Benchmarks face 2020s evolution
The reference prices for crude and other energy markets are unlikely to stand still
When a generalist, or even a specialist addressing a wider audience, talks of ‘the oil price’, they mean a benchmark—a commonly traded, well accepted grade of crude. Most likely, the specific price being discussed is West Texas Intermediate (WTI) in the US, Brent in Europe but often more globally, or, in an Asian context, Dubai.
This is because there are hundreds of different types of crude oil which substantially differ in quality and price. Most of them are never really traded—they are transacted on pre-agreed terms and prices, the latter set as differentials to benchmarks. These benchmark grades, in contrast, have very liquid and transparent physical markets, with prices that reflect their quality and fundamental factors prevailing in the regions in which they trade. Active participants in trading benchmarks are referred to as ‘price makers’, whereas the rest of the market are ‘price takers’.
They also have so-called ‘paper’ markets— layers of derivative products linked to underlying physical price of relevant benchmarks and designed to mitigate specific risks— trading in far greater volume than physical oil. Arbitrage in these paper markets facilitate efficient global oil flows.
Benchmarks are not and cannot be set in stone, as they must evolve to accurately reflect the dynamics of the market they are meant to represent, or else they risk becoming obsolete and superseded by alternative references.
WTI in the 2010s offers a good example. US oil production picked up substantially after 2011 as the shale revolution migrated from an initial gas phenomenon into crude. It first choked off oil imports into the US, and then created a domestic oversupply, as a decades-long ban on US crude exports remained in place.
US crude exports to Europe often exceed the whole of North Sea production
As WTI is an inland US market whose international relevance is dependent on representative price spreads between its Cushing, Oklahoma location, physical and derivative markets on the US Gulf Coast and, ultimately, with other global benchmarks such as Dated Brent, this oversupply posed a significant risk. WTI started trading at deep discounts to Louisiana Light Sweet (LLS) and to Brent, more than $25/bl at its August 2011 nadir—in effect, it decoupled from the international markets.
This led Saudi Aramco to switch its US deliveries from the traditional WTI benchmark published by price reporting agency (PRA) Platts to the Argus sour crude index (Asci), published by fellow PRA Argus Media, as early as 2009. However, before WTI could lose its benchmark status, the US oil export ban was lifted in late 2015, relieving the pressure at Cushing and WTI connected again with the international markets.
The relative patience shown by the market in being prepared to wait a number of years while WTI was arguably unfit for purpose reflects how difficult it is to move from one benchmark to another, due to the sheer weight of financial open interest in the derivatives linked to the incumbent price reference. More importantly, it confirms that liquidity wins over basis risk. A liquid but imperfect instrument is preferred to an illiquid, however perfect, alternative by traders.
Evolution, not revolution
This is likely to inform how benchmarks change in the 2020s, with tweaks to the major existing indices perhaps more likely than seismic shifts to entirely new price bases. Again, history provides a guide. Looking back almost 35 years, when oil supply at Cushing dried up following a 1986 price crash, an ‘alternative delivery procedure’ was introduced into the WTI contract incorporating many imported grades of oil. Or, in an early 2000s ‘Asian boom’ where the oil market’s centre of gravity shifted sharply east, the Dubai benchmark needed major adjustments incorporating Oman, Upper Zakum, Al Shaheen and Murban.
The Middle East may be an exception to the narrative of gradual change to existing benchmarks
Dated Brent has also been adding grades, in part due to volume decline, but also as one of its main ‘basket’ crudes, the Forties grade, grew in popularity in Asia, making its Atlantic Basin physical trading more vulnerable to trader ‘squeezing’. Further adaptability is going to be key to its survival in the 2020s.
As the shale boom continues, US crude exports to Europe often exceed the whole of North Sea production. If the Brent benchmark does not respond to this challenge—probably by incorporating new North Sea grades such as Johan Sverdrup, delivered WTI or other grades from outside northwest Europe—it could become irrelevant as a benchmark.
US crude production climbs sharply in the 2010s - Source: BP Statistical Review
WTI at Cushing also faces a post-2020 challenge, given its diminishing importance for international buyers of US crude. They are more concerned about the price of WTI at the US Gulf where they load the oil. For this reason, all major PRAs and exchanges have recently launched some form of US Gulf loaded WTI contract. These could in time challenge WTI at Cushing’s dominance, or at least become relatively liquid satellites to the Nymex exchange-traded behemoth.
Middle Eastern promise
The Middle East may be an exception to the narrative of gradual change to existing benchmarks. Its producers have long wanted more control over their export prices. While Oman has had some traction, there is a fair chance that Murban could emerge over the next decade as a new benchmark in the region.
Recently, the Intercontinental Exchange (Ice) and Abu Dhabi’s state-owned oil firm Adnoc have announced the launch of a new, physically delivered Murban futures contract. Murban has many advantages which could make it a solid benchmark—material production of over 50mn bl per month; aside from Adnoc’s mainly term contracts, BP, Total and additional smaller shareholders form a wide seller base of sellers; and its 40° API and 0.7pc sulphur quality make it popular among many East of Suez buyers.
Asian demand for light sour crude has increased significantly, creating a need for benchmarking
Asian demand for light sour crude has increased significantly, creating a need for benchmarking such grades. Murban is already being used by arbitrage players of Forties as well as traders of Russian grades (Espo, Sokol, Sakhalin Blend). Details of the new contract are not fully confirmed at the time of writing, but several contractual changes will be required in the way this grade of oil is sold and traded to make the contract work. The key to success will be contractual (abolishing destination restrictions) and the use of the exchange settled prices in setting up the OSP (instead of the current retroactive pricing). The rewards, though, may well be worth it.
China, soon to be the world’s largest oil consumer, is also keen not to be left behind as global benchmarks evolve. In 2018, Shanghai International Energy Exchange (INE) launched its own futures index based on medium sour oil delivered to bonded storage in China. The contract is denominated in yuan, making it less appealing internationally. Its bonded storage Cif location, limited number of buyers and credit issues with some smaller buyers are among issues making the index unlikely to be anything other than a regional marker, at least for the time being. And China’s increasingly confrontational approach in global geopolitics is likely to make internal players ever more wary, rather than more accepting, of Chinese ambitions to host global benchmarks. However, the sheer size of the Chinese domestic market could make even a regional benchmark count.
Other energy markets, such as refined products and natural gas—as well as other physically delivered bulk commodities such as coal and iron ore—have evolved along a similar path to crude, emphasising the durability of the benchmark model. Indeed, gas looks, at first glance, very similar to oil, with genuine global benchmarks emanating from the US, Henry Hub (HH), and Europe, the Dutch TTF market, and a less mature Asian benchmark, Platt’s Japan Korea Marker (JKM).
Blockchain technology could allow oil market participants to securely and accurately capture all trades
But gas also illustrates potential challenges to the providers of existing benchmarks. Given that pipeline gas is, by the nature of having to be within the quality parameters of its network, standardised, there is no natural disconnect between the physical and financial markets. The Ice TTF front-month futures contract is essentially indistinguishable from the over-the-counter front-month physical forward contract as assessed by the dominant PRA, Icis. And thus the (considerably cheaper) option of using the exchange, rather than PRA, price, is open to those wishing to link long-term contracts to a TTF benchmark.
Nymex WTI aggregate open interest on a long uptrend - Source: CME
In oil, exchanges and OTC trades may exist alongside each other for quite some time, as they do for Brent and Dubai swaps–trades done through an OTC broker get cleared and posted on the exchange. While some argue that the exchanges eliminate the need for the PRAs and their price assessments, the issue of price convergence between futures and physical markets remain. The intricacies of physical seaborne crude trading mean it could not be easily put straight onto an exchange without first establishing a reference price within the cargo market.
Artificial Intelligence (AI), algorithms, data mining, ‘black box’ trading and so on are terms already applied to various computerised trading strategies that increasingly dominate oil markets. Just like any other human activity, oil trading will be more and more dominated by information technology. Consultancy Wood Mackenzie predicted in December that blockchain technology could allow oil market participants to securely and accurately capture all trades. If they had first been able to agree a methodology to convert this data into a price—and with back-up options to cover every imaginable scenario—it could pose a challenge to PRA benchmark providers in the decade to come. That, though, may be easier said than done.
West Texas Intermediate (WTI)
West Texas Intermediate (WTI) with a delivery point in Cushing, Oklahoma was listed by the New York Mercantile Exchange (NYMEX) in March 1983, alongside then existing heating oil and gasoline contracts. It was a physical oil delivery contract, designed around well-established, physical trading around the Cushing hub. Spot trade quickly grew, and the PRA Platts started publishing prices for WTI as well as the sour grades LLS and West Texas Sour (WTS).
Interaction between the oil gathering centres, pipelines, refining and import/ export facilities is the key to understanding development and dynamics of the WTI benchmark. The pipeline links to the US Gulf (USG) are essential in keeping the benchmark linked to the rest of the world. Between the mid-80s decline in domestic production and the rise of US shale production, imported sweet barrels set the price of WTI. Even during the 1977-2015 US crude export ban—meaning the US domestic/international oil market interaction was purely one-way, the sheer size of the US domestic market provided sufficient trading liquidity to keep WTI as one of the most important global benchmarks.
Dated Brent is arguably the world’s most important oil benchmark, dominating as a pricing reference for the Atlantic basin (North Sea, Mediterranean, and Africa) and for most ‘sweet’ (low sulphur) crudes in Asia (Australia, Malaysia, Vietnam and others). The Dubai benchmark is also derived from the price of Brent.
With production from the Brent field itself, which started up in 1976, about to finish, ‘Brent’ simply remains a brand name of a benchmark that has reinvented itself many times since the 1980s. As Brent production fell, other sweet North Sea grades were gradually introduced into the contract. This ultimately created a price based on a so-called ‘basket’ of crude grades—Brent, Forties, Oseberg, Ekofisk and Troll—technically named BFOET, but still widely referred to as ‘Brent’. Physical Brent basket volumes have also been boosted by widening the loading ‘window’ from the original 15 to the current 30 days forward.
The most peculiar feature of the physical Brent market is that it is generally traded as a differential to Dated Brent (Dated simply means physical Brent, with loading dates). PRAs in effect assess the Dated Brent price based on physical trades, which are themselves differentials to Dated Brent. Fortunately, the expected closing price assessments for Dated Brent are traded in a liquid derivatives market as weekly swaps, called contracts for difference, or CFDs. CFD swaps play a key role in establishing the value of Dated Brent, hence sometimes a criticism that the derivatives tail is wagging the physical crude oil value dog.
Dubai has been the main Asian benchmark since the mid-1980s, responsible for pricing of almost 30mn bl/d currently exported from the Middle East to Asian markets. Like Brent, Dubai production has diminished substantially—from a peak of about 400,000bl/d in 1991 to below 70,000bl/d—and also evolved into a brand name, allowing for the delivery of Oman, Upper Zakum, Al Shahen and Murban grades of oil into the Dubai basket during a daily pricing window between 1600 and 1630 Singapore time. Dubai partials, i.e. a tranche of a cargo, trade on a fixed price basis in $/bl only during this half an hour window. For the remainder of the trading day, all Dubai trades trade as swaps against Brent futures (exchange for swaps, or EFS), against Brent swaps, and as spreads to other Dubai swap months (swap spreads). A large derivatives eco-system has grown around the Dubai ‘brand name’, feeding back into the price discovery of the benchmark itself.
Unlike Brent and WTI, Dubai has no liquid functioning futures markets—albeit EFS, Brent-Dubai, and Dubai swap spreads frequently trade over-the-counter as well as on the exchanges. And true benchmarks trade at fixed prices in $/bl, and thus set the ‘absolute price level’ against which other oil grades can trade, so Dubai could be argued to not be a global benchmark to class alongside WTI and Brent.