It’s been a busy few days at CERAWeek in Houston, where The Wall Street Journal has a team of editors and reporters covering the most influential annual oil conference in the U.S. Saudi Arabia’s oil minister spoke, OPEC’s secretary general broke bread with rival American producers and U.S. shale-oil companies are finally getting some recognition as a permanent fixture in the global industry.
Here’s a rundown of the major news from Houston.
SAUDI OIL MINISTER: OPEC REMAINS A STABILIZING FORCE
Saudi Arabia delivered a message at CERAWeek: Don’t expect the Saudi’s to save the oil market alone.The kingdom has shouldered the brunt of production cuts agreed to last year among the 13 nation OPEC cartel and 11 other producers, designed associated with a deal by OPEC and external oil producers to eliminate about 2% of global supply. The output deal helped send crude prices up 20%. Saudi energy minister Khalid al-Falih said OPEC will look at inventory levels in May as it evaluates whether to extend the production cut into the second half of the year. In reference to recent shale oil developments, Mr. Falih He warned an audience full of American producers who have benefited from the production cuts to not fall prey to “wishful thinking that OPEC or the kingdom will underwrite the investments of others.”
“Saudi Arabia will not allow itself to be used by others,” said Mr. Falih.
PRODUCTION CUTTERS DEFEND THEIR COMMITMENTS
Ministers from countries including Russia, Iraq and Saudi Arabia said they were following through on production-cut commitments amid signs the coalition is fraying at the edges, writes Sarah Kent. For instance, Russia has only fulfilled about a third of its pledge to reduce supply, but the country’s energy minister said Tuesday that Moscow is “fully committed” to slashing all 300,000 barrels a day it promised.
OPEC: U.S. SHALE IS HERE TO STAY
OPEC’s chief said the global economy could have been worse off without shale-oil output in the U.S., report Lynn Cook and Miguel Bustillo.
The flood of supplies from American producers over the past sent the oil market into a tailspin, but it also provided new production that was needed to meet demand, said Mohammad Barkindo, the secretary-general of OPEC at CeraWeek. “We only wish it was done in an orderly fashion that did not trigger this severe cycle that we’re still battling to come out of,” said Mr. Barkindo.
OPEC RECONCILING WITH AMERICA
OPEC’S message in Houston has been conciliatory toward U.S producers that it once counted as upstart rivals. Energy scholar Daniel Yergin, who is vice chairman of energy research at IHS Markit, told the Journal that OPEC is accepting shale producers as a major source of oil now much like it came around to the discovery of new supplies from the North Sea in the 1970s. “It’s not so much ‘us-versus-them’ any more, but a watchful but peaceful coexistence,” he said. For OPEC’s part, Mr. Barkindo said: “For the record, we didn’t have any war” with shale producers.
OPEC BREAKS BREAD WITH SHALE PRODUCERS
Mr. Barkindo took his rapprochement with shale producers to the next level, bonding with them over dinners on Sunday and Monday nights in Houston.
“Mr. Barkindo held forth about the Organization of the Petroleum Exporting Countries’ sometimes tense negotiations to hammer out an agreement to cut oil production, according to people at the meeting,” the Journal reported. “Mr. Barkindo assured shale executives that OPEC didn’t want to put them out of business. And OPEC’s top official had an admission for his audience.” “We did confess that we do not have sufficient understanding of how they operate and their impact on us,” he said later.
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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