For decades, the West Texas Intermediate (WTI) has served as the benchmark for crude oil in the U.S., but since it only represents light crude oil, some experts have called for the addition of another benchmark to reflect shale super-light oil.

Since WTI only represents the production of light crude oil, the advent of a third U.S. benchmark, the experts say a shale super-light would produce more accurate commodity pricing.

“The supply-demand mechanism and the hedging can be more effectively risk priced,” said Patrick Morris, CEO of New York-based HAGIN Investment Management.

WTI is refined mostly in the Midwest and Gulf Coast regions and is a light crude oil with an API gravity of around 39.6, which is lighter than Brent crude, he said. It contains about 0.24% sulfur and is rated as a sweet crude oil, sweeter than Brent which has 0.37% sulfur.

“If you look at the actual production, a fair amount has API greater than 40 and the blend is trending toward 45-50 or more largely due to the fact that fracking releases smaller molecules, almost like a filter,” Morris said. “The lighter stuff gets through while the heavier stuff remains trapped.”

Since the refiners in the U.S. are generally wired for a heavier crude, the super-light molecules are less appealing, he said. This lighter crude oil works for blending with heavier oil, but there are functional limitations.

Adding a benchmark for shale super-light oil would be beneficial because West Texas is producing a super-light crude oil and not an intermediate blend.

“The Brent to WTI spread is likely to blow out,” he said. “The Permian needs a new futures contract, a so-called Texas super-light. The storage at Cushing is effectively empty and the oil coming out of West Texas is not attractive for refiners because it is super light and doesn’t yield the same quantities of diesel, gasoline and kerosene that the intermediate does.”

A growing mismatch between the quality of crude oil produced by U.S. E&Ps and the types that are typically processed by U.S. refiners affects both oil markets and equities, Martijn Rats, an equity analyst at Morgan Stanley, said in an April 16 report.

The increase in U.S. oil production is occurring only in the super-light grades or those with grades that are “not just ‘light’ but ‘super-light,’” i.e. API gravity above 40, he said. “There was no production growth in grades with API gravity below that.”

The problem is that refineries in the U.S. are designed for a heavier crude slate than shale and processes on average grades with API gravity of about 32.

“Domestic refiners, however, cannot take much more of this and are close to hitting the 'shale wall,’” Rats said. “Taking in more super-light shale would reduce overall refinery utilization. To work around this, U.S. refiners have so far accommodated shale by blending it with super-heavy grades. These, however, are increasingly hard to get.”

U.S. shale is estimated to consist of 70% of oil supply growth over the next five years, according to forecasts from the International Energy Agency, but is ‘super-light.’

Some hurdles exist because the market for super-light crudes outside the U.S. is relatively modest and only 15 million barrels per day (bbl/d), Morgan Stanley estimates. The seaborne market of API 40+ crudes is outright small and merely 6 million bbl/d.

Another issue which crops up is that although U.S. production has been growing strongly in recent months, this is concentrated in the super-light grades. Refiners are not predicted to set a larger capex to process more light oil.

“We expect they will simply allow themselves to be the beneficiaries as domestic light- and super-light oil production becomes increasingly challenged to find a home,” Rats said. “U.S. refiners will essentially be ‘paid-to-wait’ for the price of light- and super-light crude to become discounted enough to the point where it becomes an economic option to run the crude even if it means suboptimal operations.”

The competition between WTI and Brent, the two global benchmarks, has gone back and forth for the past decade, said Bruce Bullock, director of the Maguire Energy Institute at Southern Methodist University's Cox School of Business in Dallas.

As U.S. production and exports are rising consistently, WTI is beginning to overtake Brent again as a global benchmark since WTI contracts are now more useful for global traders and shippers, he said. As supply in the U.S. grows and becomes the swing producer, WTI’s importance as a benchmark will continue to rise.

The one challenge with WTI is that the price is at a landlocked hub at Cushing, Okla., rather than at one of the key ports which makes it a more fungible commodity, Bullock said. Competition is also heating up from China as they have launched futures trading on the Shanghai International Energy Exchange (INE) with the goal of being the Asian benchmark.

WTI is likely to remain a major benchmark even though WTI-Cushing is “really just a U.S. price and is tied to U.S. Gulf Coast prices such as Magellan’s east Houston price minus transport,” said Justin Carlson, a managing director of research at East Daley Capital in Centennial, Colo.

The east Houston price is more reflective of exports and imports since it is directly on the coast and since the city is home to a large percentage of U.S. refineries.

“At WTI-Cushing, the crude has to be moved from Cushing to its final demand destination,” he said. “One reason someone may advocate for one price over another is due to the specific market value they are trying to capture.”

Investors favored the NYMEX Light Sweet Crude Oil (WTI) futures contract as it set new record highs in both volume and open interest in 2017, according to the CME Group, a Chicago-based derivatives exchange group.

Open interest surged to a record 2.69 million lots in November 2017, while daily trading volume averaged 1.23 million contracts per day in 2017, up 12% over 2016. The number of contracts through April 24 is up by 19% year over year.

The WTI benchmark has transformed itself and is “now a world oil contract” because of record U.S. oil production and export growth from the shale revolution and as WTI futures trade during Asia’s trading hours and increased by 41% in 2017, said Owain Johnson, managing director, energy research and product development of CME Group.

“The U.S. has a massive impact on the benchmark,” he said. “Out of all the global benchmarks, the WTI is the healthiest and growing the fastest.”

A third benchmark is Dubai Mercantile Exchange’s Oman crude oil futures contract, which reflects the production and export of oil from the Middle East, Johnson said.

As demand in the Asia-Pacific oil rises, a new Chinese crude oil futures contract could become the Asian price benchmark in order to manage price risk, according to an April 25 report by the Energy Information Administration (EIA). The region, consisting of Asia and Oceania, represented more than 35% of global petroleum and other liquid fuels demand in 2017, an increase from the 30% of petroleum demand in 2008.

“Some market participants believe the region needs an oil price benchmark based on local supply and demand conditions,” the report said. “Last month marked the beginning of trading for the new Shanghai crude oil futures contract in China. For the Shanghai contract to become an accepted regional benchmark, it will have to attract a wide variety of market participants, and its usage for price discovery must be established.”

Dubai Mercantile Exchange's Oman futures contract was established in 2007, but its daily traded volume and open interest have remained at low levels and does not appear to be representative of the Asian crude oil market.

The Shanghai crude oil futures contract is priced in Chinese yuan per barrel while nearly all other crude oil transactions are priced in U.S. dollars per barrel. After trading for one month, the Shanghai futures contract for September 2018 delivery already has more open interest and trading volume than the Oman contract for September delivery, the EIA report said.