Daily Energy Blog

At the end of June Koch announced plans for an open season that started July 1, 2013 to solicit interest in a pipeline project to deliver 250 Mb/d of crude from the Bakken to Hartford and Patoka, IL. Koch’s plans suggest the new pipe could connect to St James, LA on the Gulf Coast via the proposed Energy Transfer/Enbridge Energy joint venture Gulf Coast Crude Access pipeline. If the pipeline proceeds, it would come into service in 2016. Earlier Bakken pipeline projects have failed because of flexible rail options. But rail rates from the Bakken to the coasts are currently underwater due to narrowing crude spreads. Today we review the project’s prospects.

The West Texas Intermediate (WTI) discount to Brent narrowed 80 percent since February 2013 to close at $4.05 on Monday July 8, 2013. As a result the netbacks that crude producers in North Dakota receive for barrels sent to the East Coast has tumbled and they can now make more money sending crude to market on the pipeline route to Cushing. Today we run the numbers on changing Bakken netbacks.

Finding profitable markets for the rapidly increasing volumes of condensates produced in the Eagle Ford and other U.S. shale plays will be challenging. Sure there will be a growing Canadian need for condensates as a diluent for oil sands-derived bitumen, but that will still leave U.S condensate producers with a big surplus. The logical thing would be to look further afield, but selling to overseas markets— particularly to the growing Asia/Pacific region—is a complicated matter. First, an export license for “raw” (unprocessed) condensate to overseas markets is required, but no such licenses are being issued. Second, the Asia/Pacific region is also experiencing supply growth.

Permian crude production is expected to increase 28 percent between 2013 and December 2018 to 1.8 MMb/d (Bentek). Existing pipeline takeaway capacity and local crude consumption are currently barely enough to handle production of 1.4 MMb/d. However, planned new pipeline capacity should comfortably handle output by the end of 2015. Today we review the impact of new Permian takeaway capacity.

The new Turner Mason (TMC) study titled “North American Crude and Condensate Outlook” (NACCO) forecasts a high case 8.2 MMb/d increase in crude supplies from US and Canadian production over the next 10 years. While most crude imports will be pushed out by this production surge over the 10-year period, a minimum structural import level of about 1.4 MMb/d will remain. As domestic and Canadian crude supplies overwhelm refining capacity in coastal regions TMC predict crude exports will be required to balance demand. Today we review TMC’s crude market and refinery operations predictions.

According to a new study just released by Turner Mason titled “North American Crude and Condensate Outlook” (NACCO), U.S. crude oil production could nearly double between early 2012 and 2022.  At least that is the Study’s “high case” production scenario.  That is very good news for U.S. refiners.  Perhaps less good is the fact that 80% of the volume growth is light sweet crude, super-light crude, or even lighter condensate.  How will refiners digest all of this light crude and what impact will the growing supply have on price differentials?  What will the surge of light crude mean for waterborne and Canadian heavy crude imports?  Today we start a two-blog series that will examine some of the findings of TM&C’s  “2013 North American Crude and Condensate Outlook” (NACCO).

Narrowing price differentials between inland crudes tied to West Texas Intermediate (WTI) and coastal crudes tied to Brent are resulting in a move away from rail shipments and back towards pipelines by producers in North Dakota. The switch away from rail is already having an impact on the lease rates for rail tank cars. Which could call into question the huge backlog of orders for new tank cars. Today we ponder the possibility of a bust in crude-by-rail shipments.