Everyone in the oil industry wants to see high oil prices back, because everyone wants to make money. Oil producing countries want to make higher revenues, oil companies want to earn more profits, and people want higher salaries and more jobs.
But, when high oil prices become the reason for the downturn in the oil market, and result in people losing their jobs, companies making no profits and others going bankrupt, then everyone starts to be afraid of the return of high oil prices.
How high oil prices led to the oil market downturn?
High and sustained oil prices in the past few years have made many uneconomical resources such as shale oil and deepwater's more economical to be produced. Given the fact that oil prices were sustained at high levels during the past few years, many oil and gas companies started investing aggressively in developing these resources.
The investment growth provided a suitable breeding season for more advanced technologies to be developed. These technologies have helped to increase the oil production from such resources and lower its production cost. Everything worked well and the oil production of non-OPEC producers who have these resources started to increase such as U.S. oil production.
OPEC' producers -led by Saudi Arabia- felt that the new oil production is a threat to their market-share. As a result, they changed OPEC's policy from balancing the oil market and sustaining high oil prices into defending their market-share. They kept pumping oil, and the oil market become oversupplied. Oil prices started to fall and that is exactly what led to the downturn.
Today, after almost two years of the oil market downturn, oil prices are raising again. However, not everyone in the oil industry is happy about it, even those who want it so bad.
Why oil producers are afraid of the return of high oil prices?
On the one hand, OPEC members who -in the past few years- have worked closely to balance the oil market in order to keep oil prices high to increase their revenues are now fighting for market share. They have realized that, while high oil prices environment was good for them, it has also helped their rivals increase their production and become a threat to OPEC market share.
In order for OPEC members to eliminate that threat, oil prices must remain below their rivals' breakeven prices. And lately, it become clear that $50 a barrel and below is where OPEC's members should keep oil prices in order to prevent their rivals from recovering and growing.
OPEC members desperately want to see high oil prices back, but what can they do about it? Nothing. They know that if oil prices went above $60 a barrel, many shale oil producers will be back in the game and their production will increase. In fact at $50 a barrel oil price, we now hear that few U.S. oil companies planning to start drilling activities this year.
The Saudis and their market-share strategy's supporters are afraid of high oil prices. It is like a nightmare for them now. If they want to see high oil prices again, then, they have to lose some of their market-share. And if they did that, they may end up losing their influence in the oil market. They can't offered to do that, can they?
On the other hand, despite the fact that shale oil producers are desperate to see high oil prices back in order to make profit, they know exactly that the price of high oil prices is high.
If oil prices increased to a high level any time soon, which is highly unlikely, many shale oil producers will resume their oil production and drilling activities especially those who were squeezed out. That will result in higher global oil supply which if not met with a similar demand would lead to a fall in oil prices.
Given the fact that OPEC members are now protecting their market share, there is no way that they will cut their oil production to balance the market. What they will do instead, they will increase their oil production in order to create another downturn to force shale oil producers out of the market again.
In fact, they are doing it right now. OPEC oil supply continues to increase and that is driven by the return of oil output from Iran. Not only that, but also a few other members are planning to increase their oil output such as Iraq, Kuwait, Libya and UAE. Even during their meeting last week, they reached no production ceiling agreement. That means, they will not offer any help to balance the oil market other than forcing their rivals to cut their oil output.
What OPEC members are doing right now tells shale oil producers and other non-OPEC producers that the return of high oil prices is not a good idea for business. Shale oil producers do not want to experience another downturn because they were the ones hit hard by the current downturn. And this is the reason why they are afraid of high oil prices as well.
It seems now that all oil producers whether those of OPEC or non-OPEC agree that the risks of high oil prices are more than its benefits. Therefore oil prices will remain in a range of $40 to $60 a barrel for the rest of 2016 unless unexpected geopolitical or market event takes place.
By Alahdal A. Hussein
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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