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WTI crash reverberates around spot markets

  • Spanish Market: Crude oil, LPG, Natural gas, Oil products
  • 21/04/20

The historic collapse of the WTI Nymex crude futures well into negative territory today sent shockwaves across spot physical markets, in crude and beyond, resulting in a mix of negative outright prices, bloated differentials and total dislocations.

Nymex WTI May light sweet crude futures fell by $55.90/bl to settle at -$37.63/bl amid concerns about storage availability as shutdowns and other efforts to contain the Covid-19 pandemic dry up global petroleum demand. The more heavily traded June contract fell by $4.60/bl to $20.43/bl.

The May contract continues to trade tomorrow before expiry.

Many Argus volume weighted average prices largely went negative as differentials of deals struck earlier in the day lagged the afternoon descent of the futures price.

WTI Houston finished the day at less than -$25/bl outright and Mexican heavy sour Maya fell to around -$15/bl outright.

May Light Louisiana Sweet (LLS) maintained relative support against the falling US benchmark, trading at a $50/bl premium to Cushing, the highest recorded premium for the grade in Argus records. But when applied to the Argus WTI Formula basis, the outright LLS index price was barely more than $12/bl, roughly $1/bl higher than the lowest LLS outright price on record.

Refined products mixed

In refined products, much of the vacuum gasoil (VGO) market already had moved on to trading against June Nymex WTI and July Brent crude before this week, and today sellers were heard only willing to transact against July Brent. Argus VGO differentials to the prompt May Nymex WTI value jumped by nearly $60/bl from the previous trading session when the differential was in the $8/bl range. The premium to June Nymex WTI was in the $3-$6/bl range.

Low-sulphur fuel oil (LSFO) traders turned to Ice Brent for benchmarking today, and outright values rose to nearly $30/bl upon a more than $4/bl premium to Ice Brent. LSFO has been searching for a widely accepted benchmark since the global 0.5pc sulphur cap for marine fuel emissions went into effect this year. Deals have been done against both WTI and Brent as well as other benchmarks like Nymex ultra-low sulphur diesel (ULSD) and Russian M100 fuel oil.

Elsewhere in the refined products value chain, market participants essentially ignored the WTI plunge as refined products futures fell more modestly. Nymex RBOB gasoline today fell by 4.24¢/USG to $0.6683/USG and ULSD fell by 0.0685¢/USG to $0.8878/USG, and regional physical grades behaved accordingly.

Some regional gasoline values actually rose against the benchmark amid bolstered hopes for higher than previously expected summer fuel demand.

NGLs and natural gas

Propane in the Enterprise Products Partners cavern at Mont Belvieu, Texas, ended last week at 84.2pc of the value of WTI, the highest ratio in at least six years of recordkeeping. The spread is a gauge on propane's competitiveness with refined product naphtha to feed ethylene plants internationally.

Today, that ratio turned negative because of WTI's drop below $0/bl. But demand for US LPG remains strong, propping up values domestically. LST propane at Mont Belvieu shrugged off steep declines in crude today, trading only slightly under the previous session, as netbacks on paper to Asia kept spot fob discussions well above export cargo cancellation levels, at 7¢/USG or more.

Meanwhile in US natural gas, which long ago stopped tracking crude prices, futures shot up by nearly 10pc today on the prospect that the oil price collapse will accelerate production slowdowns and shut-ins, which would crimp associated gas output. Nymex gas for May delivery at the Henry Hub was up by 17.1¢/mmBtu to settle at $1.924/mmBtu.

By Mark Babineck and Daphne Tan

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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.

15/12/25

PdV says cyber attacks contained

PdV says cyber attacks contained

Caracas, 15 December (Argus) — Venezuelan state oil firm PdV said cyber attacks on company systems that started on 13 December have been contained. In an internal communication seen by Argus over the weekend PdV told workers that all of the company's computers had been infected with a virus that erased information. The attack appeared to be focused on operations in the Oriente Norte division, where a number of pipelines, refineries and upgraders of Orinoco extra heavy crude operate. Workers had been instructed not to turn on any work computers until further notice. Exiled oil union boss Ivan Freites posted on social media on Sunday that the attack shut down operating and control systems for docks, production and refineries in the region. "Workers are operating in emergency mode, under extremely risky conditions," Freites said. US oil major Chevron, which is a partner with PdV in four joint ventures, including two located in or near the Oriente Norte area, said its operations continue without disruption. By Carlos Camacho Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

EU to dilute Ice vehicle phase out: German lawmaker

15/12/25
15/12/25

EU to dilute Ice vehicle phase out: German lawmaker

Brussels, 15 December (Argus) — The European Commission is likely this week to dilute its plan to phase out sales of new internal combustion engine (Ice) vehicles by 2035, according to a lawmaker. "The ban on internal combustion engines is history," said Manfred Weber, the chair of parliament's largest centre-right group EPP. He said the commission will present on 16 December an automotive package that "will revise the CO2 standards for cars, reversing the disastrous ban on internal combustion engines". Weber is a member of Germany's CDU/CSU party, as is commission president Ursula von der Leyen. German chancellor Friedrich Merz has called on the EU to allow the sale of vehicles with highly efficient combustion engines, plug-in hybrids and range-extender EVs beyond 2035. This had faced pushback, with more than 150 European e-mobility firms requesting the commission "stand firm" on its 2035 target. An EU official said the target is now likely to be for a 90pc GHG reduction from 2035 for new vehicles. "As it stands the targets for 2030, but also 2035, are not realistic," said Sigrid de Vries, director general of the European Automobile Manufacturers' Association (ACEA). "Even with a 90pc target [for reducing GHG by 2035], make no mistake, that will be very, very challenging." The European motor industry has already flagged the possibility of huge fines for manufacturers should they fail to meet existing emissions targets, which are for a 15pc reduction by 2029 compared with a 2021 baseline, and a 55pc reduction from the same baseline in 2030-34. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: West Africa refineries key to hub status

15/12/25
15/12/25

Viewpoint: West Africa refineries key to hub status

London, 15 December (Argus) — West Africa is developing into a regional refining and trading hub, backed by state aims to achieve greater refined product self-sufficiency and export capacity. The extent of further change in 2026 will be defined by the fortunes of existing and fledgling refining projects, including Nigeria's 650,000 b/d Dangote and a clutch of smaller plants. The independently-owned Dangote refinery continues to upend regional and global refined product markets, reducing west Africa's reliance on imports. Since gasoline production began at the refinery in September 2024 , Nigeria — the region's largest gasoline importer — has seen net gasoline imports steadily fall to a historic low of 40,000 b/d in September this year, from 332,000 b/d just a year earlier, Kpler data show. Meanwhile, Nigeria's net middle distillate exports hit a record 145,000 b/d in July, up from 82,000 b/d on the year, and the country has broadly been a net exporter of these products since May 2024. As a result, Nigeria and west Africa as a whole are pulling on considerably less gasoline and middle distillates such as gasoil and jet fuel. Year-to-date, the region — spanning Mauritania to Angola — has seen gasoline imports drop by a quarter on the year to 337,000 b/d, while jet imports have collapsed to 4,000 b/d, both the lowest since at least 2016 when Kpler records began. West African gasoil imports have fallen to a five-year low of 162,000 b/d. Dangote has inarguably transformed regional oil product market dynamics, having proven robust through multiple bouts of maintenance works, and there is room for it to capture more of the domestic gasoline market in the year ahead. The same cannot be said for Nigerian state-owned NNPC's refining assets. The company restarted a 60,000 b/d section of the 210,000 b/d Port Harcourt refinery late in 2024 only to shut it again in May this year, while the 125,000 b/d Warri plant restarted in December 2024 before going offline the following month. This underscores the challenges of modernising or rehabilitating long-mothballed facilities along the west African coast. Refiners in other west African countries are expanding their offerings to regional consumers, further eroding market share previously claimed by European traders. Angola's 30,000 b/d Cabinda refinery is up and running , producing mainly gasoil and jet fuel for the domestic market from its first phase. This is likely to curb Angolan middle distillate import demand, with the refinery — a 90:10 joint venture between UK-based Gemcorp and state-owned Sonangol — meeting 10pc of domestic demand. Cabinda's second phase will add gasoline production, but not until around 2028. Angola imported 20,000 b/d of gasoline in January-August, according to Kpler, around 40,000 b/d of diesel and gasoil, and negligible amounts of jet fuel. In Ghana, the 45,000 b/d Tema Oil Refinery (TOR) continues works to restore nameplate capacity. The privately-owned 120,000 b/d Sentuo Oil Refinery and the country's smaller Platon and Akwaaba modular refineries operate sporadically. TOR's return may be a surprise for 2026, with the operator reporting in October that turnaround activities were taking place "aimed at preparing the refinery for a safe and efficient restart". The refinery's prospects look stronger than those of Ghana's Petroleum Hub Development Corporation (PDHC), which appears to have postponed construction of the first of three planned 300,000 b/d refineries since John Mahama returned to power in January for a non-consecutive second term. The PDHC delays highlight the long lead times typical for large-scale refining projects. Dangote itself took nearly a decade to move from its first loan agreement to eventual start-up. Other projects announced this year are unlikely to advance in 2026, making operating or near-complete refineries in Nigeria, Angola and Ghana critical for the region's push towards a bigger role in the downstream market. By George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: UK offshore faces deeper consolidation

15/12/25
15/12/25

Viewpoint: UK offshore faces deeper consolidation

London, 15 December (Argus) — UK offshore oil and gas operators are bracing for more consolidation next year after the government confirmed the Energy Profits Levy (EPL) will remain in place until March 2030. The EPL, introduced in 2022, raised the headline tax rate on upstream profits to 78pc from 40pc, reshaping project economics and company strategies. Executives argue the current price environment is "far from windfall" and describe the fiscal regime as punitive. Faced with higher taxes and tighter margins, operators are seeking scale and cost savings through mergers and joint ventures. Shell and Norway's state-controlled Equinor formally launched their new UK offshore joint venture, Adura, earlier this month after agreeing the deal in 2024. Also this month, TotalEnergies agreed to form a UK-focused joint venture with Neo Next , an independent owned by Spain's Repsol and Norwegian private equity firm HitecVision. The new business, Neo Next+, will hold more than 50pc of the Elgin-Franklin gas complex, where TotalEnergies is already operator, and interests in several other fields. The deal will leave BP as the only European major still directly operating a UK portfolio itself. Other examples of operators restructuring to manage UK exposure include Italian firm Eni exchanging its UK upstream assets for a stake in North Sea producer Ithaca Energy , and UK independent Harbour Energy merging with Germany's Wintershall Dea in an $11.2bn transaction that added assets offshore Norway and in other regions. Both those deals closed in 2024. Although Harbour has since cut hundreds of North Sea offshore jobs, it is not giving up on the UK. It agreed a deal this month to increase its interest in the UK's Catcher field to 90pc, from 50pc, via a takeover of junior independent Waldorf Production. The deal, which will also give Harbour a stake in the Kraken field, will add 20,000 b/d of oil equivalent (boe/d) to the firm's UK production. Harbour is the UK's largest independent producer for now, with output of 156,000 b/d of oil equivalent (boe/d) from the UK continental shelf in January-September this year. But analysts who track the sector estimate Adura will eventually produce more than 200,000 boe/d. And TotalEnergies expects Neo Next+ to reach 250,000 boe/d in 2026. While operators consolidate to help manage fiscal pressure, the outlook for fresh projects is limited by government policy. Greenfield oil and gas developments in the UK will be scarce in the 2026 and beyond. The government's ban on new licences remains in force. Its North Sea Future Plan, released on budget day, allows limited additional production near existing producing fields. Operators are expected to direct capital spending to near-field tiebacks and other work to lift output from existing developments. Two greenfield projects that could see first oil or gas towards late 2026 are Rosebank and Jackdaw. Equinor and Ithaca continue to work on Rosebank. Shell continues to work on Jackdaw. But the government must still decide whether the resubmitted environmental plans meet the required standard. As for Ithaca Energy's Cambo development, west of Shetlands, which has yet to reach a final investment decision , analysts are increasingly sceptical that it will proceed at all. After the budget, investment bank Stifel issued a "sell" note on Ithaca's shares. Its valuation now assumes Ithaca's 100pc-owned Cambo project will not go ahead. By Jon Mainwaring Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Aramco Jafurah project still in commissioning: Resend

15/12/25
15/12/25

Aramco Jafurah project still in commissioning: Resend

Clarifies distinction between raw gas and sales gas. Story originally published on 11 December Dubai, 15 December (Argus) — Saudi state-controlled Aramco has begun to commission the first phase of its giant Jafurah natural gas project, but is yet to begin full commercial operations, according to the company's executive vice president of gas Abdulkarim Al-Ghamdi. "Jafurah… we started the commissioning last week," Al-Ghamdi told the Middle East Gas Conference in Dubai on Wednesday. "And that will be commissioned fully now, for production, before year-end." The phase is "on schedule" and "in advanced commissioning", he said. Al-Ghamdi's comments are the first from Aramco since the Saudi finance ministry said production at Jafurah had begun. In its 2026 budget released last week the ministry listed "completion of the first phase of the Jafurah gas plant construction and commencement of production with a capacity of 450mn ft³/d," as one of the country's achievements for 2025. It did not specify a date for the start. Aramco has not made its own start-up announcement. A source close to the project said a formal Aramco announcement regarding Jafurah is likely "soon" ꟷ probably before the end of the year when commissioning is complete, as per Al-Ghamdi's comments. With in-place reserves of 229 trillion ft³ (6.87 trillion m³) of raw gas and 75bn bl of condensate, Jafurah is the largest unconventional gas field in the Mideast Gulf, and constitutes a major pillar of Aramco's ambitious gas expansion plans. The 450mn ft³/d capacity referenced by the ministry reflects the project's initial maximum raw gas processing, which aligns with Aramco's long-held plans for output to begin at 200mn ft³/d as sales gas, rising to 650mn ft³/d of sales gas by the end of 2026. A second phase, which is scheduled to come on stream in 2027, would then gradually lift sales gas production to 2bn ft³/d by the end of the decade. It constitutes part of an ambitious Aramco programme to expand gas production by more than 80pc by the end of the decade, relative to a 2021 baseline of 9.2bn ft³/d. This implies output of at least 16.6bn ft³/d by 2030, with Jafurah delivering just over one-quarter of the increase. Jafurah will also produce about 420mn ft³/d of ethane, and 630,000 b/d of NGLs and condensate as by-products by 2030. Traders told Argus last week that Aramco has offered spot Jafurah condensate for loading in February. Market sources say Jafurah condensate has an API gravity of 49.75° and sulphur content of 0.16pc. The ethane and NGLs will be sent to the Riyas fractionation plant, which is being built as part of the phase two development. The condensate will be sent to the Juaymah terminal, where Aramco is expanding its storage and export facilities. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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