Future of Canadian crude pricing at stake in November ruling on Enbridge pipeline proposal

HIGHLIGHTS

Startup of Line 3 replacement largely ends pipeline bottleneck for now

Enbridge sees higher Canadian prices and volumes, pipeline expansions

Opposition fears smaller producers being squeezed out


Author
Jordan Blum Pat Harrington
Editor
Jeff Mower
Commodity
Natural Gas, Oil, Shipping

The future of Canadian crude pricing, volumes and the finances of several smaller producers could hang in the balance of a November regulatory decision on the contracting of Enbridge's Mainline pipeline network that may be upended for the first time in 70 years.

The Canada Energy Regulator is set to decide by the end of November whether it will approve Enbridge's years-long fight to change the crude and NGL pipeline network's monthly nomination system as a "common carrier" to long-term committed contracts with just 10% of capacity set aside for spot shipping.

Enbridge contends the move is necessary for volume certainty and less month-to-month volatility, as well as stronger Canadian crude pricing. Smaller Canadian producers fear higher tolls, or being squeezed out entirely with their barrels stranded in Alberta and sold at deeper discounts.

With the capacity to ship 3.2 million b/d across 8,600 miles, Mainline is by far Canada's largest crude transporter and exporter, moving supplies from the Alberta oil sands to the Ontario and US Midwest refining markets -- and farther to the Cushing, Oklahoma storage and pricing hub, and to the US Gulf Coast through additional pipelines.

The current Mainline tolling system relies on a monthly nomination system that utilizes apportionment when demand exceeds capacity, which has been the case for years with a shortage of Canadian pipelines into the US. Under 50% apportionment, for instance, a producer wanting to move 1,000 barrels would only be allowed to ship 500 barrels.

Enbridge instead wants to shift to the more modern system of longer-term, take-or-pay contracts with minimum volume commitments -- for up to 20 years -- similar to most North American pipelines. The change is preferred by US refiners and some larger producers.

The last 10-year tolling agreement expired in June and Enbridge is eager to implement the changes in 2022. The Canada Energy Regulator can either outright approve or reject Enbridge's requests, or settle on some sort of compromise that sets aside more than 10% of the capacity for spot shipments and lower the base toll, said Parker Fawcett, North America supply analyst with Platts Analytics.

"The CER decision appears to be on a knife's edge, with the regulator having to generally side with Enbridge, integrated producers and US refiners, or with Canadian producers," Fawcett said, giving Enbridge's chance of success or compromise slightly above 50%. "Enbridge's dominant market share means there are little competitive alternatives."

The regulatory decision will follow the Oct. 1 startup of Enbridge's Line 3 replacement project, increasing capacity on a key Mainline crude artery from 390,000 b/d to 760,000 b/d, and essentially ending the pipeline bottleneck into the US now that Canadian production has largely recovered from the ongoing coronavirus pandemic.

With many months requiring more than 50% apportionment of heavy crude in the past, Enbridge said Oct. 19 that apportionment levels on lines carrying heavy crude fell to 12% for November flowing barrels. However, Canada's competing Trans Mountain Pipeline expansion project, which is tentatively slated for an end-2022 completion, already has long-term contracts in place that could give it advantages over Mainline's current common carrier status.

Opposing views

László Varsányi, Enbridge's vice president of tolling strategy, said the plan is for Canadian crude volumes and Western Canadian Select pricing to both rise with the new contracting certainty. Basing the Canadian swing barrels on pipeline economics and not the more expensive crude-by-rail exports should tighten differentials and lead to more production and Mainline expansions, he said.

"That's the nirvana," Varsányi said in an interview. "We can see this basin start to grow again."

"You're talking about a $5/b difference in the price," he added.

Platts assessed WCS at Hardisty at WTI CMA minus $15.85/b Oct. 27, and at minus $7.35/b at Nederland, Texas. That $8.50/b spread is within the range of pipeline economics for committed shippers.

With the additional capacity of the Enbridge Line 3 replacement project now online, Platts Analytics sees the WCS price remaining in the pipeline economics range and not having to weaken to accommodate the extra cost of rail shipments.

Platt's Analytics projects 1 million b/d of Canadian production growth over the next decade, meaning that more pipeline expansions eventually will be needed even after Trans Mountain in the years ahead.

Varsányi said long-term contracting should lead to optimization expansions of more than 200,000 b/d on Mainline -- through additional pump stations and more drag-reducing agents -- and of other pipelines that carry crude to the USGC, especially the Flanagan South and Seaway pipeline systems. He said Enbridge also remains committed to its partnership with Enterprise Products Partners to build the deepwater Sea Port Oil Terminal, called SPOT, offshore of the Houston Ship Channel, triggering more demand for Canadian and Bakken Shale barrels for overseas exports.

"It really comes down to completely eliminating the business uncertainty as much as possible," Varsányi said of the planned contracting changes. "We've been suffering through almost 50% apportionment on a month-to-month basis."

While the lower 12% apportionment now is great, he said, it may be a "low-water mark" as volumes and drilling activity rise, at least until the Trans Mountain expansion is completed.

The goal is to win regulatory approval and then launch open seasons for new contracts, he said. "We do remain confident that mid-2022 effective date for the contract is attainable."

However, a lot of opposition remains, especially from the Explorers and Producers Association of Canada, called EPAC. The lobbying group's president, Tristan Goodman, said it is critical to keep Mainline as a common carrier open to all Canadian producers, especially now that more pipeline capacity is available on the network. The long-term contracts favor the US refiners and squeeze out the junior Canadian producers, he said.

"Mainline allows easy access to small, medium and large producers. You don't want to see one group of large producers lock up the capacity," Goodman said. "We need to allow the smaller and more junior producers to survive and thrive."

Platts Analytics projects a strong possibility for a regulatory compromise, such as requiring Enbridge to set aside 15% or 20% capacity for spot shipping.

The energy research and investment banking firm Tudor, Pickering, Holt & Co. has a base case for a 20% compromise on uncommitted capacity, as opposed to Enbridge's desire for just 10%.

"The regulator is keenly focused on the public interest," said Canadian midstream analyst Matthew Taylor, of TPH. "Our expectation is Enbridge will be successful with more concessions, including allowing more spot capacity. The other concession is making it more competitive and cost-effective for its customers."

Long history

Despite the new Mainline capacity, Enbridge's long push to move away from a monthly nomination process to committed volumes began as way to address the inefficiencies that resulted from shippers producing too much oil without enough pipelines.

In 2017, it became clear that new production from oil sands projects, such as Canadian Natural Resources' Horizon Phase 3 and Suncor's Fort Hills, would push Western Canadian production above the capacity for both rail and pipelines.

When crude inventories in Alberta rose dramatically, the value of Canadian crude plummeted. The differential for WCS at Hardisty, Alberta, reached an all-time low of WTI CMA minus $51.55/b on Oct. 11, 2018. Alberta officials warned low oil prices were threatening the province's financial stability, which ultimately resulted in a production cap by the end of 2018.

With pipelines running full and turning away crude, some buyers -- uncertain about how much crude they would receive -- began bidding for more crude than they needed. Some shippers, in turn, nominated more crude than they actually had. That led Enbridge in June 2018 to switch the monthly nomination process for one that gave priority to shippers based on their historical shipping volume. The confusion caused the WCS differential to widen more than $6/b in a single day, forcing Enbridge to cancel the plan.

The dramatic price swings around Enbridge's 2018 attempt to change its nomination process led companies, such as BP, to formally complain to the Canadian regulator. That essentially started the long process that is expected to end by late November, when the regulator makes a final decision.