Global Oil & Gas: Opec and oil market dynamics

opec-secretary-barkindo-0305_barakshrama_plenary_9630Opec’s goal of defending high oil prices may suit some members in the short run, but its long-term impacts could be damaging.

Since its historic agreement in November 2016, Opec’s efforts to manage the oil market have shown signs of success: key benchmarks are in backwardation, speculative positioning has been at record length and a floor price of $60 a barrel has been defended. Strong Opec compliance—both voluntarily (Saudi Arabia) and involuntarily (Venezuela)—has been supported by stronger-than-expected demand growth. By Opec’s own measure of success, its target of reducing five-year commercial OECD inventories has been largely met (currently between 30-50m barrels above five-year average).

Output policy evolution

Opec’s preferred oil price has always been a moving target, ranging from $100/b (following the financial crisis) to $30 (after the oil price collapse in 2014). The balance between higher oil prices to support fiscal budgets (and debt capacity) and the need to maintain (and increase) market share has been a dilemma faced by Opec for the past 40 years.

Several important lessons have been learnt about Opec behaviour in previous oil cycles: first, output cuts must be coordinated (and not unilateral)—a bitter experience endured by Saudi Arabia in the 1980s; second, Saudi Arabia cannot sustainably keep production above 10.5m barrels a day to meet supply shortfalls (as witnessed in 2011 following the Libya civil war and later in 2013, following the tightening of Iran sanctions); third, Opec’s high output, low price strategy (after 2014) wasn’t driven solely by a willingness to allow the price mechanism to clear the market of high-cost production. The strategy was also a result (partly) of some Opec members, particularly Iraq, raising production (primarily from IOC-operated fields in the south).

Opec can’t only consider short-cycle US shale as a source of supply-side risk

Similarly, non-Opec countries, such as Russia (a party to the 2016 cut), benefited from rouble devaluation to increase production (and mitigate brownfield declines) from greenfield assets owned by Rosneft and GazpromNeft.

Whilst Opec (particularly Saudi Arabia and Iraq) and non-Opec (Russia) benefited from increasing production and market share, their ability to compete on the cost of marginal production (supported by Opec’s low lifting costs and large resource base) failed: the pain of low oil prices was too severe for Opec economies, especially given their high fiscal breakevens (over $80/b on average). The lack of flexibility of Opec economies to adjust to a competitive oil price structure is likely to continue, especially given their fixed currency regimes and the difficulties in removing subsidies across the Middle East and kick-starting non-oil economic growth.

The current Opec/non-Opec strategy of cutting production to 1.8m b/d has been active for almost 16 months now: the International Energy Agency (IEA) has already called Opec’s goal “mission accomplished” with OECD inventories nearing their five-year average; declines in Venezuela are set to increase further into the next quarter (particularly if the US targets Venezuela’s naphtha imports); and the threat of Iranian exports decreasing would further support Opec’s already-strong compliance rate.

In the current market context, it’s worth asking the following: is Opec too focused on managing the market’s expectations on long-run oil prices (with talks of a “decades and generations”-long alliance with Russia) instead of managing short-medium risks to its position? After all, one of the lessons (and mistakes) after 2010 was to defend prices at too high a level, encouraging investment outside Opec in Brazil, Canada and the US; this policy not only hurt consumer demand but also incentivised alternative energies.

Short-cycle US shale: Opec’s view

So far, Opec has argued that any increase in US production can be absorbed by the rise in global oil demand. Furthermore, Opec can find solace in the fact that, notwithstanding high refinery utilisation rates in the US, Gulf Coast refiners (given their complexity) are equipped to process heavier grades (particularly Iraq’s Basrah Light, Arab Medium and Kuwaiti blends).

Furthermore, despite the threat of US shale in the oil cycle of 2009-14, both the high API gravity and its small representation in seaborne export markets (approximately 6m b/d), US super-light—the vanguard of future production growth—hasn’t made significant inroads in Opec’s major market: Asia. The “big three” oil exporters to China remain Saudi Arabia, Russia and Angola; similarly, Indian refiners have increased Iraqi imports and the growth of Saudi Arabian and Russian investments in the country have supported their crude marketing. Certainly, a number of complex refiners in South Asia will be able to adjust their crude diets to accommodate lighter oil; however, the destination of US shale is more likely to be Europe, a region where oil demand is set to decline over time.

Narrower price range
Despite this, Opec can’t only consider short-cycle US shale as a source of supply-side risk. The real problem for Opec is the convergence of other sources of supply with short-cycle shale oil: low variable-cost oil (Brazil, Canada); large-reserve, low-cost oil (Iraq); and offshore (Norway, Mexico and UK). The decline in breakeven costs since 2014 and increased capital discipline by producers gives a stronger picture of upstream Final Investment Decision (FID) projects than Opec would like to believe (the number of FID projects sanctioned for 2018 is estimated to be double that of 2016). As a result, the price range in which supply and demand can grow together is far narrower than Opec would like.

With talk of Saudi Arabia’s preferred price range of $80-100/b, the kingdom’s front-loaded and over-ambitious goals-especially its flagship Saudi Aramco initial public offering-are distorting Opec’s optimal output strategy. In one respect, higher oil prices today could help Saudi Arabia’s Public Investment Fund invest in its long-term renewable strategy, helping the kingdom transition away from fossil-fuel dependency. However, the bigger threat is from higher prices eroding demand growth, especially given the increased sensitivity between prices and demand.

Revising production targets
Moving forward, Opec’s ability to manage both a narrow price range and output risks from Venezuela, Iran, Libya and Nigeria will add strains on its de-facto leader, Saudi Arabia. One solution could be to revise the current output targets, allowing countries with a less volatile production outlook (such as Iraq) to increase their output (particularly because of the volatility of Libyan, Nigerian and Venezuelan volumes). Given Saudi Arabia’s official policy to maintain spare capacity above 1.5m b/d and the challenges it has faced in keeping production above 10.5m b/d for sustained periods, Iraq could act as a stabilising force within Opec, especially given the alarming rate of involuntary cuts, led by Venezuela.

Geopolitically, providing Iraq with greater manoeuvrability (its willingness already signalled by eroding compliance) would help with its post-Islamic State reconstruction efforts-a bellwether of future geopolitical stability, particularly important as the country moves into a new electoral cycle and seeks to offset growing interference from regional neighbours, such as Iran. From Opec’s perspective, the risk of overtightening the market and allowing prices to overshoot given both the current geopolitical landscape and greater sensitivity between oil prices and demand is a short-term risk that Opec should avoid.

Dr Falah Al-Amri is the former Director General of Iraq’s Oil Marketing Company (SOMO) and previously served as Iraq’s Opec governor.

Ahmed Mehdi is an Energy Strategist at Livingstone Partners and former Senior Consultant at PriceWaterhouseCoopers Deal Advisory Unit

This site uses Akismet to reduce spam. Learn how your comment data is processed.

%d bloggers like this: