Canadian CBR Vastly Overbuilt And Utilized -- RBN Energy -- February 29, 2016; Rolling Storage In The Bakken

Active rigs:

	2/29/2016	02/29/2012	02/29/2008
Active Rigs	38	204	62

Bakken CBR tankcars being used for storage --The Wall Street Journal: The U.S. market is so oversupplied with oil that traders are experimenting with a new place for storing excess crude.

Thousands of railcars ordered up to transport oil are now sitting idle because current ultralow crude prices have made shipping by train unprofitable. Meanwhile, traditional storage tanks are running out of room as U.S. oil inventories swell to their highest level since the 1930s.

Some industry participants are calling the new practice “rolling storage”—a landlocked spin on the “floating storage” producers use to hold crude on giant oil tankers when inventories run high.

The combination of cheap oil and surplus railcars has created a budding new side business for traders. J.P. Fjeld-Hansen, a managing director for trading company Musket Corp., tested using railcars for storage last year and found he could profit by putting the oil aside while locking in a higher price to deliver it in a later month.

The company built a rail terminal in Windsor, Colo., in 2012 to load oil shipments during a boom in U.S. oil production. Now, Mr. Fjeld-Hansen says, “The focus has shifted from a loading terminal to an oil-storage and railcar-storage business.”

Canadian CBR vastly overbuilt and underutilized.

In Part 1 of this series we noted that CBR volumes are falling across the U.S. and Canada. The decline is mostly in response to narrower spreads between U.S. domestic crude benchmark West Texas Intermediate (WTI) and international equivalent Brent. The lower spreads reduce the incentive to move crude from inland basins to coastal refineries by rail because the latter is a more expensive transport option compared to pipelines (which mostly transport crude to the Midcontinent and Gulf Coast). When WTI was discounted to Brent by upwards of $25/Bbl in 2011 and 2012 because of congestion caused by a lack of pipeline capacity, it made sense to use rail to get stranded crude to market. We described the resulting increase in U.S.

CBR shipments from 33 Mb/d in January 2010 to a peak of 928 Mb/d in October 2014 (according to EIA). As new pipelines have been built out to provide less expensive options to get stranded crude to market so the WTI discount has narrowed dramatically and CBR traffic has declined. Primarily in response to the narrowing spread - CBR volumes fell during 2015 but not as fast as you might expect – dropping only 20% between January and November 2015 (latest EIA data) even though the spot market economics often made no sense.

As we discussed in Part 2 – looking at the epicenter of the CBR boom in North Dakota – the slower than expected decline in rail shipments is mostly because committed shippers and refiners continue to use rail infrastructure that they invested in and because some routes still do not have pipeline access. In Part 3 we looked at CBR traffic out of the Niobrara shale region in the Rockies. Rail load terminal infrastructure there was built in Colorado and Wyoming in response to increased crude production from the Niobrara shale over the past 4 years. Now although crude production in the region is down from 2014 peaks and expected to only grow slowly in the next 5-years if oil prices stay low – midstream companies continue the build out and expansion of rail terminals as well as new pipelines. This time we look at the fate of CBR load terminals built out in Western Canada in today’s low crude price environment.

Over the past two weeks we detailed the sorry plight of producers in Canada’s oil sands region in the face of record low prices for local benchmark heavy crude Western Canadian Select (WCS) at Hardisty in Alberta. For some producers the transport costs to get these heavy crudes to market are so high that at today’s crude prices they make minimal or even negative netbacks (crude selling price minus transport costs) at the wellhead.

The high transport costs include a penalty for blending in expensive light hydrocarbon diluent at the wellhead to dilute bitumen crude so that it can flow in pipelines. Producers not only have to pay more for diluent than the value of the blended WCS, but they also have to ship the diluent to markets as far away as the Gulf Coast (over 2000 miles). Nevertheless – as we noted in “Desperadoes” – Oil Sands producers continue to run their steam assisted gravity drainage (SAGD) bitumen plants despite losing money because they otherwise risk damaging these 40-year long-term production assets. And previous investment means that new projects continue to come online so that incredibly, – Canadian crude production is expected to continue growing. 

The Canadian National Energy Board (NEB) forecasts that total crude production will increase by about 5% during 2016 from 3.9 MMb/d in January to 4.1 MMb/d in December with oil sands SAGD production expected to increase by 9% in 2016. With Canadian market needs already met, almost all new production heads to the U.S. where closer-by Mid-Continent refinery demand for heavy crude is saturated – meaning producers have to ship all the way to the Gulf Coast to find new markets. For Canadian producers the long distances to market in the U.S. have been compounded by delays in the build out of more economic pipeline routes out of Canada – culminating in the November 2015 Presidential cross-border permit rejection of the proposed 800 Mb/d Keystone XL pipeline. The history of CBR in Western Canada is closely entwined with pipeline congestion on routes to the U.S. such that producers turn to more expensive railroad options when they can’t get access to pipeline capacity.