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Canada's differential dilemma

Wide discounts for Canadian oil lead to unilateral production cuts

Canadian oil producers are price takers, not price makers. But what to do when your main export is selling for less than half of global prices?

That was exactly the situation in November last year when the differential — or discount — for Western Canadian Select (WCS) widened to an all-time high of $46/bl to West Texas Intermediate (WTI) and prompted a crisis of confidence in the country's oil patch after nominal Canadian prices fell below $11/bl.

Given that fully 99% of exports go to the US, domestic producers are effectively subsidising American refiners to the tune of $2.4/bl per month — both figuratively and literally lining the pockets of US president Donald Trump's economic resurgence.

This in turn has led to what politicians and industry leaders north of the 49th parallel have dubbed a crisis with broader implications for the Canadian economy as a whole. In response, the Alberta government has taken the unprecedented step of imposing mandatory production cuts to the tune of 325,000bl/d or 7pc of the country's crude output.

Speaking in Edmonton, Alberta, state premier Rachel Notley tells Petroleum Economist the production curtailments are a temporary stopgap. They will continue until markets stabilise at a "normal" level that would support additional rail capacity and new processing infrastructure until pipelines are built, which could take years. When asked what that sweet spot is, she demurred.

"We still see a great deal of volatility," she says. "This is a short-term situation, but the long-term economics remain strong… as premier of Alberta I can't put out a number".

Heavy oil economics 101

Differentials are a fact of life for Canadian oil producers. They are a function of oil quality — the Canadian barrel is heavier and naturally sells for less than lighter grades from countries such as the US and Saudi Arabia — as well as basic supply and demand fundamentals predicated on factors such as output levels, markets and transportation costs.

According to Alberta's energy regulator (AER), about 56pc, or 2.8mn bl/d, of the province's oil production is in the form of raw bitumen, which must be thinned with NGLs and even light crude oil to make it saleable to US refineries, adding to an already high-cost barrel.

35mn bl/d — Alberta's storage volumes

The discounts have typically averaged 20pc of WTI after factoring in currency exchange between the US and Canadian dollars. Counterintuitively, this is considered normal and even healthy because it forces homegrown producers to be more cost-efficient and competitive with their US peers.

Differentials also encourage value-added processing and upgrading to close the gap. The wider the discount, the more attractive it is to build new upgrading infrastructure and increase efficiencies with investments in new technology. In theory, the lowest-cost producer always wins.

But differentials of 60pc or more mean that Canadian producers are losing money on every barrel sold. According to Notley, the discounts were costing the Canadian economy more than $80mn/d in direct and indirect costs, a situation that had become unsustainable.

Crisis of confidence

Although Canada is at the mercy of global markets, the differential dilemma in many ways is a crisis of its own making. The status quo has been disrupted by a rising tide of production and a lack of takeaway capacity as the country struggles with its own internal politics to get new pipelines built and open new markets other than the US.

"The severe imbalance between Canada's production and its capacity to export caused Canadian oil price benchmarks to collapse," says Andrew Botterill, a partner with consulting firm Deloitte in Calgary.

Pipelines have become a political hot potato after the federal court of appeals struck down regulatory approvals for the Kinder Morgan TransMountain pipeline to the west coast of British Columbia last autumn. In exasperation, the national government in Ottawa bought the entire project for C$4.5bn ($3.39bn) without any assurances it will ever be built.

The fate of the pipeline is a critical factor in overall heavy oil economics, given that landlocked Alberta is home to nearly all of Canada's oil production. Yet environmentalists and aboriginal groups are vehemently opposed to the prospect of increased oil tanker traffic off the coast, leading to lengthy legal challenges and construction delays, and in turn, shipping constraints.

It all comes as Canadian producers continue to add capacity to a record 4.5mn bl/d, a figure expected to increase another 3pc by 2027, according to the AER. Consequently, the crude has backed up in Alberta, straining storage and creating a glut that has pushed prices down.

The crisis has been particularly acute in Alberta, whose public accounts are drowning in red ink as service workers are fired and international firms such as Shell, Total and Statoil pull out of the oil sands altogether. By some estimates, more than 100,000 oil-patch jobs have disappeared since 2014 as direct foreign investment flees the country.

Desperate times, desperate measures

In response, the Alberta government in November 2018 unilaterally imposed production cuts of 7pc or 325,000bl/d in a bid to stabilise markets. They took effect in the first week of January this year.

Deloitte's Botterill says the Canadian supply glut remains an issue, noting that storage volumes in Alberta rose to approximately 35mn bl in 2018. But the mandatory reductions should mop up the excess volumes, he says, after which the cuts will drop to 95,000bl/d for the rest of 2019.

Deloitte forecasts that Canadian oil prices should strengthen after 2019 because of improved export capacity due to 7,000 additional railway tanker wagons, combined with the expanded capacity of Enbridge's Line 3 pipeline, which transports a variety of Canadian crude oils to the US through Michigan. The extra rail wagons should increase exports by 120,000bl/d by 2020, while the Enbridge pipeline will add approximately 370,000bl/d of export capacity, or an increase of about 9pc, it says.

Although the move to cut production is not without precedent — Alberta last cut production in the 1980s in response to the National Energy Programme — it is unusual for a government to intervene in a sector where it has traditionally taken a hands-off approach. Supply management is common in Canada's agricultural sector to prop up prices for commodities such as milk and eggs, but has never been attempted on such a scale for petroleum.

Initially, the policy worked in spades. After just one week, differentials shrunk to $7/bl, a multi-year low, prompting politicians to proclaim success. The irony is that producers such as Cenovus and US-based Devon Energy had already announced their own production cuts based on pure economics.

Unintended consequences

And while the numbers look good on paper, there have been unintended consequences. The economics of rail — the touted relief valve for the lack of pipelines — are threatened as a result of the policy. Texas-based market consultancy Genscape estimates it costs $15-20/bl to ship oil by rail, which is well out of the money at present differentials.

Alberta's government finds itself in a bind. Though it has managed to prop up markets, it has committed C$350mn ($263.69mn) to buy 7,000 new rail wagons and has put up with another C$3.5bn ($2.64bn) in incentives for new upgrading facilities and associated infrastructure.

Notley further says that the aim of the curtailment policy is to stabilise the differential at a level which would preserve rail economics "until at least two of three (proposed) pipelines are built".

In a move more reminiscent of Opec, Canada appears to be aiming to become a price maker rather than be content to pick scraps off the floor.

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