5 Takeaways From Platts Houston Global Crude Conference
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5 Takeaways From Platts Houston Global Crude Conference

We don’t just see earth from space. We like to hit the road, meet with clients and interact with folks in the industry which is exactly what we did this week.

 

Seven of us descended upon Houston to attend the S&P Global Platts North American Crude Oil Exports Summit, which was sponsored by Ursa.

 

With all the news about OPEC right now, the event brought some balance. Yes, the fallout from Iran sanctions matter. It is equally true that US exports have begun moving the needle in the global oil market.

 

The emergence of a major export player is very rare. What is even more exceptional about US exports is the absence of a national oil company calling the shots.

 

This competitive structure means there are many different companies in action. The Platts Houston conference brought those players together under one roof.

 

Here are the Top Five Takeaways:

 

#1: Bottlenecks will persist:

 

Pipelines are being built to take crude out of the Permian Basin, but these projects aren’t expected to come online until late 2019 at the earliest.

 

The logistical constraints behind WTI Midland discounts will therefore continue. The bottlenecks will prevent more crude from reaching Gulf Coast ports creating a ceiling on exports until the issue is resolved.

 

Crude exports are also crucial for the growth of domestic production. Gulf Coast refining capacity won’t expand by much between now and the next few years, leaving refiners abroad as the only hope for reaching new customers.

 

#2: Crude grades are too variable:

 

The fluctuations in US crude physical characteristics because of blending has upset refiners abroad who aren’t accustomed to dealing with this type of issue.

 

“A barrel of [Nigerian] Bonny Light is a barrel of Bonny Light,” one panelist said. “WTI can be a range of things,” he said.

 

Refiners sometimes pay less money for US crude to compensate them for the quality risk, but this workaround isn’t seen as a long-term solution.

 

Ursa co-founder and VP Derek Edinger gives opening remarks in Houston

 

 

#3: Gulf Coast market is segregated

 

Some supply reaches the Gulf Coast while avoiding a pit stop in Cushing where blending occurs. That has caused the market to split into places where barrels for sale are marketed differently.

 

For example, the BridgeTex and Longhorn pipelines run directly from West Texas to Houston. Those barrels are then stored in segregated tanks at the Magellan East Houston (MEH) terminal.

 

This delivery structure comforts buyers. They know they’re getting WTI Permian. The rest of the market is now under pressure to conform to similar standards.

 

The CME group has even amended the contract specifications for WTI crude delivered to Cushing under the light sweet futures contract.

 

In addition, producers would like for new pipelines to be segregated by crude type. Midstream companies building those lines are apt to listen because they need commitments from producers to use those lines.

 

#4: Who wants to handle shipping?

 

Not all US oil companies want to deal with the logistics and risk that accompanies exports. The first point of sale occurs before the barrel leaves the Gulf Coast.

 

A refiner could agree to FOB Gulf Coast terms. But the refiner is worried about freight rates rising after the sale has been finalized. A good deal can become a bad one. Nor are there tools available to hedge freight rates.

 

For a European refiner, there is less risk associated with a barrel of light sweet crude, such as CPC Blend or Saharan Blend. The cross-Med route is obviously shorter than trans-Atlantic.

 

Who wouldn’t mind dealing with freight risk? Integrated oil companies or major trading houses. They have the expertise and appetite for arranging ocean freight. These are the players likely to sell US crude on a delivered basis.

 

#5: Gulf Coast storage matters

 

How much supply is there? It’s a basic question potential buyers of US crude exports will want to know the answer to. Outside of the US, supply is organized into monthly loading programs.

 

No such program exists on the Gulf Coast. Nor can supply be measured solely in terms of tankers leaving ports every month. There is storage sitting in tanks that must be counted in the supply figure.

 

That requires having access to inventory data on a more granular level than provided by Energy Information Administration data. Alternative sources capable of tapping into new technology will fill this void.

 

 

 

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