http://blogs.platts.com/2018/11/12/us-bakken-crude-takeaway-constraints/?utm_source=twitter&utm_medium=social&utm_content=barrelblog&utm_term=we-oilOil produced in North Dakota’s Williston Basin is the latest North American crude grade to experience plummeting values because of what many in the industry say is rising output and tightening pipeline takeaway capacity combined with regional refinery maintenance.
Bakken crude values began experiencing a rather sharp decline at the start of October when a combination of factors began to weigh on values.
Midcontinent crude traders have spoken about Bakken differentials being pressured by pipeline-constrained Canadian grades, as well as ongoing refinery maintenance in the Midwest.
More than 800,000 b/d of Midwestern refining capacity was offline in October, but planned work started to wrap up at the end of the month.
But one of the region’s largest refineries — BP in Whiting, Indiana — extended its maintenance to mid- to late November. There also were reported issues at Phillips 66 at the Wood River refinery in Roxana, Illinois, recently after the coker and crude sections were shut.
Bakken grades have dropped sharply since the beginning of October when a combination of factors began to weigh on values.
Prices for Bakken at terminals near the oil producing Williston Basin decreased nearly 70% from September to October, according to S&P Global Platts data. Average price differentials in the Williston Basin fell from a $2.75/b discount to the NYMEX light sweet crude calendar-month average in September to a WTI CMA minus $8.45/b in October. So far in November, Bakken Williston has averaged about WTI CMA minus $17/b.
Bakken in the Clearbrook, Minnesota, hub has followed a similar trajectory.
BAKKEN PRODUCTION RISING
In addition to seasonal maintenance, rising output is filling available pipeline space out of the Williston Basin, and that is leading to some in the industry to search for trucks and rail cars to move the crude to desirable markets. But trucks and trains also are in short supply, traders have said, as much of that rail capacity has been “re-positioned” because of new pipelines.
Sending Bakken crude to the Gulf Coast by rail has become a desirable option for some traders, if they can manage to secure railcars. The spread between Bakken in the Williston Basin and in Nederland or Beaumont, Texas has grown to around $26/b.
Bakken oil producers are close to maxing out available pipeline space and rail out of North Dakota, even though on paper the basin roughly has 300,000 b/d of spare takeaway capacity, the state’s pipeline regulator said in an interview last week.
Justin Kringstad, the director of the North Dakota Pipeline Authority, said the Basin has 1.37 million b/d in pipeline capacity, with another 250,000-275,000 b/d of crude leaving by rail. It’s unclear if more railcars are available in the region, but sources have said they have had a hard time securing railspace.
North Dakota recently reached a record 1.29 million b/d in oil production and that is expected to rise. Kringstad said that despite new wellsite requirements for natural gas capture, he expects Williston Basin output to reach 1.34 million sometime next year.
While there seems to be enough pipeline takeaway capacity on paper, in reality it’s a slightly different story, Kringstad said. Several lines are idled or running at very low volumes because it is undesirable to ship on them, such as Enbridge’s BEP line from North Dakota to Cromer, Manitoba, in Canada.
Other options also are not ideal for many, Kringstad said.
The Enbridge mainline that takes crude from North Dakota to Clearbrook, Minnesota, also is not shippers’ top choice because differentials in Clearbrook are hurting due to downward pressure from depressed Canadian grades, and refinery maintenance.
“[DAPL] is the obvious choice,” Kringstad said. “Those routes that get you to Clearbrook are the last resort.” Kringstad said that DAPL is by far the top choice for many shippers to move Bakken crude to the Gulf Coast, where differentials, refinery demand, and the opportunity to export is much stronger.
OTHER CRUDES CONSTRAINED BY PIPES
Extremely depressed values for North American crude near production fields have been a familiar trend this year, with output outpacing pipeline takeaway options as the main reason behind those low differentials.
Prices for WTI Midland crude reached record-low levels of WTI cash minus $17.50/b in August, when production in the Permian Basin continued to outpace available pipeline space. WTI Midland has found some support after it was announced a pipeline expansion project would start up by the end of the year.
But major relief for takeaway issues will not be available until new pipelines are completed next year.
A lack of pipeline takeaway capacity out of Canada, combined with refinery maintenance in the US Midwest, has widened Canadian crude price discounts and has pushed some producers to cut output. The dynamic has depressed values for both Canadian heavy and light grades, which compete with Bakken crude and often initiate price movements.
Syncrude Sweet Premium, the light benchmark, was last assessed at a discount of $32/b to the WTI CMA, the weakest differential on record. Mixed Sweet and condensate differentials at Edmonton also fell to record lows Thursday.
On the heavy side, S&P Global Platts assessed Western Canadian Select crude at an average $27.78/b discount to WTI CMA during Q3, out from an $18.15/b average in Q2. The discount has since widened to average $45.84/b so far in Q4.
S&P Global Platts Analytics expects total Canadian production losses to be limited to roughly 100,000-200,000 b/d by the middle of 2019.
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