“Amateurs talk about strategy but professionals study logistics,” as an old military saying has it. The current collapse in oil demand places more stress on logistics than ever before. Where will supply be cut, how can it stay profitable, and where can it be stored and sold?
There are three ways production can be reduced. Producing wells and fields can be shut-in because the sales price for oil and gas does not cover their operating costs, or because they physically have no available access to export or storage. Supply can decline naturally and more gradually because of a halt in investment (new drilling and processing facilities). Or Opec countries and others can voluntarily reduce output, either unilaterally or more likely, through coordination.
The calculation of economic survival has become extremely complex in this matter of wafer-thin margins. It depends on operating costs, transport costs to market, the costs of stopping or restarting production, taxes, and oil quality. Goldman Sachs estimates that 1 million bpd of uneconomic production is already shut-in worldwide.
Companies may keep producing at a loss for a while, because they have contractual commitments to customers or pipelines, or because they fear the wells will not be viable to restart once shut down. But smaller firms will quickly run out of money. Bankruptcy may expunge their obligations, and new owners of the assets will continue operating only the profitable ones.
The current collapse in demand has affected gasoline (petrol) and jet fuel more than diesel for trucks and fuel oil for ships. So light crudes, like those from American shale oil, north and west Africa, have lost value relative to medium-grades typical of the Middle East and Russia.
Many government fiscal schemes impose a fixed tax on oil production regardless of profitability – either a limit on how much costs can be set against tax each year, or a royalty levied on gross revenues. As prices fall, governments face a difficult choice: waive these rules temporarily and give up badly-needed revenue, or keep them and risk production shutting down entirely.
Disadvantaged producers include the landlocked ones – facing high transport costs to destinations where demand may be in freefall. Those who have long sea voyages to remaining markets confront rising tanker costs as the ships have been snapped up to carry expanded exports from Saudi Arabia, or to act as floating storage. Heavy crudes, such as those from Canada and Venezuela, face the double whammy of higher production costs and lower sales prices than benchmark grades.
At the start of this price war, there was an idea Russian companies were immune because of their low production costs. But their problem is market access. Though the Espo pipeline from East Siberia reaches China and East Asia directly, exports through the Druzhba pipeline, rail and barge to European destinations are likely to be choked back as the continent’s refiners cut their throughput. Crude exports from the Baltic face a long journey to Asia. That partly explains why Saudi Arabia cut its official selling prices, particularly for Europe, after the Opec+ deal broke down a month ago.
When the price for Russia’s benchmark Urals grade fall below $15 per barrel, companies stop paying mineral extraction and export taxes. So Russian government oil revenues will approach zero faster than the drop in prices.
Global production will also decline steadily as investment in new wells and fields dries up. Shale oil will take the brunt of this initially. Many conventional non-Opec projects have already been canned, but given their long lead-time, this will only have a major impact on production from 2022 onwards.
Finally, the leading Opec countries and Russia, the only producers large and flexible enough to balance the market, could return to a renewed pact to limit output. But despite Donald Trump’s hopeful tweets, it’s practically unlikely the US will join in, and without that, a deal remains out of reach for now.
In this environment, the target market becomes key. East Asia, where the response to the virus has been better, and where China is increasing purchases for its strategic crude reserve, is now an even more important buyer than before the crisis.
Storage has emerged as a key strategic asset. Saudi Aramco has storage at the Egyptian Mediterranean terminal of Sidi Kerir, the Dutch port of Rotterdam and the Japanese island of Okinawa, as well as at home. Adnoc has agreements to store crude in India’s strategic reserves and is building a 42-million-barrel underground facility at Fujairah. Private Abu Dhabi firm Brooge is also expanding its storage in the east coast emirate.
Equity partners in fields in places such as Oman, Abu Dhabi and Iraq can be required to lift their share of oil, shifting the responsibility for selling it. National oil company access to joint-venture refineries or long-term sales contracts can also help place barrels.
In the 1985-6 price bust, Saudi Aramco began offering “netback” contracts which guaranteed refiners a profit based on the sales price of their products. But such arrangements may not work now that the products are not even wanted. Some Indian refiners have already declared force majeure, a legal manoeuvre to avoid taking unwanted deliveries.
The leading Gulf producers have to pull out all the stops. As the market shrinks and prices plunge, they have to ensure it is their oil that gets to market first. That is the fastest way to drive out the high-cost producers, or set the stage for a deal, a brutal but necessary process.
Robin M. Mills is CEO of Qamar Energy, and author of The Myth of the Oil Crisis