According to the US Energy Department, US crude production hit 11 million barrels per day in early July. This was always seen as an inevitability, but the speed at which the mark has been achieved has been astonishing. It was only eight months ago in November 2017 that the US production reached 10 mmb/d – a level that had only been reached (briefly) in 1970. Back then, the Energy Information Administration (EIA) predicted that American output would reach 11 mmb/d by November 2018. While the Energy Department’s figures have yet to be confirmed by the EIA – which releases confirmed data on a lag of 2 months – there is no reason not to believe that the mark hasn’t been achieved.
In any other month, this would make the USA the largest crude producer in the world, except for a jump in Russian production to 11.2 mmb/d. The recent OPEC+ agreement means there is room for Russian (and Saudi Arabian) output to grow, so the race for the title of world’s largest crude producer will be tight for a while, but America has more potential and it seems only a matter of time before American production nears the 12 mmb/d mark. Perhaps next year? With crude prices at their healthiest levels for 4 years, there is every reason for American drillers to keep pumping, although concerns over geopolitical issues about supply and global oil demand could curb potential.
The nature of the shale revolution is the US is also changing. Just last week, Concho Resources completed its US$9.5 billion acquisition of RSP Permian, creating the largest unconventional shale producer in the Permian Basin. ExxonMobil, Chevron and Shell are moving in on the Permian, while BP is looking to be the frontrunner in purchasing BHP Billiton’s onshore shale and gas assets. At the start, the US shale revolution was characterised by a large number of small and nimble players riddled with debt; as it now matures, consolidation is setting in to create a smaller number of larger players. This is viewed as necessary to make the sort of large-scale investments required to take the shale revolution to the next level, but this can also cause inertia in growth, since merged and larger firms are likely to be far more risk averse due, as they are answerable to shareholders.
However there are still some challenges ahead in the Permian. The most important for now seems to be infrastructure, or lack thereof. Pipeline bottlenecks in the onshore shale plays, particularly the Permian, are making it increasingly difficult for producers to get their oil to market, especially the clearing point in Cushing, Oklahoma. This constraint has been behind the large Brent-WTI differential over the past two months, as crude volumes remained stuck without access to the market. Figures indicate that the Permian currently has some 3.56 million barrels per day of pipeline capacity, equivalent to current production, meaning that pipelines are operating at full capacity. New pipelines are being planned, but this will take time, restricting immediate growth. And with more drilling activities taking place, costs in the supply chain is also expected to go up in tandem. The issue about actual profit margins in the Permian has often been debated due to the amount of debt poured into the region, when oil prices were at marginal levels. Current prices do provide some relief but existing operators who are highly leveraged do run a high risk, if prices trend downhill.
Despite all that, the 12 million barrel per day mark seems to be a question of when, not if. If the US succeeds in its aim to reduce Iranian crude exports significantly by November, the additional American volumes could be a necessity, not a spanner. The pieces are all in place for that to happen, and while the Energy Department and the EIA have not issued any formal forecast, we would not be surprised if American oil output came very close to the mark this time next year.
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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