During all the turbulent phases, and amidst the economic slump, the most critical component is that how swiftly the manufacturers can product their Oil in the market.
“Amateurs mention strategy however, the professionals’ study and know their logistics,” as an old military adage has it. The present failure 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 3 ways manufacturing are often reduced. Producing wells and fields are often shut-in because the sales price for oil and gas doesn’t cover their operating costs, or because they physically haven’t any available access to their entire export or storage. Supply can decline naturally and more gradually due to a halt in investment (new drilling and processing facilities). Or Opec countries as well other hydrocarbons and oil production nations can voluntarily reduce the output, either separately or more likely, through coordination.
The calculation of economic survival has become extremely complex during this matter of seldom profit margins. It depends on operating costs, transport budgets to plug, the fees of stopping or restarting production, taxes, and oil quality. Goldman Sachs estimates that 1 million bpd of an uneconomic production is already shut-in globally.
Corporates can keep producing at a loss for a short time, as they need contractual commitments to customers or pipelines, or because they fear the wells won’t be viable to restart once pack up. However, a relatively smaller firms will quickly run out of cash. Bankruptcy may delete 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 quite diesel for trucks and heating oil for ships. So light crudes, like those from American 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 hard and fast tax on boring no matter profitability – either a limit on what proportion costs are often set against tax annually, or a royalty levied on gross revenues. As net value diminishes, governments face a turbulent choice: of waiving these rules temporarily and provides 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 could also be in freefall. Those that have long sea voyages to remaining markets confront rising tanker costs because the ships are snapped up to hold expanded exports from Saudi Arabia, or to act as floating storage. Heavy crudes, like those from Canada and Venezuela, face the double whammy of upper production costs and lower sales prices than benchmark grades.
At the beginning of this price competition, there was a thought Russian companies were immune due to their low production costs. But their problem is market access. Though the Espo pipeline from East Siberia that reaches China and East Asia directly, exports through the Druzhba pipeline, rail and barge to European destinations are likely to be overcome back because the continent’s refiners have now reduced in their output.
Crude exports from the Baltic as well face an extended 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 worth for Russia’s standard Urals grade fall below $15 per barrel, companies immobilized paying mineral processing and export taxes. Therefore, the Russian government crude oil revenues will approach zero faster than the drop by prices.
Global production also will deteriorate steadily as an investment in new wells and fields dries up. Crude Oil will take the brunt of this initially. Many conventional non-Opec projects have already been preserved, but given their long lead-time, this may only have a serious impact on production from 2022 onwards.
Finally, the leading Opec countries and Russia, the sole producers large and versatile enough to balance the market, could return to a renewed pact to limit output. But despite US president Donald Trump’s hopeful tweets, it’s practically unlikely that the US will take part, 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 a better pivotal buyer than before the crisis.
Storage has emerged as a key strategic asset. Saudi Aramco has a storage at the Egyptian Mediterranean terminal of Sidi Kerir, the Dutch port of Rotterdam and therefore the Japanese island of Okinawa, also as a buffer. 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 additionally expanding its storage within the East Coast emirate.
Equity partners in fields in places like Oman, Abu Dhabi and Iraq are often required to lift their share of oil, shifting the responsibility for selling it. National company access to joint-venture refineries or long-term sales contracts also can help place barrels.
In the 1985-86 price ruins, Saudi Aramco began offering “netback” contracts which guaranteed refiners a profit supported the sales price of their products. But such arrangements might not work now that the products aren’t even wanted.
The leading Gulf producers need to pull out all the halts. As the market shrinks and costs plunge, they need to make sure it’s their oil that gets to plug first. That’s the swift thanks to drive out the high-cost producers, or set the stage for a deal, a brutal but a pivotal process.
