Alberta’s Crude Curtailment Program Could Be Prolonged Affair

The Notley government’s crude oil curtailment program, backed by the opposition United Conservative Party, to reduce a glut of oil in storage in Western Canada and bolster catastrophic regional prices, was to run from January to December of this year. The program’s sunset clause was predicated on Enbridge Inc.’s Line 3 Replacement project coming online in late 2019, adding 370,000 bbls/d of incremental pipeline capacity out of the region.

On May 22, the day of the Throne Speech, Alberta’s new Energy Minister Sonya Savage said “we are looking at an orderly way out of curtailment.” In a speech to the Global Petroleum Show on June 11, Premier Jason Kenney said his government might have to extend the program into 2020, given additional delays to Line 3 Replacement.

Unfortunately, if the Kenney government is to avoid another collapse in western Canadian crude prices the province’s curtailment program may have to be extend not just into 2020, but beyond as well.

Determining when we have enough egress to move our oil — crude and NGLs — to market is a complicated affair, even ignoring seasonal factors such as refinery turnarounds and the severity of a western Canadian winter and unpredictable factors including pipeline outages due to accident. The key factors are: regional oil production; regional oil consumption; oil pipeline capacity; and the ability of railways to move the remainder to market.

As a result, it is not surprising it has taken the Alberta government several months to calibrate its crude curtailment program to both improve regional crude prices and bring down inventory levels. The curtailment order started at 325,000 bbls/d in January and was gradually ratcheted down to 175,000 bbls/d for June and July.

In the interim, the discount for Western Canadian Select (WCS) to West Texas Intermediate (WTI) fell below US$10/bbl, making rail transport to U.S. Gulf Coast refiners uneconomic and crude-by-rail volumes plunged. Western Canadian oil inventories hit a record high of 37.1 million bbls at the end of April, as reported by Reuters based on Genscape data.

The WTI-WCS differential has since increased to around US$15/bbl, reviving crude-by-rail volumes and bringing down regional oil inventories to 34 million bbls at the end of May. In retrospect, and with the benefit of hindsight, it appears Western Canada was short about 175,000 bbls/d of egress at the end of last year.

The Canadian Association of Petroleum Producers (CAPP), in its recently released crude oil market report, is forecasting western Canadian oil supply — including foreign sourced diluent to allow extra-heavy crude to meet pipeline specifications — to gradually increase from 4.66 million bbls/d in 2018 to 5.23 million bbls/d in 2022. The latter is the earliest possible year either TC Energy’s 830,000-bbl/d Keystone XL (KXL) or the 590,000-bbl/d Trans Mountain Expansion (TMX) could come into service, negating the need for crude-by-rail to clear the market.

Using 2018 as a baseline, including the estimated 175,000-bbl/d egress deficit at the end of the year, and CAPP’s western Canadian oil forecast and estimate for oil pipeline capacity from the region — 3.39 million bbls/d — an average of 380,000 bbls/d would have to be shipped to U.S. markets by railway this year and 580,000 bbls/d next year. This number drops to a mere 300,000 bbls/d in 2021, assuming Line 3 Replacement comes online by the beginning of that year.

The 380,000-bbl/d crude-by-rail figure for this year is high, based on volumes to date, suggesting a continuing need for Alberta’s crude curtailment program despite efforts by Canadian National Railway (CNR) and Canadian Pacific Railway (CPR) to ramp up locomotives, crews and tanker cars and other companies adding the latter as well. The 580,000-bbl/d figure for 2020 appears more doable, if not for one potential factor, major U.S. railways refusing to transport DOT-117R tanker cars.

In July 2017, it was widely reported that BNSF, Warren Buffet’s Berkshire Hathaway owned-railway and largest freight carrier in North America, was planning to ban the use of the retrofitted DOT-117R — TC-117R in Canada — oil tank cars on their tracks following a number of derailments, punctures and fires. U.S. railways bear the cost of derailments and environmental mitigation for spills, including associated legal rewards.

BNSF has yet to do so, instead charging a substantially lower fee for transporting DOT-117 tanker cars — original builds to the most stringent safety standards — but it has also been reported that Union Pacific, the other major railway west of the Mississippi River, would follow BNSF’s lead if it goes ahead with a ban.

At the same time, Line 3 Replacement coming online by the beginning of 2021 is far from a slam dunk — a term I previously used about the end 2019 in-service date. This Enbridge project was pushed back a good chunk of a year by a delay in permits from the State of Minnesota. On June 3, the Minnesota Court of Appeals ordered further actions to consider the potential impact of an oil spill into the Lake Superior watershed.

Alexandra Klass, a University of Minnesota law professor, has said it will take at least six months for Enbridge to comply with this new condition. Without a valid environment statement from the Minnesota Public Utilities Commission, Enbridge’s certificate of need and route permit for Line 3 Replacement in the state is void. If Line 3 Replacement does not come online in 2021, the railways would have to move 670,000 bbls/d of oil to U.S. markets that year barring continuing crude curtailment by the Alberta government.

Finally, and totally out of left field — and a classic case of cutting off one’s nose to spite the face — in March, Michigan Governor Gretchen Whitmer told Enbridge that she wants the tunnel to house Line 5 under the Straits of Mackinac connecting Lake Michigan to Lake Huron completed by 2021 instead of 2024, as agreed by former Governor Rick Snyder. Whitmer has repeatedly threatened to shut down Line 5 if Enbridge does not provide an accelerated schedule, as she fears anchors from boats could rupture the 66-year-old underwater section of Line 5.

On June 6, Enbridge President and CEO Al Monaco announced his company would be filing suit in the Michigan Court of Claims “to establish the constitutional validity and enforceability of previous agreements,” as a two-year timeline is too short to construct the tunnel. On May 30, Michigan Attorney General Dana Nessel said she may go to court by the end of this month to stop the flow of oil through the underwater section of Line 5 if Enbridge fails to comply with the governor’s demand.

Enbridge Line 5 carries around 540,000 bbls/d of light crude and NGLs, mainly from Western Canada, and in conjunction with other pipelines feeds a total of eight refineries in Central Canada, U.S. Midwest and U.S. Northeast, including Marathon Petroleum’s refinery in Detroit.

To conclude, Alberta’s crude oil curtailment issue may be with us much longer than originally anticipated given the wide range of impediments facing new and old pipeline capacity and possibly crude-by-rail capacity as well, unless capital spending and western Canadian oil supply are significantly weaker than presently forecast by CAPP.