Regulation and government action again threaten Canadian oil markets. This time, it’s a trickle-north effect from U.S. court decisions on a fully complete pipeline.
*** Update April 9, 2021 — This article was written ahead of the U.S. court date last week, April 9, 2021. The hearing was deferred by 10 days, so the potential effects of DAPL on Canadian diffs remain. Look for updates here and at https://aegis-hedging.com/insights/ after April 19, 2021 ***
Once again, we’re talking about regulatory hurdles facing egress issues for Canadian barrels. The DAPL status conference that was delayed in February 2021 is due to finally occur at the end of this week. The DAPL pipeline, which moves Bakken light sweet oil out of North Dakota and into Patoka, (where it can either be put into storage or continue to Nederland on ETCOP) plays an important role in the keeping the Canadian market as uncongested. While the DAPL pipeline is a US problem, it inherently affects Canadian barrels as removing this pipeline capacity from the market will push barrels onto the Enbridge owned Bakken Expansion Pipeline and ultimately onto the Enbridge Mainline system.
A four-year old, in-service Bakken pipeline may be shut down
The pipeline suffered a setback in August 2020 when the US Court of Appeals upheld a lower court ruling (from July 2020) that vacated the Corps of Engineers Lake Oahe easement. A January US Court of Appeals affirmed this ruling and directed the US Corps of Engineers to complete its Environmental Impact Statement (EIS) but reversed the parts of the ruling requiring the pipeline to be shut down during the process. A second motion filed by the Standing Rock Tribe for an injunction to shut down DAPL during the EIS is the topic of the status conference to occur on April 9. The Standing Rock Tribe is arguing that the pipeline should be shut down and not restarted during the EIS process, given that the easement for DAPL’s crossing under Lake Oahe has been vacated.
Not enough spare pipeline capacity exists to serve all barrels
A shutdown of the pipeline will force producers and shippers to find alternative means of egress for the DAPL barrels. The pipeline has been running at a little over 80% capacity meaning that the barrels looking for alternative means of egress is in the neighborhood of 490-500 kbpd, according to Genscape/Wood Mackenzie. Crude production in the Bakken has yet to fully recover from the COVID-19 downturn and faced additional headwinds in January and February’s arctic blast.
Rail is the only viable transportation alternative if production does not decrease
Assuming production levels remain around 1.2 Mbpd, we estimate the total call on rail will be approximately 380 kbpd. Crude by rail out of North Dakota has been averaging around 200 kpbd – even in times when pipeline capacity isn’t scarce, producers and shippers regularly use crude by rail as a steady takeaway option to refineries in PADD 5 and (to a lesser extent) PADD 1. Some fancy math leads to the assumption that, at current production, about 180 kbpd of additional rail will be required to clear the barrels.
Congestion would transfer to the Enbridge system
The concern for Canadian producers is the volume of crude that finds its way onto the Enbridge Mainline at Cromer through the Bakken Expansion Pipeline (BPEP), owned by Enbridge. Recent economics have failed to incentivize moving any barrels on the BPEP line, but there are contracts still in place. Enbridge is also part owner of DAPL (a minority interest) and will be looking to recoup what it loses on DAPL through moving barrels on BPEP. Even if it doesn’t completely fill the line, it won’t take much to move the needle in terms of creating congestion on the mainline, and anything that doesn’t go north to Cromer will add to what has to be moved by rail.
What is the effect on price and price risk? Timing matters.
The timing of any pipeline closure will also matter. Any widening of Canadian crude differentials is mitigated by upgrader turnarounds near term, but as these plants come back online, expect to see differentials widen. AER reported that Alberta crude production continued to trend down in February to 3.57 Mbpd after reaching a peak of 3.8 Mbpd in December, the difference stemming from a decrease in mined bitumen. Overall production is expected to decline further during the seasonal turnaround before rebounding in the June/July time frame. With no incremental egress available until L3R comes on in 4Q21, we expect to see diffs widen through the summer.
Can storage help mitigate? Less now.
Not to throw more shade on the looming congestion in Alberta, but we have to pay attention to storage levels which are currently at an 11-month high. Inventories can provide a cushion for lost supply due to the upgrader maintenance, but PADD 2 refineries will also undergo seasonal maintenance decreasing demand for Canadian barrels.
Source: Genscape. The chart shows Alberta crude oil storage has been filling.
Watch the DAPL results carefully in the U.S. If the threat of shutdown remains, there would be regional upsets, starting with Bakken oil discounts, and ending with more congestion in Canada and the pipelines that carry Canadian oil to market.
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