Events that happen today don’t always show their impact until later. Sometimes much, much later. Tsunamis can occur several hours after the initial earthquake. And, as much as markets have access to an over-abundance of information, the impacts of trends currently happening on the ground (or rather, under the ground) aren’t always obvious until they hit.
Take US crude production, for example. The story over 2018 and 2019 was the quick acceleration of American crude output, powered by the shale revolution. The US has now overtaken Saudi Arabia and Russia as the world’s number 1 oil producer. Total production blasted past the 12 mmb/d level in 2018, and heady forecasts predicted that output could comfortably reach 14 mmb/d by the end of 2020. The amount of US crude flowing – onshore and offshore – has upended world crude price dynamics, and also bestowed cheap fuel on the US, powering its economy. The trends have also spilled over in the gas markets, where the US is currently enjoying historically low natural gas prices domestically and in the process of transforming itself a major LNG exporter.
To assume this will continue is a fallacy. The scenario occurring today is happening because of what happened several years ago. Looking at the data of active US oil rigs available from Baker Hughes – which is taken as a proxy for the level of upstream activity in the country – and the US crude production numbers from the EIA shows an evident lag between the two indicators. There appears to be a two-year lag between activities in the drilling sector with impact on output. Between December 2016 and December 2017, when the active oil rig count increased by 272, crude oil production only increased by 1.18 mmb/d; but between December 2017 and December 2018, crude oil production jumped by 2.06 mmb/d. Between December 2017 and December 2018, when the active oil rig count growth slowed down to 128, crude oil production growth also slowed down to only 800,000 b/d between December 2018 and estimates for November 2019.
To be fair, there are many other factors that impact production. But the active oil rig count is a significant indicator, and indeed predictor, of future output. Which is why current trends in the US active rig count are worrying. Between December 2018 and November 2018, Baker Hughes reports that the active oil rig count in the US declined by 206 – a 31-month low. And the decline seems chronic. Within that data, much of that decline comes from onshore rigs, particularly in the Permian and Eagle Ford basins. At current trends, the oil rig count could fall below 600 by early 2020. Given that shale fields have a prolific initial production period, followed by a sharp decline, this is worrying. US oil production could actually decline in late 2020, early 2021.
Of course, there are other things to consider. Consolidation is ongoing in the Permian, which may be reducing rig count but increasing productivity. With the investment community has turned against shale, drying up capital, some small- and medium-scale drillers are going bust. These assets, sometimes in high-opportunity areas, are being plucked off, as the big guys – the ExxonMobils, the Chevrons and the BPs – move in. There are many reasons why the active rig count might be dropping, but the main reasons remains that drilling just isn’t as attractive anymore. That itself will never translate 1-to-1 to production trends, but it will have a definite material impact. A reversal in US oil production growth is unlikely; what’s more likely is that the explosive growth will slow down. In fact, it already is. An average production level of 13 mmb/d is still achievable within six months, but the 14 mmb/d level looks very far off. Don’t be fooled by the surface image of current US oil output. Trying times are coming, and if you paid attention to the indicators, you would have known it is coming… and can prepare for it.
US Active Oil Rig Count vs US Crude Production
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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)|
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
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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