Is the oil market facing a supply crunch?
Market forces, Trump's tweets and the latest Opec+ agreement have helped shape global supply in recent months
Early this summer, Opec scrapped its commitment to supply restraint, reversing a long-held policy of keeping markets tight as part of an effort to maintain a price floor.
US President Donald Trump had turned up the pressure on the organisation's heavyweights through a series of tweets. "Oil prices are too high, Opec is at it again. Not good!" he Tweeted.
Saudi Arabia, for its part, affirmed it would raise output, as crude oil prices reached heights not seen since the heady days of 2014.
On the face of it, Trump appeared to have succeeded in twisting Riyadh’s arm to release more barrels onto the market and take the edge off prices surging past $80 a barrel.
An Opec ministerial meeting in Vienna in June had yielded a wider commitment to boost production by about 1m barrels a day, despite Iran's evident opposition. The direct aftermath of the meeting saw a swift increase in supply from Saudi Arabia and its major Opec allies, helping compensate for lower Libyan, Venezuelan and Iranian production.
Saudi Arabia was virtue signalling that it would be responsible and release supplies to make sure that no shortages materialised. Saudi energy minister Khalid al-Falih highlighted the kingdom's unique position in having all its spare capacity available at short notice. It could pump as high as 11m b/d, about 1m b/d more than it was supplying for most of the first half of 2018, he said.
Even non-Opec Russia, which had been in lockstep with the Opec approach, seemed to be changing its tune. Moscow called for an easing of supply curbs amid concerns about the impact of $80/b-plus prices on global demand.
The backdrop to the Opec meeting in Vienna in June was dominated by accelerating fears that Trump's announcement of the US withdrawal from the Joint Comprehensive Plan of Action (JCPOA) on Iran would result in a much more significant loss of supply than the initial expectations of up to 500,000 b/d. The market soon began factoring in a steeper fall in Iranian output in advance of the November deadline when full sanctions would kick in again.
With the likes of Venezuela in meltdown, and other Opec producers such as Angola underperforming, the spectre of a supply crunch began spooking the markets—with prices responding in the expected way.
This seemed to set the stage for a substantial release of Opec+ barrels onto the market. According to the Oxford Institute of Energy Studies (OIES), and production numbers communicated to the Opec Secretariat revealed that Saudi Arabia had started to hike its production even before the June meeting. Riyadh increased its output to 10.5m b/d in June, an increase of almost 500,000 b/d on May. Saudi exports surged to a 15-month high of 7.5m b/d in June, up from 7.15m b/d in May, said the OIES.
The overall hike in Saudi, UAE, Kuwaiti and Russian production reached 600,000 b/d in June-equivalent to half the entire Opec cut target of 1.19m b/d.
According to the International Energy Agency (IEA), global oil supply rose by 300,000 b/d in July to 99.4m b/d, 1.1m b/d above levels a year earlier. Compliance with the Vienna agreement eased to 97% in July as output cuts were relaxed. The IEA expects non-Opec production to grow by 2m b/d in 2018 and by 1.85m b/d next year.
With more supply coming on stream, consumers expected to look forward to bearish price signals re-emerging. Yet, events have proved that if nothing else, the oil market is never predictable.
Falih had given advance warning that the Opec increase wouldn't be felt immediately, even as those who could boost supply did so: UAE production averaged 2.98m b/d in July, an increase of 85,000 b/d from the previous month and 110,000 b/d more than in May. Another Gulf Opec stalwart, Kuwait, saw crude oil production rise by 80,000 b/d in July to 2.8m b/d. Across the border, Iraqi crude oil production hit its highest level in 13 months in July at 4.46m b/d. Beyond Opec, Russia ramped up its crude production in July by as much as 250,000 b/d compared to May levels.
These producers were in a position to add barrels with relative ease. But as Schlumberger chief executive Paal Kibsgaard noted, it also served to highlight a relative scarcity of new supply options.
With Libya and Nigeria producing at near-full capacity, Venezuelan production in free fall, the potential of new sanctions against Iran, and rising geopolitical risks, Kibsgaard said in a statement that "the only major sources of short-term supply growth to address global production decline and strong worldwide demand are Saudi Arabia, Kuwait, the UAE, Russia, and the US shale oil industry."
Despite the favourable noises in Vienna about boosting supply, evidence suggests that Saudi Arabia actually cut production in July. Output averaged 10.3m b/d, down 2% or 200,000 b/d on the previous month. Platts tanker tracking software flows showed that Saudi crude exports dropped 461,000 b/d from June to 7.14m b/d in July. Any Opec members fearing that Saudi Arabia was about to flood the market with oil and do another "2014"-grinding down prices to flush out the marginal producers-could now rest easier.
Opec crude oil output was steady in July, at 32.18m b/d, notes the IEA, with the unexpected decline in Saudi Arabian supply offset by higher production from the UAE, Kuwait and Nigeria.
What caused Saudi Arabia to soft pedal on its production increase? One issue is that for all the Sturm und Drang emanating from Trump's Twitter feed, the market didn't actually need the additional supply from the Gulf producers and Russia.
In June, notes the OIES, Iranian exports hadn't yet fallen sharply. And after a brief disruption, Libya restored its production in July and August. In addition, according to OIES analysts, US crude exports to Europe reached an unprecedented level this year and were competing with other light sweet crudes such as West African oil.
The truth is that Saudi Aramco may not have been able to market the additional crude volumes, if it had attempted to bring these on stream. To do so it might have needed to offer deeper discounts to refineries-thereby shifting prices below the kingdom's preferred comfort level.
Rather, says OIES analyst Andreas Economou, the Saudis wanted to reassure consumers they have the buffer to cope with a Venezuela-sized outage.
"The downward adjustment in Saudi supply underscores the kingdom's sense of the need to assert a price floor just as much as to putting a cap on prices. The drivers behind the change in production stance ahead of June remain in play," says Economou.
Other analysts attest to the Saudi intention to find the right balance-the hallowed 'goldilocks' pricing point where it's neither too low, nor too high. "They are trying to find the perfect price," says Spencer Welch, a director on the oil markets and downstream team at IHS Markit. "Not so high that it stimulates alternative fuels and not so low that it is uneconomic in terms of production."
Riyadh is keeping a close eye on what is happening across the Gulf, with Iran's situation pivotal to the overall supply-demand balance.
Iran exported just over 2m b/d in crude oil and condensate in August, according to Bloomberg tanker tracking, the lowest since March 2016, and down 28% from April of this year-the last month before Trump announced his pull-out from the nuclear deal. There've been no shipments to South Korea or France since June, and overall Iranian exports to the EU were reported by Bloomberg to have fallen by about 40% since April.
According to Garbis Iradian, chief economist for MENA at the Washington-based Institute of International Finance, the fall-off in Iranian supply represents a substantial decline in available oil on the market. "How much that will be offset by Saudi Arabia and other producers-including Russia, the UAE and Kuwait-is a big question," he says. "They are unlikely to offset the expected sharp decline in Iranian, Venezuelan, and Angolan production, and that's why the market is still tight and global inventory continue to decline," he says.
IHS Markit's Welch says the expectation is that Iranian output will fall by about 1m b/d. While that will keep prices firm, it may not have a sustained impact, he predicts.
"We expect that by around 2020, one way or another this Iran issue will start to be resolved, a compromise agreement will be reached, and sanctions will be eased as they were previously," says Welch. "We don't see that as a contributing factor to any supply crunch. Similarly, with Libya we don't expect their production to go down any further than where it is now. There is some upside, but it may take a while so that will not impact on the early 2020 supply tightness possibility."
Americas to the rescue?
North American liquid hydrocarbons output hit 20.1m b/d in 2017, as production from the US and Canada offset a decline in Mexico, BP Statistical Review of World Energy figures show. The US Energy Information Administration (EIA) expects US oil production to grow by 1.4m b/d this year, and another 1m b/d in 2019, though current rates of growth suggest an even more rapid increase of 1.6m b/d, according to BofA Merrill Lynch (BaML) Global Research.
US oil output is on a firmly upward trajectory, hitting 11m b/d by late August-thereby putting it in earshot of becoming the world's leading producer. US supply growth is currently faster than at any point during the 2011-15 shale revolution, says BaML. The bank expects US crude oil output to exceed 12m b/d by the end of 2019. "With Russia pumping 11.2m b/d at present, this milestone should turn America into the world's largest crude producer within the next few quarters," it notes.
So, if an imminent supply crunch isn't on the cards, is this a matter of crisis delayed rather than crisis averted? In spite of Opec's commitment to boost output in June and rising North American production, the possibility of a near-term supply crunch can't simply be dismissed out of hand. Some senior figures have been sounding warning bells.
In early July, Saudi Aramco chief executive Amin Nasser said the oil industry is risking a supply crunch as big energy companies focus on US shale and other short-term efforts over the long-term mega-projects seen in years past.
Nasser told the Financial Times that rising investment into short-cycle output—which ebbs and flows faster than conventional projects—wouldn't be enough to meet rising crude demand. Shale oil, he said, wouldn't really create a major dent in total global supply requirements up until 2040.
Such concerns reflect a deeper long-term challenge facing the oil industry, which has seen oil and gas companies' confidence in investing in expansion projects erode amid a growing realisation that such investments can no longer yield the kind of returns demanded by shareholders.
Majors focus on costs
Although oil prices have edged up to a full-year average of $75/b, that's still not high enough to encourage IOCs to green-light multi-billion-dollar oil projects. According to the OIES' Economou, the majors' exposure to long-term risks remains a big concern. "We do see upstream investments persisting into short-run cycle projects, as well as greenfield projects continue being delayed or cancelled. What this shows is that there's still not a lot of confidence around, despite the price recovery."
Most oil companies are still budgeting on a lower-for-longer basis. The oil majors' overriding focus is on cost containment—and in some cases handing back cash to shareholders—rather than engaging in ambitious capex expansion schemes.
Consultancy Rystad Energy reckons that total capital expenditure by energy groups in the 2015-20 period will almost halve to $443.5bn from $875.1bn in 2010-15. Some of that decline reflects improved cost efficiencies. But it also betokens a reduced willingness to plough additional capex into capital-intensive conventional projects that could materially expand production capacity.
This loss of corporate appetite for mega-projects spells bad news for long-term future supply stability. The IEA forecasts that insufficient investment into new large-scale projects will lead to a supply shortfall in the early 2020s, just as US shale production plateaus.
"[T]he concern is that particularly for conventional projects there isn't enough spending taking place and therefore there are knock-on implications that could hit us in the early 2020s," says Welch. He also points out that the lack of new conventional capacity coming on stream will become clearer once all the current Canadian projects are commissioned.
There remains a close correlation between spending and discovering productive oil resources. The IEA notes that global oil discoveries fell to a record low in 2016 as companies continued to cut spending and conventional oil projects sanctioned were at the lowest level in more than 70 years. Oil discoveries declined to 2.4bn barrels in 2016, compared with an average of 9bn barrels a year over the past 15 years.
In the agency's view, upstream investment may not be enough to avoid a significant squeezing of the global spare capacity cushion by 2023, even as costs have fallen, and project efficiency has improved.
Glass half full
While the picture is far from pretty, none of this means a supply crunch is completely inevitable. History shows that the hydrocarbons industry can haul itself out of the deepest of troughs.
"The US has proved itself at least twice in the recent past able to respond to price signals very rapidly and we think that it still has the ability to do that," says Welch. "And because of the significant amount of oil in storage that was built up, it has the ability to meet short-term demand. An oil supply crunch is certainly not to be dismissed, but we are not building in an early 2020 spike into our price outlooks because of it."
Canada and Brazil are shaping up as strong non-Opec supply centres
The IEA points out that after collapsing in 2014-16 by over 40% amid the downturn, an upstream recovery that saw 4% growth in 2017 will this year accelerate to 5%, accounting for projects worth $472bn. Its World Energy Investment 2018 report cites the example of the US shale success story as driving much of the growth: capital spending in the US shale patch is expected to increase by 20% in 2018 after a 60% jump last year, as shorter-cycle projects take precedence over offshore and oil sands ventures.
Looking beyond 2020 means adopting a more speculative timeframe. That requires looking deeper at the growth in demand for crude-derived products and comparing that with available crude and condensate supply. Sarah Emerson, managing principal at US-based ESAI Energy, downplays the prospects of a supply crunch, although the combination of sanctions on Iran and the 1 January 2020 deadline for limiting sulphur content in fuel oil on board ships should lead to a near-term price spike. "We have non-Opec crude oil growth in excess of 1.1m b/d in the next two years, and crude oil-derived demand is chugging along at about 1m b/d," she says.
Emerson points out that an overly geologically-focused approach concentrating on reports of significant field declines in some major producers could lead to misconstrued interpretations as to the impact on future supply.
Despite stories far and wide of large-scale field declines, the industry is working hard to make up the difference. "They are attenuating the decline in some of these fields, and notably crude oil production at the national level in many countries barely falls—or even rises," says Emerson. "The decline in some of these countries hasn't been as dramatic as people think, so it's hard to get this really urgent supply crunch when we look at national data. Country-level production profiles do not show the aggressive decline that you see in individual fields."
Looking forward, Canada and Brazil are shaping up as strong non-Opec supply centres, with new greenfield projects underscoring the message that non-Opec supply can add sizeable ballast to Opec output, as producers are forced to tap spare capacity to offset disruptions.
BaML highlights the ramp-up of greenfield projects in Canada and Brazil, and growth from tight oil producers in the US should provide a substantial boost to non-Opec supplies over the course of H2 2018, taming upside pressures on Brent crude oil prices.
"There's a lot of room for growth outside of Opec," says Emerson. "Canada is adding 150,000-200,000 b/d over a two-year timeframe, Brazil is going to add over 300,000 b/d in 2019, and another 100,000 b/d after that. In addition to that, we see another 1.4m b/d of US supply. Altogether, just those countries are adding 2m b/d over 2019 and 2020."
BaML cites H2 2018 guidance showing that US producers are expecting a large increase in output during the remainder of the year. The bank forecasts sequential growth of 750,000 b/d from Q2 2018 to Q4 2018. This increase, coupled with returning oil sands output and refinery maintenance, should weigh on domestic pricing later this year and next, eventually moderating US oil output growth.
Much will inevitably hinge on what Opec agrees in the coming weeks and there are other factors that will have a say in the future supply balance. With an intensification of the US-China trade war beckoning, which would likely have the impact of subduing demand for oil, the prospects of an imminent supply crunch may reduce.
In the meantime, all eyes are trained firmly on Tehran—or more specifically the Islamic Republic's shaky future as an oil exporter. "The Iranian losses are the most important thing to look at in Q4, along with the low spare capacity," says Economou. "That's an issue because with low availability in spare capacity, even small surprise changes in supply and demand can generate large price fluctuations."