Strategy v market dynamics
Members must consider a host of complex issues as they wrestle with the problem of managing oil supply
Opec production has fallen from 32.9m barrels a day in July 2017 to approximately 31.8m b/d in May this year. The decline has been driven by both intentional cuts (particularly from Saudi Arabia, Kuwait and the UAE) and unintentional ones (Venezuela and Angola). The market is rightly focusing its eyes on Venezuela. The country lost almost 1m b/d of production since 2016, with exports set to suffer further in the coming months. ConocoPhillips' seizure of PdV's storage and loading assets in Netherlands Antilles increases reliance on its already congested domestic ports. For Angola, its heavy weighting of deep-water production makes it particularly vulnerable to further declines.
With Opec itself estimating global oil demand growth to increase over 1.8m b/d this year and uncertainty over how many Iranian barrels are at risk, the call on Opec is in a range of 32-33m b/d this year. Despite the growth of non-Opec supply expected this year from US shale, Brazil and Canada, we're facing heavy and sour crude disruption in physical markets—a situation which makes it difficult for light, sweet US shale to replace.
Despite the growing call on Opec vs actual production, several important points need to be made about the group's optimal output strategy. First, it's exports (not production) which will have an impact on prompt prices. Second, despite a worsening geopolitical risk outlook, all the states involved (Iran, Libya, Nigeria and Venezuela) have differing sources of disruption, geopolitical endgames, pricing differentials and crude destinations. Finally, Saudi Arabia is keen to avoid the risk of weakening differentials without necessarily putting a cap on the oil price, particularly given the risk of demand destruction and higher prices incentivising short-cycle US shale production.
When assessing the real impact of Opec's output policy, it's important to distinguish between production due to seasonality of domestic demand and net export increases driven by any physical market tightness. Saudi production is set to increase over the next several months (having already started in May) as crude burn volumes for power generation increase. It's estimated that production will increase by around 160,000-180,000 b/d to meet seasonal demand.
Saudi Arabia can manage competing US/Opec agendas by adopting a gradualist approach to supply-side management
More importantly, however, Saudi Arabia has shown no sign of increasing exports to its key market: Asia. Official selling prices for July-loading cargoes are at their highest levels since 2014. With exports to Asia likely to remain unchanged over the next several months, it's possible that Saudi Arabia will increase exports to the US, particularly as it's a point closely watched by traders.
In 2017, Saudi Arabia cut exports to the US by 40% from 1.3m b/d in January 2017 to a low of 560,000 b/d in October. Increasing Saudi exports to the US would help mitigate some of the effects of reduced loadings from Venezuela to the US, given similar crude qualities and the demands of US refiners. Elsewhere, increased Iraqi crude exports to India (where it now dominates) can help offset reduced purchases from Venezuela, particularly given the growing relationship between Indian refiners and Iraq's state marketer, SOMO.
A key driver of prompt Brent prices has been growing concern about Opec spare capacity and the buffers to unplanned supply disruptions. Since mid-2017, approximately 1.6m b/d of geopolitical supply disruptions have been offset by gains in Libya and Nigeria. With concerns surrounding Libya's Ras Lanuf and Es Sider terminals resurfacing and Nigeria entering an election year, the ongoing crisis in Venezuelan output will test the resilience of the oil market's buffers.
Despite this, several points need to be raised. First, Libya's oil exports have shown wild fluctuations over the past 12 months and despite a starved National Oil Company budget, any impact to Libyan exports will come from a high base.
For Nigeria, the resumption of security attacks in the Niger Delta has already impacted exports (with Bonny Light declaring force majeure ). However, given the weakness in West African grades, supported by a widening spread in WTI-Brent, growing US exports to Europe and an Angolan crude overhang can mitigate any decline in the physical market.
Second, a comparison of the ratio of geopolitical disruptions versus Opec spare capacity shows that the situation was in fact worse in 2013 following the Arab spring.
Third, the slow response of Saudi Arabia to date on Venezuela's declining production is a strong indicator of the kingdom's gradualist approach. For Saudi Arabia, a slow response to geopolitical disruptions take into account shipping times. Increasing exports too quickly to mitigate any sour crude disruption runs the risk of reacting too quickly, especially if the situation is resolved. This is what happened in the early 2000s following Venezuela's oil strikes.
Finally, the market hasn't yet seen the real impact of President Trump's re-imposition of sanctions on Iran. There are concerns whether EU offtakers can gain waivers from the US ahead of November and uncertainty from tanker owners and insurers. But the impact on Iranian production and exports is more likely to be felt in the long term, as declining investment and inflationary pressures impact decline rates at Iran's southern fields, which require enhanced oil recovery techniques.
For Mediterranean refiners, the declining quality of Russian Urals and Kirkuk blend (due to mixing with heavier grades) has made Iranian oil more attractive. It will be interesting to see how more competitive Iranian pricing in the months ahead impacts EU off-taker appetite. If anything, assessing India's policy toward Iran is a more accurate bellwether of the sanctions, given its strong demand growth and ability to offset any reduction in flows to Europe. Both Iranian discounts to heavy crude and more attractive payment terms for refiners such as Reliance and Essar will be important factors.
Saudi Arabia and Opec's concern about high prices triggering faster US production is less of a risk today than several months ago. In addition to longstanding service-sector constraints, the US shale sector now has to contend with constraints in pipeline takeaway capacity from the Permian basin—a dynamic reflected in the WTI-Midland spread. It's not until the second half of 2019 that this will narrow when an additional 1.25m-b/d capacity will be added.
Similarly, despite the widening of the WTI-Brent benchmark incentivising US exports to Europe and Asia, India—a key demand market—isn't (yet) a major buyer of US crude. The ongoing trade dispute between the US and China also provides Saudi Arabia with the ability to deepen its ties with China, as refiners can increase nominations of Saudi crude to increase its leverage with the US.
In the next six months, Opec's de facto leader, Saudi Arabia, can manage the competing geopolitical agendas of the US and Opec member states (primarily Iran) by adopting a gradualist approach to supply-side management. The real test, however, will be in November when the deal officially expires. By then, greater clarity on Iranian exports will be provided. Likewise, the full impact of Venezuela's escalating crisis will be made apparent, along with other emergent supply-side disruptions: Nigeria and Libya.
Similarly, there are demand growth wildcards like the US-China trade war, Indian demand growth, and changes in the Chinese refining complex, particularly among independent teapot refiners. The real test for Saudi Arabia will be in the medium term, not the next six months.
Ahmed Mehdi is an energy strategist at Livingstone Partners and former senior consultant at PriceWaterhouseCoopers Deal Advisory Unit