That’s the way the cookie crumbles. Emphasis on crumbles. Just three months ago – in September – the oil world was riding on a cusp on strong prices. Hedge funds, traders and banks predicted that headline Brent crude prices would be US$90/b by Christmas and three digits by early 2019. US President Donald Trump hammered incessantly on Twitter about high oil prices, placing pressure on Saudi Arabia to act ahead of the US midterm elections. Lured by strong prices, oil majors sanctioned new upstream US projects at the fastest pace since 2014. What a difference a few months make.
At time of writing, Brent and WTI have fallen far below their recent psychological marks – Brent at US$54/b and WTI at US$45/b. That is almost a third below the benchmark’s respective peaks for this year, and also far below where they started 2018 at. In fact, crude prices are now back at levels similar to January 2017. This is after OPEC+ managed to corral its members together to agree to a 1.2 mmb/d cut in early December – a move that managed to steady oil prices for mere days.
Where do prices go next year? Long-range forecasts for 2019 have been slashed over the past two weeks, but most analysts are still generally maintaining averages of US$65-70/b for Brent and US$55-65/b for WTI. The assumption is that oil demand will remain strong and that OPEC will continue to coordinate moves to ensure global supply remains in line with global consumption – a development presaged by OPEC itself when it admitted that a ‘deeper cut’ may be necessary in 2019. If it manages to keep the supply/demand balance aligned, it is conceivable that crude prices could return to those ranges – which underpin the budgets of most major oil companies and producing countries - assuming that demand growth continues. But with the Chinese economy looking shaky and the US-China trade spat diffused only temporarily, there are plenty of headwinds for global growth, and by association, global oil demand.
Far more volatile – and therefore far more interesting – is the supply side. OPEC+ has decided to cut its production until April, when a review is due. Is there enough appetite among OPEC+ members for another cut then if prices remain low? Much will depend on the question of Iran; new American sanctions against Iranian crude exports were almost completely muted by the issue of waivers to eight key importers – waivers that are due to expire in May 2019. If the waivers are extended, how much more can OPEC cut to appease the market? And if the waivers aren’t, then are the current production levels of other members enough? Add to this the perennial issue of American shale. The US is now the single largest crude oil producer in the world. And despite the pipeline bottlenecks, the USA is on track to hit 13 mmb/d in output in 2019 and 15 mmb/d in 2020. Some of the new pipelines connecting the Permian to the Gulf of Mexico will be ready by then, unleashing even more American crude to the world. The dilution of OPEC’s swing supplier status will accelerate, and then the question will be: how much market share is OPEC willing to cede to American producers in order to prop the market up? Could 2019 be a return to more mercenary, free-for-all tactics from 2014 where OPEC floods the market to muscle American shale players out?
It will be interesting to see how all these factors play out over 2019 – and more, including US Federal Reserve interest rate hikes and chatter about an imminent recession - which will redefine the power dynamics in the oil industry. What does seem inevitable is the rising tide of American shale oil in the world, which the rest of the world has to adapt to – by sinking or swimming. With this in mind, the upside for crude oil prices will be limited in the coming year; US$60-65/b Brent crude oil seems like a safe bet for now, but as with all forecasts, this is never a certainty.
Brent Crude Benchmark Prices:
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
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Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline