Yesterday (All My Exports Seemed So Far Away) – The Future of the Brent/WTI Spread

Next week (January 2016 - according to press reports) Enterprise Products Partners will load the first cargo of U.S. crude oil to be exported without regard to the regulations that restricted such movements to most countries except in certain circumstances for the past forty years. It looks like the lifting of crude oil export restrictions came too late to have much impact on U.S. production or prices in an era of free falling prices. Today we look at the impact of the change on the crude price spread between U.S. benchmark West Texas Intermediate (WTI) and international counterpart Brent.

This analysis combines two of our most popular blogosphere themes about crude oil during the period between 2011 and 2014 when U.S. production of (mainly) light sweet crude from shale increased by roughly 1 MMb/d for four straight years in a row. The first of these themes is the changing price relationship between WTI and Brent and the second is the impact of 1970’s era regulations restricting crude oil exports. The surge in shale output caught just about everyone by surprise – not the least of which were midstream companies tasked with getting that crude from production basins in relatively remote regions like North Dakota, West and South Texas and the Rockies to refineries mostly situated along the coast. Until this crude transport challenge was sorted out to allow crude to flow reasonably efficiently to refinery markets – particularly past the Midwest trading hub at Cushing, OK - a large portion of the new production was land-locked or stranded. The stranded crude was subject to price discounts versus coastal markets – leading to a breakdown in the traditional pricing relationship between inland crudes priced based on WTI  and crudes at coastal markets that were priced relative to international marker Brent. Gradually these transportation issues were resolved – initially by workarounds like crude-by-rail (see The Year of The Tank Car) – and eventually by the build out of pipeline networks connecting new production to coastal markets.

Then the second theme – crude export restrictions – became more prominent. That happened when more shale crude started flooding  the Gulf Coast than refiners could easily handle (see Texas Bound and Flyin’). This refining constraint was not - and is not - to do with there being more crude than refineries could process. The U.S. is still far from self sufficient in crude production and continues to import 7-8 MMb/d to meet demand. Rather the refining constraint has to do with crude quality – namely the fact that many U.S. refineries were not configured to process the type of light (often ultra-light or condensate) crude produced from shale. So as new supplies of shale crude began to arrive at the Gulf Coast they rapidly replaced imported equivalent grades of light crude but could not immediately substitute for the diet of medium and heavy crude that many refineries were better configured to process. In normal circumstances this imbalance of crude quality would have worked itself out in the international marketplace by U.S. producers selling shale crude to refineries overseas that could process lighter crudes and continuing to import the heavier crudes they preferred. However – 1970’s era regulations governing the export of U.S. crude severely limited this normal balancing process (see The Molecule Laws). Because crude exports were constrained - the flood of light crude accumulated at the Gulf Coast – weighing on the market and keeping U.S. prices lower than overseas equivalent grades. Commentators began to talk about a time when U.S. refiners could no longer process all the new shale crude (see Here Comes The Reckoning Day). Producers started lobbying Congress to end crude export regulations that (as they saw it) kept U.S. prices artificially low and shut them out of the world market. Refiners (especially those on the East Coast) argued in favor of the restrictions because lower U.S. crude prices allowed them to compete more effectively in refined product markets overseas. The result of much lobbying on both sides was some loosening of the restrictions – most notably in the case of condensate in 2014 (see CCATS Scratch Fever) and subsequently the idea of crude price swaps in 2015  (see Have Another Swap of Mexican Crude). Then at the end of December 2015 all the wailing and gnashing of teeth about export restrictions abruptly came to a halt as Congress and President Obama removed all the regulations with a stroke of the pen. 

That has led many market analysts – including RBN – to wonder where U.S. crude prices (represented by benchmark WTI) will come to rest in 2016 relative to their traditional international counterpart Brent. We begin our answer to that question with a quick recap of the relationship between these two crudes since the late 1980’s. Figure #1 shows the Brent premium to WTI (blue line) since 1989 using daily settlement prices for nearby delivery London Brent IPE futures and nearby settlements for CME WTI futures. Where the blue line in the chart is above zero (red line) Brent is at a premium to WTI and where the blue line is below zero WTI is trading at a premium to Brent. As we have detailed before in our analysis of the relationship between these two crudes (most recently in Tank House Blues) WTI and Brent are both light sweet crudes with similar refining qualities that should be priced about the same if they are trading in the same market.  Historically that was the case before 2006 as you can see in the first section of the chart in Figure #1 (green dashed oval). For this 17-year period between 1989 and the end of 2005 WTI and Brent prices tracked closely - with WTI generally having a slight premium (averaging $1.55/Bbl) over its international rival – reflecting the freight cost to ship Brent to the US. During this time, Brent and similar light sweet crude grades were regularly imported at the US Gulf Coast since domestic production did not meet refinery needs.