On December 2, Alberta Premier Rachel Notley announced the province will mandate production cuts beginning January 1, 2019, to alleviate the glut of crude in Western Canada that caused severely depressed differentials and record-high inventories. The cuts will total 325,000 barrels per day (bpd) and be reassessed on a monthly basis based on how effectively they are able to diminish the storage glut.
Currently, we estimate the 325,000 bpd cut for January to be split between bitumen (177,000 bpd), Synthetic Crude oil (110,000 bpd), and conventional oil (38,000 bpd), according to our Canadian Crude Oil forecast. Even with the cuts, we estimate that production in January will still exceed pipe capacity by ~100,000 bpd, which can easily be covered by current rail capacity. Our weekly Canadian Crude Oil Storage Report will stay ahead of the impacts, yielding unrivaled insight into inventory changes at Western Canadian storage hubs during this period.
Rail is paramount to watch in 2019 as it will still be the mode of transport to clear the market. The Alberta Energy Regulator (AER) needs to watch rail very closely to get a good view on what mandated production cuts will be needed month-to-month to reach their goal of approximately 19mn bbls in storage for balancing the market. Any rail or pipeline operational disruption could have an outsized impact on their inventory target in a given month. We monitor at least 70 percent of Canadian crude-by-rail volumes and 88 percent of Canada-to-U.S. pipeline capacity.
How Bad is the Canadian Inventory Glut?
Inventories at monitored storage locations in Western Canada decreased 1.956mn bbls to 33.05mn bbls between weeks ending November 16 and November 30, or an average of 978,000 bbls per week. Stocks remained within 4mn bbls of the record-high level set in mid-September. Storage capacity utilization for week ending November 30 averaged 55 percent, compared to the record-high utilization of 67 percent set in May 2014, according to our Canadian Crude Oil Storage Report. Storage operators, particularly in Edmonton, AB, and Hardisty, AB, store a wide variety of crude types in grade-designated tanks. The non-interchangeable nature of the tanks results in a lower overall utilization.
Inversely, terminal operators typically do not drain inventories below a certain level for operational purposes, which means the entire 33mn bbls in storage as of week ending November 30 would not need to be shipped downstream to alleviate the glut. The lowest utilization rate on record of 30 percent was set in July 2017, when production outages hindered supply in the region. Utilization also slipped to around 35 percent in April 2012, June 2013, and July 2016. Inventories last week were roughly 14.8mn bbls higher than the record-low utilization rate. Based on operational storage capacity from week ending November 30, a 30.3 percent utilization rate would equate to 18.3mn bbls in storage.
Full Pipes and Frozen Power Lines
Utilization on our monitored Canada-to-U.S. pipelines averaged 97 percent in 2018 through the end of November, leaving virtually no available space for growth, according to our Canadian Pipeline Service. The lack of available takeaway pipeline capacity, along with steady production growth, led to record-high inventory levels and crude-by-rail loadings.
December apportionment on Enbridge's Line 4/67 heavy oil pipeline was announced at 46 percent, down one percentage point from November, which was the most in the prior three months. Line 2/3 light oil pipeline was limited by 43 percent in December, from 46 percent the month before. November apportionment was the highest on the year.
Constrained pipeline capacity leaves Canadian markets especially susceptible to the impacts of unplanned outages. On December 4, Genscape reported outages along the two largest trunk lines out of Western Canada: Enbridge’s 2.665mn bpd Edmonton-to-U.S. Mainline system and TransCanada’s 590,000 bpd Hardisty-to-Steele City, NE, Keystone pipeline. The outages occurred amid widespread power outages that were reported by SaskPower, a Saskatchewan utility company, on December 4.
Both pipelines resumed normal operations during the early morning of December 5, which was enough time to cause a substantial disruption. The outages prohibited at least 1.8mn bbls from entering the U.S., which equals at least 5.5 days of Alberta's mandated production cuts. The incident serves as a sobering reminder that any unexpected disruption, especially along pipelines out of Western Canada, can significantly impede the progress of Alberta’s plan to decongest the region.
The differential for Western Canadian Select (WCS) was $11.25/bbl higher on December 3 from the week before at WTI CMA minus $21.25/bbl, the narrowest since July 16, according to our data. The spread narrowed considerably amid the news of upcoming production cuts. However, the WCS spread then widened to WTI CMA minus $24.50/bbl on December 4 following the Saskatchewan power outages and subsequent pipeline disruptions.
When All Else Fails, Ship By Rail
In addition to the production cuts, the Alberta government announced on November 28 release that it will purchase rail cars in order to haul crude out of the province to help reduce the supply glut and get more value for its production amid a shortage of pipeline takeaway capacity.
Alberta's stated goal is to "create enough new rail capacity to move 120,000 barrels a day out of the province to markets where our oil can earn the best value possible for three years, starting late 2019," the release said. The Alberta Petroleum Marketing Commission is "negotiating with rail manufacturers and suppliers to make the best possible investment," for railcars on a minimum three-year contract, it said.
Crude-by-rail loadings in Western Canada in the week ending November 30 inched up 2,000 bpd from the week prior, to put the weekly average at 264,000 bpd. Last week marked the eighth straight week the weekly average was over 250,000 bpd after not crossing that threshold prior to then, according to Genscape data which began February 2014. The November monthly loading average was 264,000 bpd, a month after posting a record high of 274,000 bpd, according to our PetroRail Report.
The magnitude of increasing rail volumes has been a crucial point of focus in determining the severity of the Canadian bottleneck. Rail shipments will continue playing a key role, but the production cuts could flatten growth in crude-by-rail volumes from the region, as pipeline apportionment will likely ease.
Alberta’s decision to mandate production cuts in 2019 has been an unprecedented, and seemingly polarizing, event in Western Canada. Although the justification for the decision is being hotly debated, the impact is fairly straightforward: supply cuts will help alleviate the pervasive glut and associated price discounts that plagued Canadian markets throughout the past year.
As the new mandates commence, it will be imperative for the Albertan government and market participants to constantly assess the effectiveness of cuts. The rate of storage draws will paint a picture of how quickly supply and demand are reaching a balance. Meanwhile, the magnitude of crude-by-rail volumes will illuminate variability in takeaway flows from the region. Pipelines operated near full capacity for the entirety of 2018 through November, which seemingly indicates they are a constant variable. However, the recent outages along Mainline and Keystone highlight the drastic impact unplanned disruptions can have on the supply chain. As the “new norm” begins to pan out in Western Canada, vigilant monitoring for any fundamental changes is paramount.
Genscape monitors crude inventories at key hubs in Western Canada, including the storage hubs in Edmonton and Hardisty, on a weekly basis, click here to learn more about our Canada Crude Oil Storage Report. Additionally, we report on near-real-time pipeline flows for 88 percent of Canada-to-U.S. pipeline capacity, as well as daily crude-by-rail shipments for more than 70 percent of loading volumes in Canada. Find out more about our Canadian Pipeline Service and PetroRail Report. We also forecast production in Western Canada using bottom-up analysis on a project level for the oil sands and a well level conventional oil production outlook, request a trial for our Canada Crude Oil Production Forecast.