Producers’ mindset needs to change
Storage logistics have never been more challenging, playing to oil traders’ strengths. Pure producers’ structural lack of patience may only assists them
Oil trading companies’ mastery of storage economics in a contango market—where future, so-called ‘curve’, prices are higher than the immediate physical market—bears comparison to investment banks. Just like M&A activity, IPOs and other relatively low-risk banking functions, storage plays are seemingly simple.
Work out the cost of storing oil and, when the price difference between prompt and curve exceeds that cost, buy the barrels, pay for the storage, sell the volumes in the futures market and pocket the difference. But, in practice, it is much more complicated.
For example, management of physical oil pricing based on Dated Brent using contracts for difference (CFDs), exchange of futures contracts for physical oil (EFPs) exposures, accounting for arbitrage opportunities (e.g. Brent/Dubai or WTI/Brent location spreads) and many other complexities, is far from simple.
There is also an additional optionality layer provided by having the physical barrels to hand. A sudden, possibly geography-specific, supply disruption could cause a rally in spot prices. Stored barrels could then be re-sold profitably back into the market earlier than in the planned storage play, while the associated hedges can be closed. Again, though, ensuring that this is done while adding additional value requires both logistical and risk management skills.
Often misunderstood, it is the prompt price and emerging contango that informs traders to store. As demand picks up and balances improve, contango gradually narrows to the level where it cannot cover the costs of storage. It is a signal for the market to stop storing and eventually to start releasing the barrels back into the tightening market. These price signals help regulate stocks, planned production etc. and bring the market into equilibrium.
Supply that is already far outstripping demand will not materially reduce immediately
Therefore, one of the key functions of the futures markets is to provide information regarding spreads and promote the economically desirable control of stocks. The industry closely monitors weekly stock levels, especially the US Department of Energy figures, for trading purposes. But they are just an indicator and not a cause of price movements—in the same way doctors would not consider elevated body temperature levels to be the cause, but rather a symptom, of illness.
Hardest challenge yet
The current market will continue to offer one of the toughest storage challenges ever faced. The demand loss over March, April and potentially more months to come, is at least into double figures in mn bl/d terms, possibly by over 20mn bl/d according to some forecasts.
The agreed Opec+ supply cuts will take time to physically implement, meaning that supply that is already far outstripping demand will not materially reduce immediately. Even if and when production drops by anywhere close to 10mn bl/d, it may not yet match the demand missing before any substantial post-coronavirus rebound.
Readily available storage convenient to major supply and demand hubs is rapidly filling. The next step is to move to capacity in less premium locations, such as Saldanha Bay in South Africa. But that entails more shipping, more cost and more uncertainty—again favouring the experienced traders.
Tankers are a commodity in themselves—the more required for storage, the more expensive chartering them
The next step involves even greater complexity, as lack of capacity onshore sees unwanted physical volumes stored on ships, so-called floating storage. Storing oil in this way is far more expensive—you need to pay for ship hire, crew and other logistics costs you do not incur with tanks on costs—thus requiring a larger contango to justify doing so.
And the economics of floating storage are multi-layered. Tankers are a commodity in themselves—the more required for storage, the more expensive chartering them, thus the need for a greater contango to justify, and make a profit from, doing so. There is also the interplay between vessels commandeered for storage and having enough ships to do their primary job of moving oil around, yet another potential variable on the prices driving storage economics.
Coping for now
Should the current unprecedented mismatch between supply and demand threaten to overwhelm the usual onshore storage sites; other, less favourable terminals that can be pressed into service; and the volume of ships that can be made available while still allowing the required deliveries to be made, the storage spread would blow out entirely. Supply cuts by the necessity of being unable to evacuate the barrels would have to bring both the physical and traded markets back into equilibrium.
There is no clear sign of this yet. While stretched to the limit, the existing price system has performed well. With implied volatility has exceeding well over 100pc, quality differentials and Dated Brent have taken the brunt of price adjustment in the massively oversupplied market (see Dated-M1 in Figure 1). Using a daily storage rate for a VLCC (no steaming) of $210,000/day (equating to well over $3/bl per month), for floating storage to work, contango has to widen by at least the equivalent amount. It is no coincidence that the Brent spreads (M1-M2 and M2-M3 in Figure 1) normally find some short-term support around that level.
Unless production cuts are effective and all storage fills—most analysts agree that we could reach that point by the end of May, if not before—there is no more support or limit to how far the price differentials can fall. This is often referred to as ‘super-contango’.
Given these challenges, it is perhaps not surprising that, by and large, the NOC producers continue to produce now and leave trading houses and IOCs that have built sophisticated trading arms to the ‘easy’, or, rather not-so-easy money to be made from storage plays.
While NOCs have been making efforts and setting up their own trading arms for many years now, they have a long way to go before they can challenge the major oil traders in managing oil in space and time, both logistically and financially.
In theory, there is a simpler option. Storing the oil in the ground, i.e. not producing it, is a lot cheaper than leasing tanks, paying for insurance, incurring pipeline and tank losses and so on. Moreover, many oil producing countries could borrow money to cover unproduced volumes in the financial markets at same, if not better rates, as the trading companies.
Few countries other than Saudi Arabia are willing to produce at less than their current maximum possible rate for any length of time
It used to be argued that forward selling by producing countries of deferred production would overwhelm the futures markets. While this argument might have been valid a decade ago, it is no longer the case. The main global oil benchmarks—Brent, WTI, Dubai and Oman—trade in large multiples of the daily global oil production. Mexico is a good example of a producing country hedging exports, for up to a year at a time.
Max now, not later
But few countries other than Saudi Arabia are willing to produce at less than their current maximum possible rate for any length of time. So, storing oil is the ground is not really a practical option, because, if the barrels are deferred, there is no capacity to produce them in addition to a baseline some months further down the line.
Barrels thus ‘stored’ in the ground are only available at the end of the life of a field. This is why the producers are so reluctant to defer their production when contango appears. However, hedging a portion of their production forward, at least at good times and high oil prices, thus ‘locking in’ some of their revenues, is certainly a viable option. After all, this is exactly a strategy that made shale oil producers so resilient in the past.
The current demand crisis may change the way a number of NOCs and for some non-national producers that lack trading sophistication view the market. They might be advised to consider if, in a ‘new normal’, they might want to think more about the value that both greater physical flexibility and available derivative instruments might offer them.
Adi Imsirovic is a research associate at the Oxford Institute for Energy Studies