Enbridge’s mainline pipeline system. Source; Enbridge.

We were surprised to see Enbridge has this much additional expansion potential on its mainline to PADD II (Midwest) and it is even earlier than expected. – Dan Tsubouchi

Canadian oil producers selling on the spot market are being hammered by record high discounts to West Texas Intermediate, costing companies and governments billions of dollars and slowing Alberta’s economic recovery. But while there’s no immediate fix at hand, help is on the horizon. Pipeline giant Enbridge has as much as 500,000 b/d of system upgrades that require no or little regulator approval, cost a fraction of a new project, and can be completed as early as next year. Is this the market access relief Alberta has been waiting for?

Al Monaco, CEO, Enbridge.

Enbridge has been talking to investors about these “other projects” since at least 2017, as a review of past investor presentations reveals.

The amount of new Enbridge capacity available varies between 375,000 b/d to as high as 500,000 b/d depending upon the presentation. By comparison, the Trans Mountain Expansion project that would stretch from the Edmonton area to Burnaby, BC would cost over $7 billion and transport 590,000 b/d.

Why hasn’t Enbridge moved more quickly on these projects?

That was the question asked by an analyst on Enbridge’s recent earnings call, who noted the apparent urgency created by the historic differentials, which have reached as high as CDN$65/b in recent months.

“We’re not seeing the current situation having much impact on those discussions. The existing CTS [competitive tolling settlement] runs through mid 2021 and I think there’s a lot of expectation in the marketplace that by that time Line 3 [Enbridge’s 390,000 upgrade project] is going to be in service. We know at least one of the competing pipelines is targeting to be in service by that time,” an Enbridge executive replied.

“So, I think the producers and the shippers on our system are sensing that by the time that this new agreement goes into service that there’s going to be some relief on that front.”

Dan Tsubouchi, chief market strategist, Stream Asset Financial Management.

Dan Tsubouchi, chief market strategist for Calgary-based Stream Financial Asset Management, offered another explanation in a September blog post: “We suspect Enbridge’s ‘Other’ mainline capacity addition projects have been forgotten for a long time because these are long identified projects that were originally sitting behind Enbridge Line 3, Keystone XL and Trans Mountain Expansion.”

According to an Enbridge spokesperson, the pipeline giant is considering four or five optimization projects.

“Some of the ways we’ve increased capacity is by system optimization through use of drag reducing agents and scheduling improvements. We are also looking at creating space by redirecting downstream mainline injections to open up that capacity for WCSB [Western Canadian Sedimentary Basin] shippers,” the spokesperson emailed in response to Energi News questions.

The company is considering using 100,000 b/d of  “idle” Bakken Expansion Program capacity, which carries light sweet crude from the North Dakota shale basin. The current capacity is 145,000 b/d, but a 2011 Enbridge document (the line came into service in 2013) says that could be increased to 325,000 b/d.

Reversing Line 13 (also known as Southern Lights), a 180,000 b/d pipeline that delivers diluent from Illinois to Alberta, would add another 100,000 b/d according to Enbridge’s investor presentation. According to the earnings call, management is actively considering this project: “Southern Lights, I think that was the first part of your question, we’re in discussions already there with the customers that currently move product in the other direction. It is a good opportunity and this is the nature of the Beast, is looking at options to reverse and incremental capacity in. So, we’re all over options like that.”

Each of the projects will increase shipping space on the mainline to PADD II, the US Energy Information Administration’s term for the American Midwest market.

“These capacity options require minimal construction or regulatory work, and they’re highly capital efficient for us and our customers,” said the Enbridge spokesperson.

Enbridge estimates that its “other projects” will cost between $2 billion and $4 billion.

“If we will look at the fundamentals, we certainly think that there is an opportunity for that to happen. We are stepping up our conversations both with our customers on that [main] line and potential crude oil customers to try to sort through just whether in fact there’s a commercial solution here that the shippers are interested in,” an Enbridge executive said during the earnings call.

“Certainly, to your comment, there’s interest and we are pursuing that.”

With heavy crude oil demand from the US Gulf Coast (PADD III) growing because of ever-dwindling supply from Venezuela, Mexico, and Iran, Canadian producers are increasingly interested in selling to Texas and Louisiana refineries where they can get the full WCS price – and sometimes even a premium.

“As we’ve had more interest recently coming from shippers about the potential to do some of these staged expansions on the mainland, we have to look at the market access opportunities and many of our shippers are interested in potentially trying to get more barrels to the Gulf Coast,” an Enbridge executive said on the earnings call, explaining that options include expansion of Flanagan South, a 585,000 b/d line stretching 590 miles from Pontiac, Ill. to Cushing in Oklahoma, and reversal of another pipeline.

While industry believes only 375,000 b/d of “oil egress” will come online by 2020, Tsubouchi and his team believes Enbridge’s projects could raise that total to 700,000 b/d, which would be a significant boost for beleagured Alberta producers, especially juniors and midcaps without “take or pay” pipeline commitments that force them to sell in Alberta to American refiners at the inflated WSC/WTI differential.

Industry and investors believe the only market egrees relief in sight is Line 3, which won’t come on line until 2020 and will provide only short-lived relief for beleagured producers.

“Most seem to believe TransCanada will be able get its Keystone XL 830,000 b/d pipeline over the goal line, but with views generally in 2022 or 2023.  There are mixed views on the 590,000 b/d Trans Mountain expansion post the recent court ruling,” Tsubouchi wrote.

“Some believe it will never get done, but, those that do, seem to be looking at first timing sometime after 2023.   The reason why markets have been cool at best for the Canadian oil egress picture is that Enbridge Line 3 is viewed to only provide temporary relief.”

News of Enbridge’s potential capacity additions will be welcome – and unexpected – news for the Alberta industry.

“We were surprised to see Enbridge has this much additional expansion potential on its mainline to PADD II (Midwest) and it is even earlier than expected,” Tsubouchi wrote.

“And by adding these ‘Other’ projects, there should be enough pipeline capacity to support western Canada oil growth to 2025.  This is why we see these as a potential game changer and why we had such a positive Canadian oil outlook.”