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Unprecedented is a word that has captured headlines since January 2020, when the Covid-19 pandemic first began to accelerate in China. Unprecedented contagion, unprecedented lockdowns, unprecedented demand destruction, all leading up to what could be the worst economic recession since the Great Depression almost a century ago. And now, unprecedented oil prices, as the WTI crude price marker slipped into negative territory for the first time ever.
Not just any negative territory, but double digits negative. The front month WTI contract for deliveries in May fell as low as -US$37.63.b on Monday. The discount between WTI and Brent also crashed to its lowest point ever, at a peak of -US$62/b, as Brent continues to trade in the mid-US$20/b level. That’s unprecedented. It isn’t just WTI; other US grades are also deep in the negative, as well as Western Canada Select. This essentially means American and Canadian producers are paying to offload their crude oil to (a thin pool) of potential buyers.
There are many reasons for this. Demand for refined fuels has virtually dried up as the US imposed strict lockdown conditions to contain the virus. Jet travel has evaporated, and though gasoline prices have reportedly fallen by 75% in some parts of the US, there is nowhere to drive to. At least three North American refineries have been idled in the face of oil demand destruction, and there are certainly more to come. Try as much as President Donald Trump wants to re-open the US economy, the threat of the virus re-accelerating is worse. This huge dip in demand and refining meant that all the crude and shale oil being produced had nowhere to go but into storage. But storage is rapidly getting maxed out; spare capacity in the main hub of Cushing is fast depleting, and there are even plans to store oil in train cars and in halted pipelines. Storage in the US Strategic Petroleum Reserve is available, but even that is limited.
What makes this even more unprecedented is that much of this oil is onshore, very far inland. This had the same effect, though different contributing factors in 2019, when WTI prices were depressed because demand was high but pipeline capacity was insufficient to carry crude to refining centres along the US Gulf Coast, creating a shale glut. In a way, that paved the way to the current catastrophe; many shale producers picked up a lot of debt during this time, and were forced to pump oil even more aggressively just to stay alive. In the world of a growing oversupply, inland oil is overflowing as storage fills to the brim. Offshore production doesn’t face the same issue. As long as crude can be delivered on the coast, it can be placed on a tanker and stored offshore indefinitely, especially with so many ships idled due to the slowdown in economic activity. This is already happening in Singapore, in Fujairah, in the North Sea, and is the reason that the global crude marker, Brent, has not collapsed.
But the main reason for the unprecedented demolition of US crude prices hinges on a technicality. The Brent NYMEX contract is settled in cash. WTI contracts, however, are settled physically; those holding the contract must therefore take physical delivery at expiry. That expiry date for May contracts is April 21. The dive into deep red territory came because of extreme selling pressure to avoid have to physically receive the oil, especially with nowhere onshore to store it. News that large cargoes of Saudi crude were heading to the US Gulf made matters worse. However, further WTI futures contracts for June and beyond, are still trading at a far more normal range of US$20-30/b; there is still enough time for demand to recover (or for more storage to be found) for these contracts. But for the May contract? It is a bloodbath.
The situation certainly isn’t as dire as it seems, though the headlines might seem apocalyptic. This knee-jerk reaction will almost certainly sort itself out over the medium term. Already, the expiring May WTI contract recovered to -US$6/b in after-hours trading. WTI should return to a more normal range with the switchover to the June benchmark contract on Wednesday. Economic pressure will keep prices low, but not that low. At least not yet. But it will be a whole new galaxy of pain for the US oil industry, especially those that are completely reliant on shale and those that service them. The Saudi-Russia oil price war may have begun as a battle for market share, but might have inadvertently achieved a secondary objective, wiping out US shale production that was undermining supply control efforts. In just three months, the entire oil world has been turned upside down. In response, the industry is recalibrating. There will be some winners, and some losers. In these unprecedented times, expect unprecedented things.
WTI’s Great Fall:
-Traded prices on NYMEX, 20 April 2020
- 10am: US$11.28/b
- 2pm: US$4.88/b
- 2.30pm: -US$0.02/b
- 3pm: -US$.6.89/b
- 4pm: -US$37.63/b
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Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.
Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.
Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.
Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.
But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.
Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.
Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)
| Region | Consumption (mmb/d)* | Refining Capacity (mmb/d) |
| North America | 22.71 | 22.33 |
| Latin America | 6.5 | 5.98 |
| Europe | 14.27 | 15.68 |
| CIS | 4.0 | 8.16 |
| Middle East | 9.0 | 9.7 |
| Africa | 3.96 | 3.4 |
| Asia-Pacific | 35 | 34.75 |
| Total | 95.44 | 100.05 |
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
Market Outlook:
End of Article
In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.
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Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.
The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.
Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.
Source: U.S. Energy Information Administration
First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.
Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.
Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.
Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.
Principal contributor: Jesse Barnett
Key findings