It is either a brave or delusional man who thinks he can write an interesting article about oil price indices, but on the basis that Portland was set-up during the 2008-9 financial crisis, we shan’t let those characteristics get in the way of this month’s report! This is because there are some fairly chunky changes being proposed in the way that crude oil prices are to be reported and these changes will affect not only the millions of dollars of oil contracts executed every single day, but also many of the key indicators that the world has come to rely on with regards global economic health.
How the pricing of North Sea oil came to be such an important global economic benchmark is worthy of a whole article in itself, but suffice to say, North Sea oil is the marker price for oil traded around the world. When people refer to the oil price, what they are really talking about is North Sea oil. Fully 70% of the world’s production is priced off North Sea grades and the specific grade in question is commonly referred to as “Brent” (after the original 1970’s field of the same name). In reality though, the “Brent” price is actually made up of several different North Sea crudes – including Brent – but also including Forties (UK sector), Oseberg, Ekofisk and Troll (all Norwegian sector). All of the “Brent” grades have similar high quality, low-sulphur characteristics, which gives them a higher market value than heavier, “sourer” crudes from elsewhere (eg, the Middle East). Furthermore, North Sea oil is sold direct to ship (FOB = Free on Board) for onward distribution around the world, making it a “pure”, free-market oil price, tainted by neither logistical complications nor political interference.
For the last 10 years, “Brent” has faced a growing existential crisis, born out of dwindling supply. As the North Sea oil fields mature, so production diminishes, which means far less “Brent” can be bought and sold. Back in their heyday, the Brent fields were producing as much as 2m barrels per day (bpd), allowing multiple trades of the black gold on a daily basis. But now, declining output is falling below the baseline 1m bpd mark and in recent pandemic-struck months, volumes fell to 400,000 bpd (less than 0.5% of global oil production). If we deduct product sent by pipeline direct to the UK mainland, this leaves enough oil for barely 1 or 2 international trades per day – hardly the sign of a robust global market, underpinning everything from oil, derivatives and gas contracts, to inflation indices and investment funds.
Which is why there is now the radical suggestion to include West Texas Intermediate (WTI) in the Brent pricing pot. Technically there is some sense in this, as WTI is a “sweet”, light crude (high quality), just like its North Sea counter-parts. But commercially speaking, this is a truly seismic proposal. Historically, WTI has been sold to the US inland market, which means it reflects a set of commercial fundamentals quite different to those of the North Sea crudes that serve the rest of the world. Equally significant is the fact that by definition, including American oil in a North Sea price basket, must mean that the oil has been delivered to the North Sea region (a so-called “CIF” price = Carriage, Insurance & Freight) as opposed to the current FOB nature of Brent sales.
The terminology may be confusing, but the outcome is very simple. A FOB cargo sold direct to ship represents a core product price, whereas a CIF North-West Europe price has to account for 2 “alien” factors. Firstly it has to reflect the source of the crude (in this case, the USA market) and secondly, it has to include the cost of shipping from the USA to Europe. In both cases, divergence from Brent economics is easily possible and very likely. If the US oil market goes haywire (for whatever reason), it doesn’t necessarily follow that the world economy will immediately follow suit. When it comes to freight, the obvious statement is that shipping adds cost, but also the freight markets are themselves notoriously volatile, which adds further unpredictable dynamics to the price of (Brent) oil.
The addition then, of US crude to a North Sea basket seems to make little sense, although the core conundrum of declining North Sea production still remains. Pricing publishers argue that without a supplemental grade, the North Sea can no longer justify its over-sized importance. They also argue that since the US shale boom and resultant increases in American oil exports, WTI is already the mainstay of North West European oil trading, with over 450,000 barrels arriving in ARA (Antwerp-Rotterdam-Amsterdam) every day. And then there are the cynics who point out that a market friendly American crude is far more desirable than adding one of the Russian blends or alternatively, relying on the China dominated oil exchanges of the Middle East (eg, Dubai Mercantile Exchange).
That takes us back to WTI as the “least worst option”. Of course, numerous interested parties will still want to have their say over the next few months. Producers, Refiners and Traders will have to decide what changes need to be made to their supply contracts (some of which are 10 year term deals) and then all eyes will turn to the paper markets (eg, Intercontinental Exchange = ICE, New York Mercantile Exchange = NYMEX). Without their support, the trading liquidity that is the foundation of all oil markets will be lost. And all the while, government tax bodies (such as HMRC in the UK) will also be taking a very keen interest in developments, as numerous Petroleum Revenue Taxes around the world are calculated against Brent.
All in all then, not quite the snorefest you might have expected – but do expect it to become one soon, as every interested party argues over every miniscule detail. Like the super-tankers that carry the oil, when it comes to pricing mechanisms, making directional changes is a cumbersome process and although discussions are well under-way, we wouldn’t expect these to manifest themselves into anything “concrete” until 2022 at the earliest.
