OPEC counts 13 countries among its membership, but one of them has long reigned as a first among equals.
Saudi Arabia, with its production of around 10.2 million b/d representing about a third of the group’s output — and about 11% of world supply — has served as OPEC’s de facto leader, its swing capacity traditionally leading the organization’s efforts to manage the market.
But last week’s failed talks in Doha to enact a production freeze saw a potential new oil producer group emerge with another player in the room that could have changed the dynamics of the market and challenged Saudi political eminence in world oil affairs.
The Doha summit of 18 nations included 11 OPEC members and several major non-OPEC producers, most notably Russia, whose output surpasses Saudi Arabia’s at close to 11 million b/d, according to its energy ministry.
Russia has geopolitical ambitions of its own that in many cases do not align with Saudi Arabia’s, particularly in the Middle East, where the two have clashed over the civil wars in Yemen and Syria.
But Russia and Saudi Arabia were among the leading architects of the freeze proposal, before Saudi Arabia reversed course as the Doha talks took place.
Had the talks been successful and a production freeze implemented, would Russia have found itself with an influential international perch in a new oil producer group that supplants OPEC’s role in overseeing the market?
The question is moot for now, as it was Saudi Arabia flexing its political muscle at the meeting, scuttling negotiations over its insistence that Iran be a party to any production freeze agreement and demonstrating that the market still is beholden to Saudi wishes.
But the failure of the talks, coming on the back of a fractious OPEC meeting in December, when the group scrapped its production ceiling altogether in a disagreement over output policy, has brought into sharp question the future of OPEC, which holds its next regular meeting June 2 in Vienna.
OPEC is dead, many commentators have written, as divergent interests have cracked the group and made any consensus on how to manage the market as unlikely as a blizzard in Doha.
“We’ve killed OPEC,” Texas Congressman Joe Barton said in a February interview with CNN, saying the December lifting of the US’ decades-old restrictions on crude exports will put a further squeeze on the producer group.
The Republican is not entirely wrong on premise, though his OPEC death declaration is a bit overwrought. After all, OPEC has ridden through price crashes and fractious relationships before.
OPEC still attracting new members
“OPEC is a bureaucratic organization; it is unlikely to go away anytime soon even if it never made another production decision,” said Jamie Webster, a Washington-based independent analyst. “It may be ineffective on the big decisions, but it is arguably still relevant in some form.”
Dysfunction and recent Doha embarrassment aside, OPEC membership still maintains sufficient cachet that Indonesia reactivated its suspended membership last year, while Gabon is also seeking to rejoin the group, he noted.
Even Washington-based consultant Bob McNally, who characterizes the current market as having entered a “post-OPEC” era, due to OPEC’s unwillingness to serve as swing producer, said the organization will remain as a conduit for its members to discuss market strategy.
“OPEC members are used to operating amidst high tensions among members,” said Bob McNally, a former energy adviser to US President George W. Bush. “They will exchange competing views in the meeting and to the press afterward, but this is par for the course.”
Beyond hosting the twice-annual meetings of its member oil ministers in Vienna, where it declares its output policies, OPEC also provides research on the market and issues regular reports to the public, and its secretary general, Abdalla el-Badri, speaks frequently at forums to represent producer views.
OPEC’s Vienna secretariat hosts a workforce of about 150, including researchers, statisticians, administrative staff and public relations personnel.
Amrita Sen, the London-based chief oil analyst with Energy Aspects, said to look for signs of obvious discord when judging OPEC’s ability to implement policy.
Russia may still have a role to play, as it appears it could be invited to consultations surrounding the June 2 meeting, though the impetus for now is on OPEC to find a détente among its own sparring factions.
“Historically, the most successful deals, particularly when OPEC is concerned, have worked best when agreed behind closed doors and official meetings have only been used to communicate the pre-agreed message,” Sen said. “That still remains the case.” — Herman Wang in Washington
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
There are things brewing within OPEC. At a meeting in Baku, Azerbaijan last week – which was meant to set the stage for a formal meeting in April to review the current supply deal among the 24-country OPEC+ block – the conclusion of the meeting was that the April meeting would be deferred. The review will now take place at OPEC’s regular meeting in Vienna in June, which is mere days before the current supply deal is scheduled to end. That’s cutting it close, but more interesting for market observers is that it points to the Saudi Arabia-Russia bromance souring.
Prior to the meeting, Saudi Arabia had gone on record to state that the Kingdom believed that OPEC’s job in rebalancing the oil market was far from over and that output cuts were necessary to continue into the second half of 2019. Defying US President Donald Trump’s Twitter tantrums – especially with the Kingdom implicated in the assassination of Saudi dissident Jamal Khashoggi – Saudi Arabia is firmly behind continuing restricted supply. In the past, Saudi Arabia would most likely to be able to bully its way into an OPEC consensus. But now, it has to deal with an equally powerful 20-ton gorilla in the same room: Russia.
The success of the OPEC+ club over the past two years has been down to this close relationship between the world’s two largest oil producers. This had allowed crude prices to recover from sub-US$50/b levels. But the latest meeting is also the latest sign that all may not be well in the friendship. First, a joint Saudi-Russia meeting at the World Economic Forum in Davos was called off. Second, February data showed that while Saudi Arabia and its allies were doing far more than necessary to cut their crude production, Russia was shuffling its feet with less than 50% adherence, claiming that it needed more time to implement the cuts. And last week, despite Saudi Arabia lobbying for an extension to the cuts and general backing from members including Iraq, Russian Energy Minister Alexander Novak was in opposition. The official reason was that OPEC+ would need clarity on market situation before planning the next move, given the disruption brought about by ongoing and developing American sanctions on Iran and Venezuela. In the absence of necessity, the two crude powerhouses have drifted back to their default positions: Saudi Arabia’s aggression and Russia’s conservatism.
So while the world waits and watches for OPEC+’s next move, the market is analysing the potential impact of a strained Saudi-Russia relationship. But necessity might bring the two back together again, since they now face a common foe – rising US crude production. OPEC’s secretary general recently met with key executives in the US shale oil industry. This was billed as a ‘friendly conversation on current industry trends’ and interpreted as an attempt to cajole American shale producers in a mutually-beneficial stabilisation of the market. It is ridiculously unlikely for the US to ever join the OPEC+ club, but if the move could convince US shale firms to temper their expansion to prevent global oversupply, it might be worth it. Because OPEC has accompanied the olive branch with a threat – if OPEC does all the work to stabilise markets only to have American shale take advantage of the situation, it could very well reverse its stance and turn the OPEC tap on full to swamp the market once again. It’s a classic example of game theory, and one to watch as the power dynamics of global oil continue to change.
Key upcoming dates for OPEC:
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