal of 2.6mn b/d by 2027. The latest figures from NUPR have November crude production at 1.49mn b/d and the targets might prove too ambitious, even though output rose from 1.33mn b/d in December last year. Angola, the second largest crude producer in Africa behind Nigeria, has also endured years of output decline since a peak of nearly 2mn b/d in 2008. Argus estimated the country's crude output at 1.14mn b/d in October, broadly unchanged from September, but down from 1.20mn b/d in August. Angola has been trying in recent years to encourage investment in its upstream sector, and recently signed an initial agreement with Shell to explore six oil offshore blocks. The upstream regulator ANPG has a target of awarding 50 oil blocks by the end of 2025 and has said it is planning a licensing round for the first quarter of that year. By Elena Mataro Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Reliability drives New Zealand power mix: Minister

19/12/24

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19/12/24

Reliability drives New Zealand power mix: Minister

Sydney, 19 December (Argus) — New Zealand's conservative coalition government wants to ensure reliable generation, whether that is from coal, oil, gas, or geothermal resources, the country's resources minister Shane Jones told Argus this week. Jones was also clear about the need to draw a distinction between "the expectations on [a] small, open trading nation like [New Zealand] not to use coal and the major hope[s] and needs of the average New Zealander for affordable power, reliable power." "If [reliable power] comes from coal, that's the mix and the menu for the future," he added. Jones argued that existing renewable power sources cannot exclusively provide for New Zealand's energy needs. He instead suggested that his government is interested in promoting alternative power sources such as oil, gas and geothermal, through investments and policy changes. New Zealand's coal-fired power generation surged between July-September, according to the New Zealand's Ministry of Business Innovation and Employment (MBIE). Coal rose to 8pc of total generation from 3pc a year earlier, following a drop in hydroelectric power production. The country burned 363,513t of coal over those months, more than tripling its use for power generation purposes compared to the same period last year. Oil, gas Jones has taken steps to boost the country's oil sector since taking office in late 2023, following the coalition's victory over the centre-left Labour party. The minister introduced the Crown Minerals Amendment Bill in June, a piece of legislation that he described as being "aimed at increasing investor confidence in petroleum exploration and development." Jones told Argus that under the previous government, "people who may have been willing to [make] investment[s] and bring patient capital concluded that New Zealand was no longer available as a destination for oil and gas and this has resulted in a diminution in [oil] investment." The Crown Minerals Amendment Bill will overturn a 2018 ban on offshore oil exploration, which was introduced while Jones was serving in the previous Labour-led coalition government. New Zealand's oil sector increased its annual well spending from NZ$110mn ($63.2mn) in 2018 to NZ$403mn, in the years following the ban in 2018. The total number of active oil permits in the country has plunged from 56 to 37 over the same period, MBIE data show. New Zealand likely houses at least 223.5bn m³ of undiscovered, offshore gas reserves; 249mn bl of undiscovered, offshore oil reserves; and 177mn bl of undiscovered, offshore NGL reserves, mostly scattered around the North Island, according to US Geological Survey (USGS) estimates in 2022. The country's discovered, recoverable reserves are at between 38.3mn-52.7mn bl of oil; 29.4bn-39.8bn m³ of gas; and between 1.2mn–1.4mn t of LPG as of 1 January 2024, according to the MBIE. Besides restarting oil exploration, the Crown Minerals Amendment Bill also seeks to change permitting processes to drive capital into the sector. Permits are currently allocated through a competitive tender process, Jones told Argus this week. The government wants "the flexibility to use alternative processes to match investor interest in the most efficient and effective way by allowing the option of using non-tender methods." MBIE has indicated that the government may start using ‘priority in time' tenders, which allocates permits to the first eligible projects that apply for them, once the bill passes. But the Crown Minerals Amendment Bill does not specify how the government will manage non-competitive tenders. The government is also not using the Crown Minerals Amendment Bill to "specifically intervene in coal mining operations" in New Zealand, Jones said. But coal demand will fall "in the event that [the government is] able to expand the supply of indigenous gas," he noted. Geothermal The government's energy strategy also appears to involve doubling down on domestic geothermal generation, which is New Zealand's second most common source of power. Geothermal generators produced 2,363GWh of power between July-September, accounting for 20.5pc of total generation, in line with historical averages, according to MBIE data. New Zealand's government seems to be trying to push that share up. The government in early December decided to allocate up to NZ$60mn of public infrastructure funding to research for deep, geothermal energy production. The work will focus on drilling geothermal wells up to 6km deep, nearly twice the depth of standard wells. Jones told Argus that New Zealand officials are currently in Japan, discussing supercritical geothermal generation opportunities with engineers and scientists. By Avinash Govind Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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US Army Corps proposes new Illinois River lock

18/12/24

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18/12/24

US Army Corps proposes new Illinois River lock

Houston, 18 December (Argus) — The US Army Corps of Engineers (Corps) has proposed a new lock to replace the LaGrange Lock and Dam (L&D) near Beardstown, Illinois, as part of the Navigation and Ecosystem Sustainability Program (NESP). The project would be the first new lock for NESP, a program that invests in infrastructure along the Mississippi and Illinois rivers. The new 1,200ft proposed LaGrange Lock would allow for passage of more barges in a single lockage, instead of having to split the tow in two with the current 600ft LaGrange Lock. At the moment, most tows trying to pass through the LaGrange lock experience multiple hour delays. The new LaGrange lock would have an estimated cost of $20mn, with a construction timeline of five years. The project area would be located on the west bank of the Illinois River near the 85-year old LaGrange L&D, encompassing 425 acres. Real estate acquisition, design plans and contractors are already in place, said the Corps. The current LaGrange lock would remain in operation and become an auxiliary chamber. The Corps opened the upcoming project to public comments on 11 December and will close on 3 January. NESP has four other projects along the Mississippi River. Another full lock construction project is anticipated for Lock and Dam 25. By Meghan Yoyotte Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Opinion: Better times ahead for refining?

18/12/24

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18/12/24

Opinion: Better times ahead for refining?

London, 18 December (Argus) — We were waiting last month to see whether Opec+ would agree to postpone the start of a tapering mechanism that would eventually see 2.2mn b/d of crude being released back to the market. We are firm believers in the process of market management, which fundamentally underpins our forecasts of global supply-demand and oil prices. So we were not surprised when the alliance agreed to a postponement at its meeting on 5 December. The group actually went a little further than anticipated. Earlier expectations of another one-month delay were trumped by an agreement to hold back until April. The latest timeframe also allows the unwinding process to extend until the end of September 2026, rather than the end of 2025. It also includes an agreement from the UAE to only gradually introduce the permitted 300,000 b/d increase in its quota, — starting in April 2025 and running through to the end of September 2026. It is unlikely to have been a coincidence that Saudi Crown Prince Mohammad bin Salman visited Abu Dhabi immediately ahead of the meeting. Assuming full quota compliance and that the new schedule is fully implemented — but not allowing for any compensation yet to be agreed — this new arrangement goes a long way to ensuring that 2025 brings a balanced and stable market. Our balance shows a small deficit in the first quarter, followed by much less oversupply through the rest of the year than might have been the case if the alliance had started to return its barrels earlier. But the market becomes significantly oversupplied in 2026 should producers move forward with the scheduled unwinding of production cuts. This is a stark reminder of the fundamentals that confront the Opec+ alliance — not just in 2026, but further out as well. Global demand growth is weakening in the face of widespread moves to decarbonise the energy system. But non-Opec+ supply — fossil fuels and renewables combined — will continue to grow strongly, by over 5mn b/d in 2024-28. This will outstrip the likely increase in global oil demand, leaving Opec+ to face the harsh reality of the fading call on its crude. It might at times be a struggle, but we remain confident that the producers will do what is necessary to keep the market balanced and prices supported. If only things were so simple downstream, where — after a spell of stellar results — refiners are suddenly contending with sharply lower margins. Here, there is no industry body to try and regulate supply-demand dynamics — indeed, any attempt to create one would swiftly be condemned as an oligopoly and an infringement of competition laws. Refining margins have certainly fallen sharply in 2024. Average global margins across all configurations were 50-55pc lower than in January this year and 75-80pc lower than in January last year (see graph). A fall of this magnitude was always on the cards, given how high margins had climbed in 2022-23 following the disruption to global product trade caused by sanctions on Russian exports. Currently, margins are broadly in line with pre-Covid levels — and actually somewhat stronger for simpler configurations because of the current strength in fuel oil prices. But there is a body of opinion that the refining sector could benefit from a much tighter market. Since 2019, almost 7mn b/d of CDU capacity has closed, a further 1.1mn b/d is set to close in 2025-26, and there is a strong chance that more closures will be announced. This seems to reflect a generally gloomy perspective on refining — especially in the mature Atlantic basin markets, where oil demand is most likely to have already peaked. But some commentators are now suggesting that perhaps too much capacity has been closed, and too quickly — leaving a market environment that is actually supportive for those willing to remain in the game. Greater refining sector interest in mergers and acquisitions tends to support — or at least feed off— this view. The present difficult macroeconomic environment has made it difficult to maintain the decarbonisation momentum and projections of when global demand might peak have slipped. This is adding fuel to what sounds like an increasingly upbeat refining narrative. For the moment, we remain sceptical that the refining sector is on course for any sort of boom. The recent disruptions to global refined product trade patterns have boosted prices and margins, but they have also served to mask the fact that the last two years have brought with them a significant net increase in capacity. And net capacity is poised to climb further still — the industry is adding more capacity than it is retiring (see graph). In 2026, global oil demand is expected to be running some 7.8mn b/d higher than it was back in 2016, whereas installed CDU and splitter capacity is only expected to be around 4.4mn b/d higher. This would certainly suggest a tighter refining environment. But this ignores the growing role of non-refinery sourced products in meeting global oil demand. Over the same period, the use of non-refinery sourced products — such as biofuels and NGLs that are derived from gas processing — is expected to grow by close to 5mn b/d, which is equivalent to almost two thirds of the increase in total demand. A very different picture starts to emerge when you take this into account. Instead of outstripping net capacity additions, the cumulative growth in demand for refined products now lags the growth in installed capacity (see graph). Further closures would act to head off this emerging capacity surplus. But the growing perception that there might be better times ahead for refining could encourage new entrants to the sector and prolong the operating life of assets that otherwise would have been retired. This article was first published in Argus Consulting's Argus Fundamentals, a monthly report examining global oil supply-demand dynamics now and in the future. The report is published every third Wednesday of the month. Global oil balance mn b/d 2022 1Q23 2Q23 3Q23 4Q23 2023 1Q24 2Q24 3Q24 4Q24 2024 2025 2026 Demand North America 22.42 22.17 22.83 22.95 22.96 22.73 22.18 22.65 22.99 22.96 22.70 22.72 22.77 Europe 14.18 13.79 14.19 14.34 14.06 14.09 13.52 14.29 14.57 14.23 14.15 14.16 14.07 Asia-Pacific 36.06 37.66 37.76 37.40 38.12 37.74 38.70 38.10 37.15 38.34 38.07 38.70 39.02 Latin America 8.42 8.38 8.49 8.66 8.58 8.53 8.42 8.65 8.75 8.69 8.63 8.76 8.91 Middle East 9.19 9.05 9.24 9.79 9.11 9.30 9.03 9.37 9.90 9.38 9.42 9.61 9.85 FSU 4.10 4.44 4.24 4.55 4.63 4.46 4.36 4.50 4.26 4.48 4.40 4.48 4.55 Africa 4.37 4.39 4.31 4.27 4.37 4.33 4.34 4.24 4.38 4.21 4.29 4.40 4.50 Total 98.74 99.88 101.05 101.97 101.83 101.18 100.56 101.82 102.00 102.30 101.67 102.84 103.67 Year-on-Year change 1.74 0.73 3.79 3.32 1.91 2.44 0.68 0.77 0.03 0.47 0.49 1.17 0.83 Supply Non-Opec crude and NGL US 17.92 18.84 19.19 19.71 19.98 19.43 19.45 20.24 20.28 20.28 20.06 20.54 20.90 Canada 5.43 5.52 5.13 5.54 5.85 5.51 5.69 5.55 5.64 5.81 5.67 5.87 5.96 Europe 3.27 3.38 3.32 3.22 3.33 3.31 3.31 3.24 3.17 3.24 3.24 3.27 3.31 Latin America 7.69 8.27 8.35 8.60 8.78 8.50 8.75 8.58 8.58 8.80 8.68 9.01 9.39 Africa 2.42 2.31 2.39 2.46 2.44 2.40 2.39 2.34 2.45 2.40 2.40 2.54 2.55 Russia 11.00 11.25 10.89 10.80 10.90 10.96 10.82 10.68 10.44 10.37 10.58 10.42 10.70 Other FSU 2.84 2.97 2.90 2.72 2.89 2.87 2.89 2.78 2.75 2.74 2.79 2.82 2.86 Middle East 2.99 2.96 2.98 2.95 2.97 2.96 2.92 2.94 2.95 2.96 2.94 3.00 3.08 Asia-Pacific 7.05 7.16 7.10 6.93 7.01 7.05 7.13 7.10 6.91 7.05 7.05 7.15 7.06 Total non-Opec supply 60.61 62.67 62.25 62.92 64.14 63.00 63.36 63.45 63.17 63.64 63.41 64.61 65.83 Opec Opec crude 27.83 27.85 27.31 26.69 26.92 27.19 26.76 26.73 26.49 26.56 26.63 27.01 28.18 Opec NGL and condensate 5.12 5.26 5.26 5.26 5.26 5.26 5.40 5.40 5.40 5.40 5.40 5.48 5.73 Total Opec supply 32.95 33.11 32.58 31.95 32.18 32.45 32.16 32.13 31.89 31.96 32.04 32.49 33.91 Biofuels 2.90 2.58 3.19 3.54 3.19 3.12 2.82 3.45 3.73 3.42 3.35 3.45 3.54 GTLs and CTLs 0.55 0.58 0.58 0.56 0.57 0.57 0.59 0.58 0.57 0.57 0.58 0.57 0.56 Processing gains 2.32 2.32 2.37 2.40 2.35 2.36 2.32 2.40 2.45 2.39 2.39 2.40 2.42 Global supply 99.33 101.26 100.96 101.37 102.43 101.51 101.24 102.02 101.81 101.98 101.76 103.51 106.26 Strategic stocks -0.74 0.03 -0.13 -0.00 -0.04 -0.04 0.13 0.08 0.10 0.12 0.11 0.04 0.00 Global balance* 1.32 1.35 0.04 -0.59 0.65 0.36 0.56 0.12 -0.28 -0.44 -0.01 0.63 2.59 Opec+ crude output** 37.05 37.07 35.82 34.66 35.03 35.65 34.56 34.08 33.77 33.60 34.00 34.37 35.90 *equivalent to global stock change, assuming Opec+ production cuts are unwind as per 5 December 2024 announcements **not including Iran, Venezuela, Libya Change in global oil demand vs CDU capacity mn b/d Global refining margins by key configuration $/bl Changes in global CDU capacity: Firm plans mn b/d Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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