US refiners are once again calling for a domestic crude benchmark that covers more than the standard gravity and sulfur pairing offered by the existing NYMEX contract.
The push is being spurred this time by increasing concentration of shale crudes in the West Texas Intermediate common stream, which have pushed the average API gravity in Cushing – where that contract is delivered – beyond the maximum 42 degrees.
That has forced shippers to blend with heavier crude and bottom-of-the-barrel products in order to meet pipeline specifications, which in turn drives down the value refiners can squeeze out of a barrel, AFPM Senior Director of Refining Technology Jeff Hazle said at a Crude Oil Quality Association meeting earlier this month.
The COQA advocated changing the specifications at the March meeting. It wasn’t the first time. US refiners requested a change in 2010. At the time, CME said the COQA should focus on changing the physical market first, citing the fact that very few barrels of physical crude are delivered against the futures contract.
By 2013, however, CME said it planned to implement additional quality specifications, although that has yet to happen. CME needs backing in the midstream industry, Hazle said.
Technically, the NYMEX contract calls for a light sweet crude deliverable at Cushing, Oklahoma, and specifies several domestic grades, including WTI. The NYMEX contract also allows for the delivery of foreign grades, such as North Sea Brent.
If the CME tightens the contract’s specification, it would need to make sure trading liquidity does not suffer. The CME theoretically could launch a new contract reflecting the tighter specification, although it is unlikely that much volume would shift away from the existing — and very successful — contract.
One thing CME does need is backing in the midstream industry, Hazle said.
Any change to the specifications would have to be supported by the ability to reasonably monitor the relevant qualities of crude coming into the system, and midstream infrastructure isn’t set up for real-time testing beyond gravity and sulfur content yet. Other tests generally involve lab-testing a sample, after which the relevant batch of crude will be long gone into the common stream.
“I think there’s going to be more effort put into getting the midstream companies on board [this time],” Hazle said.
The CME is working on the quality issue with COQA and the refiners, said Dan Brusstar, CME’s senior director of energy research and product development.
“We’re cooperating and working with everybody to try to make the whole transition as smooth as possible,” he said.
If a refiner tried to simply buy crude that meets the further specification, that would mean giving up access to the common WTI stream, which makes it less viable, Hazle said. If they want access to more specific grades of crude, refiners have to set up and operate their own midstream infrastructure, an expensive endeavor, Hazle said.
Still, some refiners have done it, reaching further into basins in order to combat the prevalence of blended or lighter crudes. Western Refining, for instance, uses a fleet of trucks to gather the crude and bring it unblended to its storage tanks, CEO Jeff Stevens said during the company’s fourth-quarter earnings call.
The blending issue has crept further into the refineries lately — not only are they having to buy heavily-blended crudes, but marketers have started buying bottom-of-the-barrel products, like residual fuel and asphalt, to push the crude gravity within spec, Hazle said.
A refinery might sell residual fuel or asphalt to a shipper at a discount to WTI crude, only to see that product blended back into the stream for them to buy at the full crude price — something that happened recently to at least one Midwest AFPM refinery, Hazle said.
US Gulf Coast waterborne 1.0% sulfur resid was assessed by Platts at $23.90/b Wednesday, a $10.78/b discount to Cushing WTI.
When that crude makes it back to the refiner, it will yield the residual fuel blended in on top of whatever ambient resids that were already in the crude, Hazle said. That means the concentration of low-value products keeps increasing, cutting into refinery margins.
“You’re going to end up with more of a low-valued product than you would have expected,” Hazle said.
The stream was indeed seeing WTI deliveries outside of the specification in 2015, and those deliveries have been trending lighter, making blending more common as additional shale crude finds its way into the market, Ashok Anand, the director of petroleum quality at Enbridge Pipelines, said at the COQA meeting.
“The shale oil came into existence in big numbers [in 2015],” Anand said. “We’re getting stuff that’s over 42 API, which really means it’s getting lighter.”
Enbridge owns one of the largest terminals in Cushing, with more than 90 tanks and about 21 million barrels of storage, Anand said.
When a counterparty delivers or takes delivery of out-of-spec crude at a leased Enbridge tank, “it’s really between the buyer and the seller to settle it,” Anand said.