The spread between the world’s two benchmark crude oil markers – Brent and WTI – is currently hovering at US$6/b. This is the widest gap between the two for a long while, first breaching the tight US$2/b spread range since 2015 in the run up to Hurricane Harvey as traders fretted that widespread refinery closures along the US Gulf would impact US crude consumption.
Those refineries have come back online, but the spread is still persisting. It is so large that India’s Reliance – an opportunistic buyer if there was any – bought a massive million barrel cargo of US crude oil last week. All across Asia, key buyers are taking advantage of this new arbitrage window to stock up on (cheaper) American crude, some for the very first time. Indian refiners – notably state refiners IndianOil, HPCL and BPCL – are leading the way, with buyers from South Korea, Japan, Thailand and Singapore also in the fray. Chinese activity is still minor, but one has to imagine they can’t be that far behind.
When the Brent-WTI spread hit its all time high at US$28/b in September 2011, there was a similar enthusiasm for US crude. Volumes then, however, weren’t readily available. The WTI discount to Brent then was because oil generated from the burgeoning US shale revolution was trapped in Cushing, Oklahoma – the main price settling point for WTI – at a time when global demand was soaring. In other words, the discount was due to the inability of sufficient WTI volumes to make it into the wider market. The oil was there, but midstream infrastructure to ship it to Houston and from there to the wider world, was inadequate. A rush to expand existing pipelines and build new ones – transportation by train was even used at one point to clear volumes – occurred, and when it did by 2014, the Brent-WTI spread had decreased. The lifting of the US crude export ban in 2015 narrowed things even further, to a range of US$2-3/b.
In 2017, that lack of infrastructure is no longer there. Supply has caught up with the ability to meet demand, and as US oil exports soared, WTI prices have closed the gap with Brent, which is used as the main international marker, including Middle Eastern grades. In such a competitive scenario, we would expect both benchmarks to move towards parity.
But even before Hurricane Harvey reared its head, the Brent-WTI spread was already growing. The circumstances this time are different. On the Brent side, there is a ‘fear premium’ being priced in; tensions in the Middle East – between Qatar and the rest of GCC, tensions between Iraq and its Kurdish province – have been raising the spectre of supply disruptions. More significant though is that on the WTI side, there is now once again an abundance of supply. But unlike before, that supply can make it to market. Which is why we are seeing such strong volumes of US crude exports. Some six million barrels are earmarked to be shipped from the US to Asia for November so far; up from usual monthly shipments of 2-3 million barrels. The cheap prices are enticing, but Asian refiners are being forced to look further afield for crude as OPEC and some non-OPEC sellers have been cutting availability as part of their supply freeze.
US crude exports reached an all-time weekly high at the end of September. That jump in demand should naturally reduce the spread. The Brent physical market is tight, meaning that Brent’s strength is not artificial but demand driven. A break towards US$60/b appears possible soon. But a look over the future curve indicates that the current Brent-WTI spread will persist through October 2018, having doubled since May 2017. This suggests that the sheer amount of supply coming out of the US will negate demand drivers to keep WTI significantly lower than Brent, where supply is a lot steadier.
That’s good news for Asian buyers, as the avenue of cheaper US crude remains open to them for far longer. With OPEC likely to extend, or even deepen, the supply freeze beyond the current deadline of March 2018, Brent-linked crude volumes will be in short supply. The distance from Houston to Yokohama, Singapore or even Paradip is vast - VLCCs have to go through the Suez as the Panama Canal is too narrow – but at current and projected spreads, well worth the distance.
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Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b
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At some point in 2019, crude production in Venezuela will dip below the 1 mmb/d level. It might already have occurred; estimated output was 1.15 mmb/d in November and the country’s downward trajectory for 2018 would put December numbers at about 1.06 mmb/d. Financial sanctions imposed on the country by the US, coupled with years of fiscal mismanagement have triggered an economic and humanitarian meltdown, where inflation has at times hit 1,400,000% and forced an abandonment of the ‘old’ bolivar for a ‘new bolivar’. PDVSA – once an oil industry crown jewel – has been hammered, from its cargoes being seized by ConocoPhillips for debts owed to the loss of the Curacao refinery and its prized Citgo refineries in the US.
The year 2019 will not see a repair of this chronic issue. Crude production in Venezuela will continue to slide. Once Latin America’s largest oil exporter – with peak production of 3.3 mmb/d and exports of 2.3 mmb/d in 1999 – it has now been eclipsed by Brazil and eventually tiny Guyana, where ExxonMobil has made massive discoveries. Even more pain is on the way, as the Trump administration prepares new sanctions as Nicolas Maduro begins his second term after a widely-derided election. But what is pain for Venezuela is gain for OPEC; the slack that its declining volumes provides makes it easier to maintain aggregate supply levels aimed at shoring up global oil prices.
It isn’t that Venezuela doesn’t want to increase – or at least maintain its production levels. It is that PDVSA isn’t capable of doing so alone, and has lost many deep-pocketed international ‘friends’ that were once instrumental to its success. The nationalisation of the oil industry in 2007 alienated supermajors like Chevron, Total and BP, and led to ConocoPhillips and ExxonMobil suing the Venezuelan government. Arbitration in 2014 saw that amount reduced, but even that has not been paid; ConocoPhillips took the extraordinary step of seizing PDVSA cargoes at sea and its Caribbean assets in lieu of the US$2 billion arbitration award. Burnt by the legacies of Hugo Chavez and now Nicolas Maduro, these majors won’t be coming back – forcing Venezuela to turn to second-tier companies and foreign aid to extract more volumes. Last week, Venezuela signed an agreement with the newly-formed US-based Erepla Services to boost production at the Tia Juana, Rosa Mediano and Ayacucho 5 fields. In return, Erepla will receive half the oil produced – generous terms that still weren’t enough to entice service giants like Schlumberger and Halliburton.
Venezuela is also tapping into Russian, Chinese and Indian aid to boost output, essentially selling off key assets for necessary cash and expertise. This could be a temporary band-aid, but nothing more. Most of Venezuela’s oil reserves come from the extra-heavy reserves in the Orinoco Belt, where an estimated 1.2 trillion barrels lies. Extracting this will be extremely expensive and possibly commercially uneconomical – given the refining industry’s move away from heavy grades to middle distillates. There are also very few refineries in the world that can process such heavy crude, and Venezuela is in no position to make additional demands from them. In a world where PDVSA has fewer and fewer friends, recovery will be extremely tough and extremely far-off.
Infographic: Venezuelan crude production:
Headline crude prices for the week beginning 31 December 2018 – Brent: US$54/b; WTI: US$46/b
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