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Brent crude is once again flirting with the US$80/b level. By the time October begins, it is likely that Brent prices will be comfortably over the mark, pulling WTI prices up towards the same level. The last time crude prices surged (and sustained) above this level, US$80/b was identified as the level where demand destruction began, as countries and companies scaled back on oil usage. Since the price crash in 2015, demand has managed to pick up tremendously, in no small part due to cheap prices. Where do prices go from here? Can they return to the US$100/b level? That would be cheery news for oil firms, who are finally emerging from a tough slump, but it could also return us to the excesses of the previous cycle, repeating the same problems.
The direction for oil prices – at least for the foreseeable futures – is definitely up. The main thrust for this is Iran. Or rather, renewed American sanctions on Iran. Though the Trump administration’s aim to reduce Iranian crude exports to zero is probably a pipe dream – in no small part due to pushback from India and China – the sanctions will still manage to remove at least 1 million b/d from the market. At a time when Venezuela production is in a downward spiral and disruption continually threatens OPEC’s North African members, this supply risk is constantly pushing prices levels up. OPEC has vowed to turn on the spigots in association with its NOPEC partners, but not to a level that can offset all the losses, to appease members such as Iran and Iraq. This is unlikely to be revised drastically at the upcoming OPEC meeting in December. The US is not happy about the situation – witness President Trump’s flailing tweets – and the American Congress is considering an anti-cartel bill that could open OPEC to lawsuits, all to rectify a situation that it itself created.
Because of this, major oil trading houses and banks are predicting prices to rise even further. Goldman Sachs, which once famously predicted prices could spike to US$200/b during the 2008 boom, is curiously cautious in maintaining its prediction at a floor of US$80/b, as is Citibank. JP Morgan, however, expects Brent to hit US$85/b as early as November, on a path to rise to US$90/b. Trading houses are more bullish. Mercuria and Trafigura are both predicting US$100/b prices by early 2019 – citing the lack of spare capacity in the market to replace lost volumes. Even the shale rush in the US that has made America the world’s largest crude producer will not be enough to replace lost Iranian volumes in the short- and medium-term. Most analysts expect the Iranian losses to be at least 1 mmb/d, with some analysts predicting that Iranian exports would fall to just 700,000 b/d from 2.1 mmb/d last year, shipped mostly to China and to India, with land routes used to circumvent shipping and insurance sanctions.
At prices like this, one would expect oil producers to rush in to fill the gap. But pipeline infrastructure limitations in the Permian are hampering distribution to Gulf Coast export hubs, while promising upstream production in Guyana, Mexico and Australia are still far, far off from commercialisation. Meanwhile, vast new LNG facilities has come onstream, together with major natural gas finds, accelerating oil’s displacement by gas in key sectors such as power and petrochemicals. Meanwhile, oil firms expect the bonanza to continue; service firms, particularly deepwater-focused ones, are seeing enthusiastic signs, as firms push towards riskier projects made economical only at high oil prices. This has happened before, as most would remember, but the oil industry has a short memory. Where will crude prices go from here? Nobody can agree on the exact magnitude, but everyone agrees that the direction is up.
Factors influencing the rise to US$100/b oil:
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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:
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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