Economist Andrew Leach and Kirsten Smith pop the notion of a “bitumen bubble”
Even with new pipeline infrastructure, geographic price discounts for Albertan crude will remain
When Premier Alison Redford declared, in January of 2013, that Alberta was enduring the effects of a so-called “bitumen bubble,” she brought the concept of the heavy-light differential into the living rooms of Albertans. However, to focus only on the discount applied to bitumen ignores changes in the North American oil market and the impact of these changes on future crude prices here in the province.
The discount on Alberta oil can be broken down into two constituent parts – geographic and quality discounts. The recent discount of Alberta heavy oil to world light oil prices, the so-called bitumen bubble, implicitly includes both. While Albertans seem to be more worried about the quality component – the heavy-light differential – the changing North American oil markets have significant and long-term implications for the geographic discount. This should worry Albertans more than the quality differential, because it will affect all the oil we produce and it won’t be solved by creating better market access through pipelines.
Up until the middle of the last decade, the pattern of oil movements in North America was advantageous to Alberta. The oil demand centers in the U.S. Midwest were using oil delivered either from the Gulf Coast or from Canada. As a result, the price of oil in the Midwest was at a premium to world prices, reflecting the costs of shipping oil into the mid-continent. Canadian oil shipped into these markets still had to cover shipping costs, but since the oil was able to command a premium at its destination, Edmonton Par prices were roughly equivalent to West Texas Intermediate prices, with WTI prices themselves being at a premium to tidewater light oil benchmarks like Brent or Louisiana Light Sweet. Despite being in the middle of the continent, Alberta oil traded at a premium to world prices as a result of being close to under-supplied demand centers.
Since 2010, thanks to increasing levels of U.S. domestic production, in particular from the Bakken, combined with a 40 per cent increase in the amount of Canadian oil moving into the U.S. Midwest and flat local refinery throughput, the mid-continent is currently swimming in a glut of oil. Markets north of the oil trading hub at Cushing, Oklahoma, that had been premium markets were suddenly discounted relative to world prices. This excess supply not only led to the much-publicized blowout in the differential between WTI and Brent, but also to an Edmonton Par discount because Alberta producers had limited access to other markets.
Chances are if you’ve read something discussing oil prices lately, then you’ve heard about the need for more pipelines. And more pipelines will, indeed, allow Alberta crude to be sold in markets with higher prices than the currently discounted WTI price, but the change in oil flows will have a variety of implications for Alberta oil producers.
The two principal impacts are likely to be a sustained geographic discount for Edmonton oil prices relative to world prices and a significant premium for oil producers with firm shipping commitments on shorter routes to tidewater. These are both exacerbated by limits on new pipeline capacity, but not fully alleviated.
To understand the first, consider the distance likely to be traveled by the marginal barrel of oil, which sets the price. Suppose for argument’s sake that the Energy East, Keystone XL and Northern Gateway pipelines to ship oil east, south and west are approved and allow most oil produced in Western Canada to be moved by pipeline. In such a scenario, barrels moving east to Saint John, or south to the U.S. Gulf Coast, would likely see shipping charges of up to $8 per barrel. Some of these barrels might be able to command a slight premium to Brent, if there is sufficient demand on the U.S. east coast, or may trade at a slight discount to Brent if exported barrels must be shipped further afield. The price at Edmonton would reflect this port price net of the pipeline toll, so it follows that the value of Alberta oil will be discounted relative to world prices by at least the amounts of these tolls – at least $8 per barrel.
Now, suppose some pipelines are not built – in such a case, the marginal barrel would be moving by rail, again likely to the U.S. Gulf or East Coast. If the transportation cost on these barrels is $12 to $15 per barrel, a conservative estimate, the price of oil at Edmonton would come to reflect this and you’d see a discount of $12 to $15 per barrel to Brent for light oil.
The second aspect of this changing North American oil market is the premium that will be associated with firm shipping commitments on shorter routes to the coast. Suppose that a west coast pipeline can offer tolls of $5 per barrel and that west coast barrels capture prices equivalent to Brent. In a scenario where some barrels are leaving Alberta by rail as a matter of course, it’s possible that a producer with firm west access commitments could see netbacks $8 to $10 per barrel higher than Edmonton Par prices as a result of cheaper shipping costs to reach tidewater.
As transportation constraints are alleviated, the market will have the ability to bring supply and demand back into equilibrium, likely eliminating the geographic cause of the recent price differentials – heavy oil will come to be traded at a discount which reflects its value relative to light oil. However, the underlying changes seen due to increasing North American oil production will remain. The ability of Albertan producers to move crude to desirable markets will not negate the change in the physical location of those markets. Inland hubs will trade at a discount to coastal hubs as U.S. reliance on imported oil declines. Though some capacity may reach the west, the marginal barrel leaving Alberta will travel further, at higher costs, and that will affect the value of the oil sands resource for the foreseeable future.