Brent

At the end of last year the Department of Commerce Bureau of Industry and Security (BIS) issued clarifications designed to clear the way for greater U.S. exports of processed condensate. More companies have received BIS approvals to export – the latest being Plains All American last Thursday. Last year expectations were that as much as 230 Mb/d would be shipped in 2015. But narrowing price differentials have reduced the arbitrage necessary to make exports economic. Nevertheless midstream companies continue to invest in infrastructure to deliver processed condensate to marine docks. Today we review the state of the export market and ongoing infrastructure plans.

It’s been a big year for oil production from the Bakken formation in North Dakota with output passing the 1 MMb/d mark in April and expected to close out 2014 at 1.25 MMb/d. Crude netbacks (market price less transport cost from the wellhead) suffered during the first half of the year from narrowing coastal price differentials - denting the economics of crude-by-rail - the most popular option to get Bakken crude to market. Rail freight costs look set to increase in 2015 with new tank car regulations and requirements for wellhead treatment to remove volatile components. But those changes pale into insignificance compared to the recent crude price nosedive. That threatens to reduce producer revenues by billions of dollars in 2015 and puts the spotlight on higher transport costs to get crude to market from North Dakota. Today we look at the financial impact lower netbacks could have on Bakken producers.

If 2012 was “the year of the tank car” in North Dakota then 2014 could turn out to be the year when crude by rail economics turned sour for producers. New pipelines are coming online to deliver increased volumes of crude to the Gulf Coast with more projects on the drawing board. Safety issues and traffic congestion are raising the cost of rail freight. But the biggest challenge to rail is the pressure from narrowing crude price differentials between North Dakota and coastal markets. Producers can now get better returns shipping barrels by pipeline and in a falling price market they are more incented to make the switch. Today we explain why rail may be losing its edge.

It isn’t often that a market measure simultaneously shrinks in quantity and gains in importance, but that is the case for crude oil imports into Gulf refineries this year. Six to nine months ago, traders were predicting the end of imports, and signaling a declining interest in how much foreign crude is still making it into the US. The indifference has turned into keen interest as two trends emerge: A far from smooth decline in total volumes, and a rising correlation between imports and PADD 3 storage.  In today’s blog, we examine these developments and their implications for the market.

Recent rumors coming out of Washington DC suggest that changes to US regulations that severely limit exports of US crudes are alternatively imminent or being discussed with a view to repeal. Many US producers have argued that the export ban should simply be removed in order to allow the free flow of crude oil across borders. Today we ponder the impact of an end to the crude export ban.

Crude oil exports from the United States are heavily restricted by Department of Commerce regulations introduced in the 1970’s that are administered by the Bureau of Industry and Security (BIS). These regulations prevent the export of US crude oil except to Canada or in specific circumstances from Alaska and California (see I Fought the Law). In Episode 1 of this series we discussed the consequences of a partial end to the ban on crude exports that might occur as a result of a change to the BIS definition of lease condensate – a very light hydrocarbon that is nevertheless defined as crude that cannot be exported. Production of lease condensate is booming in shale plays like the Eagle Ford in South Texas. Our analysis imagined that if the condensate export ban were lifted tomorrow, much of this material would be exported to Asia as a petrochemical feedstock. This time around we widen the debate to wonder what would happen if there were a complete removal of the ban on crude exports – including lease condensate.

The crude export regulations were written at a time when a shortage of oil threatened US security and prompted legislators to prevent domestic producers sending supplies overseas. Between the mid-80’s and 2009, US crude oil production was in long term decline meaning that dwindling domestic supplies were eagerly snapped up by US refiners and the export ban was never more than an occasional issue (such as when Alaska North Slope – ANS- production exceeded West Coast refinery requirements in the 90’s). Since 2010, however, the US has undergone a dramatic crude renaissance, principally as a result of the shale oil revolution. Current production is over 8.4 MMb/d – its highest level since October 1986 – up 50 percent since the start of 2011 (see Like A Bat Out of Hell). And while production is soaring, proved reserves are increasing even faster – laying the groundwork for continued output.

But although US crude production is surging, the country still imports upwards of 7 MMb/d to meet refining demand, so you might think that calls to end the export ban are premature. The trouble is there’s a mismatch between the quality of crude the US is now producing in abundance from shale, which contain a preponderance of light components, and refineries that are for the most part configured to process heavy crudes or light crudes that contain more middle or heavy distillate components than typical shale crudes (see The Charge of the Light Brigade). In effect, much of the new crude production is not best suited for processing in existing refineries without the latter undergoing potentially expensive and time consuming reconfiguration. The result is that crude supplies from prolific production in basins such as the Eagle Ford in South Texas and the Permian in West Texas are washing up at Gulf Coast refineries that are struggling to process so much light crude. And crude inventories at the Gulf Coast have recently reached record levels of close to 400 MMBbl even as refineries in that region run at over 90 percent of capacity.

In our view, the disposition and price impact of light crude surpluses are some of the most important issues in the crude oil and petroleum product markets today, and will continue to be for the next few years – regardless of what happens to BIS regulations.  For that reason, RBN has joined with Turner, Mason and Company to provide a conference focused specifically on this topic.  “Surviving the Flood of Light Crude Oil” is scheduled for August 19-20 in Houston, and is designed around many of the principles used at RBN’s School of Energy, including laptop computer access to all presentation materials and spreadsheets in real time, structured content from RBN and Turner Mason experts, and no executive project sales-pitches. Register now while space is still available. For more information on the conference, you can download the brochure here. 

And of course the export ban poses a further challenge to the US crude quality mismatch because producers are required to sell their crude to US refiners rather than perhaps seeking more suitable buyers overseas that want to process light crude. As with any market where too much product is chasing after too few buyers, US crude producers are therefore getting less money for their barrels right now than they might if exports were permitted. The data in Figure #1 sheds light on this pricing issue. The red line is the premium of international benchmark light sweet crude Brent over the Gulf Coast equivalent crude benchmark, Light Louisiana Sweet (LLS). These two crudes have similar characteristics, so would expect to be valued fairly closely in international markets. And that is roughly how they traded until last summer. Between November 2009 and August 2013 Brent averaged about $1/Bbl under LLS – a little less than the cost of freight between the North Sea and the Gulf Coast.

This week on Monday WTI prices crossed the $100/Bbl mark for the first time since the end of December (they closed at $100.37/Bbl yesterday February 12, 2014). Brent crude traded at a $19/Bbl premium to WTI at the end of November but the spread has fallen to less than $10/Bbl in recent weeks ($8.42/Bbl yesterday). One of the biggest concerns hanging over the crude market is the fear of oversupply – both inside and outside the US – with the forward curves pointing towards WTI at $78/Bbl and Brent at $90/Bbl by 2020. Today we provide an update on the crude market.