Vienna (Reuters) - For OPEC watchers, every little detail matters.
When the oil producer group holds its half-yearly meetings, what time the ministers arrive in Vienna, how they speak and which hotel they stay in - anything will be analysed in an attempt to predict its policies.
So it was seen as a sign that new Saudi Energy Minister Khalid al-Falih takes OPEC seriously when he turned up in the Austrian capital on Monday, three days before the Organization of the Petroleum Exporting Countries' upcoming discussions.
But Falih will have little opportunity to see fellow ministers ahead of Thursday's meeting. Many of them, including those from Iran and Venezuela, won't show up in Vienna until midday or even late on Wednesday.
For veteran OPEC watcher Gary Ross, founder of New York-based consultancy PIRA, that signals expectations should be low as far as OPEC policy is concerned.
"These guys are not exactly getting along these days," Ross said. "OPEC is becoming far less important. We are entering an era when market management will be non-existent".
One exception to the later arrivals was UAE Oil Minister Suhail bin Mohammed al-Mazroui, who told journalists in Vienna on Tuesday that he was happy with the oil market, suggesting OPEC should refrain from action at this week's meeting.
"We need to wait. The market will fix itself to a price that is fair to the consumers and the producers," Mazroui said.
"This year is a year of correction. The rules of the market, that is supply and demand, are working and I think that is the essence of this policy."
OPEC last decided to change output in December 2008, when it cut supply amid slowing demand due to a global financial crisis. By contrast, between 1998 and 2008, OPEC made 27 changes to output.
For decades, Saudi Arabia, Vienna-based OPEC's largest producer and de facto leader, had a preferred range for oil prices and, if unhappy, would try to orchestrate a group-wide production cut or increase.
But a technology-driven spike in non-OPEC output such as that of U.S. shale and growing fuel efficiency led Riyadh to conclude that the era of fast oil growth might be ending.
In the past two years, Riyadh has stuck to a strategy of fighting for market share, thinking that pumping more oil now at low prices is better than producing less in the future.
"We think continuity will carry the day at the June OPEC meeting in Vienna. The only real uncertainty is how divisive the meeting will be and how much discord will be put on public display," said Helima Croft, head of commodity strategy at RBC Capital Markets.
FIGHT FOR SHARE
Unlike his predecessor, Saudi oil minister Ali al-Naimi, Falih has a much larger portfolio overseeing energy, industry, mining, atomic power and renewables.
On Tuesday, Falih visited OPEC headquarters to meet Secretary-General Abdullah al-Badri, staying for 90 minutes in a clear display that despite being a busy man, he has time for the producer group.
"There are times when you need OPEC and when you don't. You only need OPEC when you have major oversupply and OPEC doesn't want prices to crash any further," Ross said.
Oil prices have recovered to around $50 (£34.5) per barrel in recent weeks from their lowest in a decade of $27 per barrel in January - but are still far below the $115 seen in June 2014.
Prices crashed after Saudi Arabia increased production to an all-time high to fight for market share with higher-cost producers, including U.S. shale firms.
The drop in prices also badly hurt fellow OPEC members, with production declining from Nigeria to Venezuela.
Iraq and Iran, however, kept pushing production higher as Baghdad sees recent investments by oil majors pay off and Tehran regains market share after the lifting of some Western sanctions in January.
Falih's ultimate boss, Saudi Deputy Crown Price Mohammad bin Salman, has said Saudi Arabia may raise production further if other members don't restrain their output increases.
"As long as Mohammed bin Salman is in charge, I don't think anything reasonable (OPEC action) can happen. This policy has hurt not only the exporting countries, but companies and the industry," a non-Gulf delegate said.
By Alex Lawler, Rania El Gamal and Reem Shamseddine
(Additional reporting and writing by Dmitry Zhdannikov; Editing by Dale Hudson)
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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