Western Canadian crude inventories plunge


In early December 2018, the Alberta provincial government took a dramatic step to address the oversupply of oil that was causing the collapse in Canadian crude prices.

Local oil companies were told how much they could produce, starting January 1, making Calgary feel more like an OPEC capital than a freewheeling oil town.

Eight months later, those efforts are bearing fruit.

Alberta crude inventories have fallen sharply since mid-May, hitting an all-time low the week of August 15, according to Ursa measurements going back to 2017.



Source: Ursa

Mandatory production limits were intended to relieve a massive supply glut that had formed as output overwhelmed the capacity of pipelines delivering barrels to US refiners and Gulf Coast ports for export.

Another factor has been the greater amount of crude loaded onto trains and shipped out of the province.



Source: National Energy Board

You might be wondering why crude-by-rail loadings fell sharply in January even though the supply glut had not dissipated. And why would they rise sharply months later?

The economics of crude-by-rail depend on the crude price differential in Canada versus the United States. More specifically, the relevant locations are Hardisty (Alberta) and Cushing (Oklahoma), a pair of major delivery points.

Cushing must fetch a large enough premium over Hardisty to cover the transportation costs.

The problem in early 2019, as we discussed in an earlier blog, was that news of the production curtailment impacted prices to such an extent it made crude-by-rail uneconomic.

The discount for benchmark Western Canadian Select (i.e. Hardisty) versus NYMEX WTI crude (i.e. Cushing) fell to as little as $8 per barrel in mid-January, compared with $52/b in October 2018.

Higher prices made Canadian oil producers happy, but had the unintended consequence of lowering crude-by-rail loadings.

So what happened? Alberta crude inventories didn’t fall. They actually rose from April to mid-May, as you can see in the first chart above.

All the while, the production limits were still in place, though becoming less stringent.

Monthly production was limited to 3.56 million barrels per day (bpd) in January, equivalent to an 8.7% (325,000 bpd) reduction.

In September, the production limit is set at 3.76 million bpd.

As you might guess, the WCS discount adjusted — widening to more than $10/b — making crude-by-rail profitable, resulting in the uptick in loadings shown above.


Source: NYMEX via MarketView

However, the back-and-forth continues, with the latest indicators underscoring how Alberta’s oil market has tightened, which in turn has strengthened WCS relative to WTI.

Earlier this week, the WCS discount was back below $11/b, raising the question (yet again) about whether rail loadings will fall in response.

Of course, what’s happening south of the US-Canada border is equally important to this topic. You cannot discuss supply without demand.

The thirst for Canadian crude by US refiners has grown in 2019 after Washington imposed sanctions on Venezuela’s state-owned oil company.

That decision drove US imports of Venezuelan crude to zero.



Source: US Energy Information Administration

A lot of US refineries, especially on the Gulf Coast, are configured to run on a slate of heavy, source crude typical of Venezuelan supply.

Where else can you buy similar crude grades? Canada

Other factors have added to the backdrop of tight (heavy sour) supply. These include US sanctions against Iran and OPEC voluntary cuts.

This shift has impacted prices, boosting the relative value of Dubai (the heavy sour benchmark) to Brent (the light sweet benchmark).

You can see in the graph below how Brent’s premium to Dubai diminished and briefly flipped to a discount earlier this year.



Source: MarketView

This environment is wonderful for Canadian producers, as long as they can seize the opportunity.

But remember congested pipelines were the problem that the Alberta government was trying to alleviate in the first place when it imposed production curtailments.

Some Canadian midstream companies (e.g. TC Energy, Enbridge) are using chemicals to increase flows on existing pipelines.

But that’s small stuff compared with the increased capacity that comes with new pipelines.

Canada’s oil industry has lobbied hard to get more pipeline capacity built, but run into stiff opposition leading to delays.

One plan that was approved recently to expand the Trans Mountain Pipeline won’t be finished until 2022 and could still run into roadblocks.

What do you think will happen next? Has Alberta done enough to resolve its chronic oversupply? Or it is just a matter of time before the problem resurfaces?




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