Skip to content

Understanding future demand for heavy oil

Blair King: Why the Trans Mountain Pipeline expansion project is a good economic bet.
(Macklin Holloway /

In the last couple weeks the campaign against the Trans Mountain Pipeline Expansion (TMX) project has been turned up to 11.

My social media feed is full of claims like: “100+ economists sent a letter to @JustinTrudeau confirming that #TMX pipeline is massive boondoggle putting billions of tax $$ at risk.” Needless to say, the letter was not signed by “100+ economists” – unless you define “economists” to mean primarily individuals with no credentials or practical experience in the academic field of Economics. Rather, it was signed by a handful of economists and a lot of anti-TMX activists.

One of the major arguments is that there will be no demand for Alberta’s oil in a post-pandemic world. More specifically, the letter argues “decline in world oil markets and the escalating construction costs have undermined the viability of TMX and put taxpayers’ money at risk“.

As I will explain, the Canadian oil sands industry (producing heavy oil at low cost from facilities with low depletion rates) makes the TMX a good investment in a world with plateauing and/or decreasing oil demand.

Oil Field Decline and Depletion

To understand why oil sands are a good bet, you must first understand the concept of oil field decline and depletion.

In the simplest terms: oil fields don’t last forever. Each oil field has a finite supply and a limited lifespan. Some, particularly the big Saudi fields, have huge supplies that have lasted for decades and will be there for decades to come. But those fields are the exception, not the rule. As Terry Etam explains:

Natural decline rates on petroleum wells/fields is a minimum of about 3 per cent and, for new technology like shale fields, something more than 20 per cent. Let’s be fairly conservative and say that global decline rates are 7 per cent.

On a 100 million b/d base, that would mean that the world would need to add 7 million b/d of production after just one year to keep production flat. Over two years, the petroleum industry needs to add 13.5 million b/d to keep production flat at 100 million b/d.

Yes, you read that right, a shale well can lose 20% of its production in one year. In order to maintain production at existing rates, new wells have to be drilled pretty much constantly. And during the pandemic, that has not been happening.

Meanwhile, on the international front, the majors and super-majors have significantly cut back on exploration and development, and have put major projects on hold. What does this mean to oil sands producers?

Contrary to claims otherwise, it is good news for the Alberta oil sands. Unlike their competitors, oils sands projects have very low depletion rates with very low break-even points. As IHS Markit puts it:

Even in a low price scenario that sees upstream investment fall sharply, production from Canada’s oil sands does not. Output remains stable and companies would chip away at costs over time, experiencing more production gains by upgrading existing facilities. This scenario is a reminder about the unique nature of Canada’s oil sands. The absence of meaningful [production] declines makes a future without oil sands growth difficult to see. [emphasis mine]

Much existing oil sands production is profitable at prices over $25/barrel – but CNRL recently reported mining and upgrading operating costs declined to a record low of $17.74/barrel. In a world where the drop in supply is expected to exceed the drop in demand, existing oil sands projects, with their low depletion rates and low break-even costs, will be ideally situated to meet the world’s future oil needs, especially since the oil sands produce heavy crude.

On the Particular Value of Heavy Crude

Why emphasize the importance of “heavy crude,” since many activists like to claim heavy crude is inferior to light crude? That is a common misconception.

Heavy oil is neither better nor worse than light crude. They are distinct products that have similar, but not the same, markets.

Heavy crude needs to be refined in specially-designed and built high-conversion refineries. These high-conversion refineries include expensive cracking and coking units, designed to break down the longer and heavier hydrocarbons into the smaller units used in gasoline, kerosene and diesel.

Simpler light crude refineries, meanwhile, don’t typically have these cracking and coking units. Ironically, this can mean light crude refineries can’t handle heavier components in light crude oils, and so these refineries end up producing more undesirable byproducts per barrel.

What this means is that the heavy oil refineries produce more gasoline/diesel/kerosene per barrel of heavy crude oil than the light refineries do per barrel of light crude oil. As a bonus, the complex heavy refineries produce a lot less waste petroleum coke per barrel, which also reduces their costs.

This difference is called the “coking margin,” which for the last few decades has exceeded the “crack spread”. That number has only increased in the intervening decades, pushing many refinery owners to invest to increase the complexity of their refineries.

Having invested heavily, owners will pay to get the heavy oil that optimizes their returns. This is why the light-heavy price differential has mostly disappeared in the last couple years.

As for the supply side, for decades Venezuela was a major exporter of heavy oil. But thanks to bad government and lack of investment, Venezuela has dropped from exporting close to 3 million barrels per day in 2000 to nearly zero in 2020. That 3 million barrels per day is almost 6 times the volume that can be moved in Line 2 of the TMX.

Now let’s look at what has happened on the demand side.

Asian Refining Capacity

One of the most bizarre recent narratives is that there’s no market for diluted bitumen in Asia, and that Asian refineries can’t refine dilbit. This is entirely untrue.

Historically, American Gulf coast refineries have been the pinnacle of refining complexity. This is no longer the case. As presented here, Asian refineries are approaching the complexity of the US fleet.

As Reuters recently reported, many of the region’s refineries are new and are optimized to process heavy and sour crudes. To the contrary, Asian refineries can refine over 8 times what Line 2 of the TMX can supply to Westridge Marine Terminal for export.

(Want numbers in detail? Please see my blog.)


Let’s summarize the case for the TMX:

Currently, the crude oil market is expected to plateau and then drop. However that drop is not expected to be as steep as the ongoing drop in supply from global oil field decline and depletion.

Historically, this decline and depletion has been counteracted by increased investment in exploration and development upstream, but instead, investment as significantly decreased. The result will be a global decrease in new oil fields, and in particular in access to heavy oil. Meanwhile, refineries have spent billions upgrading their facilities to refine increasingly hard-to-get heavy oil.

Into this world of demand outstripping supply for heavy oil comes TMX.

The project will allow Alberta to ship highly-desired heavy oil from oil sands facilities with very low depletion rates and break-even points, to motivated buyers with custom-made facilities.

Instead of a bleak outlook, this is an ideal scenario for Canadian producers. They will have motivated buyers seeking a steady supply of highly-prized oil, when global demand for heavy crude is expected to increase.

So much for that letter.