After a lesser draw than expected to crude inventories, oil is selling off on this third Wednesday in April. As strong imports from the Middle East this week should help to buoy inventories for next week's report, hark, here are five things to consider in oil markets today.
1) Much is being made of Saudi Arabia's February exports, which showed a drop to the lowest since mid-2015, according to JODI data. But we can see in our Clipperdata that this drop is superseded by a solid rebound in March exports. We see exports rebounded to over 7.2 million barrels per day, with flows bound for East Asia (think: Japan, South Korea, China) accounting for 45 percent of loadings.
This is the second-highest monthly volume heading to East Asia from Saudi on our records. The highest was in January. In the aftermath of the OPEC production cut, East Asia has been strongly favored for OPEC barrels. Total OPEC loadings bound for East Asia in March have clambered above the 10mn bpd level, the highest on our records, although April so far is looking considerably weaker as total OPEC export volumes drop.
2) It is also interesting to note that Saudi Arabia oil inventories rose in February amid the export lull. We discussed earlier in the month how JODI data showed that oil inventories dropped to 262 million barrels in January, down from a peak of 329 million barrels in October 2015.
After dropping thirteen out of the previous fourteen months - and for seven months in a row - Saudi crude inventories for February rebounded by 2.74mn bpd. This appears due to less crude leaving the country, and more finding its way to be both refined and put into storage:
3) As the Dakota Access Pipeline (DAPL) starts up, the largest refiner on the East Coast - Philadelphia Energy Solutions (PES) - is not expected to take any deliveries of Bakken crude by rail in June. Once DAPL starts up, it is more profitable for oil to be sent by pipe to the U.S. Gulf Coast than it is to send it by rail to the East Coast.
As our ClipperData illustrate below, the marginalization of Bakken barrels to the East Coast has been underway for a good while. Waterborne imports bottomed out in early 2015 - at exactly the same time that Bakken shale crude production was peaking out.
As Bakken production has dropped off since, and as oil prices have remained low (making waterborne imports a more economically viable option than crude by rail), waterborne imports have risen ever since. While Canadian and Brazilian grades are consistently delivered to the refinery, West and North African grades have accounted for nearly 60 percent of imports since the start of last year.
4) Today's key EIA inventory numbers have been driven in large part by big swings on the US Gulf Coast. While total US refinery runs rose by 241,000 bpd, an increase of 260,000 bpd was seen from Gulf Coast refiners.
This uptick in Gulf Coast refining activity, in combination with imports remaining somewhat in check, has meant oil inventories have drawn down on the Gulf Coast by 3 million barrels. Next week's report is set to be impacted by super-strong waterborne imports from the Middle East, but for now, the increase in refining activity is taking center-stage. Crude inputs are now a whopping 958,000 bpd above year-ago levels.
5) Finally, the IMF has published its April 2017 World Economic Outlook. It projects world economic growth is going to be at 3.5 percent in 2017, rising to 3.6 percent in 2018. As we know all too well, all paths lead back to energy, hence downward revisions have been made to Latin American and Middle East nations due to the impact of lower oil prices and production cuts.
While the Russian economy is seen turning a corner as oil prices rebound, Saudi Arabia's economy is projected to grow at 1.3 percent in 2018, down from an estimate of 2.3 percent in January, due to austerity measures and production cuts.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
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