Just in case you missed the week's biggest news in the oil industry. Here is a quick round-up of events.
After over a month of posturing and rhetoric that brought crude oil prices to their lowest levels since the invasion of Iraq in 2003, the world’s largest crude oil producers managed to swallow their pride. Collectively, the OPEC+ group agreed to slash global production by nearly 10 mmb/d through June 2020, before allowing gradual increases through April 2022, when the deal expires. The scale of the new deal is vast. It is the single largest output cut in history, which is in response to the single largest demand destruction event in history, the Covid-19 pandemic, and runs on a huge timeline of 2 years.
For OPEC+, the deal serves two purposes. It immediately props up the current traded prices of crude oil, which were languishing in the US$25/b level before chatter of the deal emerged but it also is prescient enough to acknowledge that the negative impact of Covid-19 will linger for very long, hence the need for a long tail to the deal. The Great OPEC+ deal will not be enough to return oil prices to the US$50/b range. The greater Covid-19 crisis has ensured that. At least 18.5 mmb/d of oil demand has disappeared due to the pandemic; the current deal mitigates just over half of those volumes when it starts on May 1. But the goal was never to deliver a sustained recovery in crude prices. It was to ensure stability at current price levels, avoid oil prices possibly crashing further down into single digits, while managing supply to pave the way for eventual an price recovery as global economic activity slowly recovers post-Covid.
The goal was also to get the US involved. And involved it did. The emergency OPEC+ meeting, also attended by key countries not part of the OPEC+ alliance, was brokered through a series of furious meetings by US President Donald Trump. A more Machiavellian take on the Saudi Arabia-Russia oil price war was that it was a gambit to force the US to step in and get involved. Threatened with a meltdown of the US oil industry, particularly the shale patch, once an investor’s darling but now saddled with debt. Trump’s hand was forced in a crucial election year to advocate market control over free market economics. And it wasn’t just US oil facing an existential crisis; the massive LNG export infrastructure being built across the US was under threat as well. All of this was outlined to Trump in a feisty meeting with representatives of the US oil and gas industry, bitterly divided between those advocating intervention (the smaller players) and those protecting the free market (the majors and supermajors).
In the end, President Trump stepped in. He had to. Another Machiavellian take on the situation was that the oil price war was an excuse to allow Saudi Arabia and Russia to inflate their production levels in April, to cushion the blow from eventual production cuts. And, indeed, Saudi Arabia and Russia raised their output to record highs of some 12 mmb/d in April. Under the new supply deal, both countries would reduce their output to some 8.5 mmb/d, making up over half of the total expected cuts. But at the initial OPEC+ meeting on Thursday, protest came from an unusual quarter. Mexico, which has over-hedged its crude, balked at cutting its output by 400,000 b/d, promising only 100,000 b/d. The Mexican Standoff, as it was called, only ended by President Trump stepped in and promised to assist Mexico with its quota. This brought the OPEC+ supply deal down from an initial 10 mmb/d to 9.7 mmb/d.
Following the provisional OPEC+ deal, the G20 group of nations met a day after, promising to support intervention to stabilise prices. Out of that meeting, the US, Brazil and Canada aimed to reduce 3.7 mmb/d from their collective production, while the other G20 nations (including Argentina, Indonesia and the UK) would contribute another 1.3 mmb/d. However, these would not be actual quotas but ‘natural cuts’ as a by-products of the low price environment, as the free-market economies balked to establishing market controls. As President Trump put it, the free market would curb output in free market nations ‘automatically’, as private firms such as Equinor, ExxonMobil, Shell and Petrobras adjust their output accordingly.
On Sunday, OPEC+ finalised the details of its Great Deal after Mexico dropped its protest following Trump’s uncharacteristic offer to ‘pick up some of the slack’. With new countries in line (at least in spirit) with the supply deal, this has now been characterised as the Great OPEC++ Deal. But those expecting prices to rally on the news were disappointed. As Goldman Sachs called it, the deal is ‘too little, too late’. The market had already priced in a comprehensive supply deal when it rallied Brent prices from US$25/b to US$32/b; but the deal wasn’t large enough to placate a market fretting over the uncertain duration of the oncoming economic depression. Adherence to the supply cuts, as always, is always a huge question mark. But, as we have mentioned, that wasn’t the plan. Instead of a shock-and-awe cut to rally prices in the short-term, the Great OPEC++ Deal instead provides a gradual exit strategy from the current catastrophe. A catastrophe that OPEC++ itself partly contributed towards.
The OPEC++ deal in summary:
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
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)
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.
Find courses available for Virtual Instructor Led Training through latest video conferencing technology.
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