The fate of the Alberta oil sands is on a lot of people’s minds. As I noted recently, the International Institute for Sustainable Development (IISD) dropped a report making it clear that as peak oil demand arrived, Alberta’s product would be first off the market. I first made that obvious point over three years ago. I’ve made that point in regard to the completely unnecessary Trans Mountain Pipeline (TMX) too.
The quality discount against Brent Crude was already US$14 per barrel in 2021. And it’s only going to get higher, much higher. Why is the subject of this article.
Let’s start with the basics. Quite a remarkable number of major organizations, including the International Energy Association, McKinsey, and Equinor have high likelihood scenarios that oil demand will stop growing this decade. Most, with a few oddball exceptions like the US Energy Information Administration, project flat demand through 2050, which makes sense only if you assume that turning the planet into a baked potato is a great idea and haven’t paid any attention to rapid global decarbonization of ground transportation. Others think it peaked in 2019 prior to COVID.
I’m with the projections of last half of this decade, personally, based on what I track globally. Among other things, there’s only one very large crude carrier (VLCC) under construction in the world, against a fleet of over 900 of them. The bulk shipping industry clearly thinks that oil has had its day. I’ve spent time with two global shipping clients discussing the end of bulk oil (and coal and natural gas) shipping, and they are very aware that their business model is coming to an end.
So why will Alberta’s product, and similarly Venezuela’s product, be first off the market? Well, Alberta has a compounded set of problems including a market that’s 94% in the US, the US becoming a net oil exporter today, and the US seeing declining global and domestic markets as electrification sweeps the planet. It’s going to be increasingly focused on locking up domestic demand with its own oil, of course, and only buying the cheapest oil from foreign sellers. That’s not Alberta’s product, so the lack of diversification of demand is going to hit it hard and fast.
The bad strategy behind the tripling of the TMX was that it would unlock the Asian market for Alberta’s product, despite a significant decline in any interest from China from 2010 onward in imports from Canada. I pointed recently out that the Aframax limit on the TMX termination port in Vancouver meant that it was going to be expensive to ship across the Pacific compared to regions that could use VLCC carriers hauling up to double the barrels of oil per trip.
Major energy analysis firm Wood Mackenzie has extended this point, noting recently that the illegal invasion of Ukraine has meant that a lot more of Russia’s oil is flowing to China now, dampening even further any prospects that Alberta’s crude would flow to China. Wood Mackenzie’s analysis is that instead, more of it will flow to California’s southern refineries that can process heavy, sour crude, but I think that’s a very short term market.
Some of the why I’ve explained above, but let’s look at the kicker: hydrogen costs.
What does hydrogen have to do with the price of oil? Well, it gets back to that quality discount point. Crude oil comes in a range of how liquid it is, from stuff that flows like slightly thick water to stuff like tar. That’s light to heavy. Crude oil comes with varying percentages of sulfur which must be removed, from the <1%, referred to as sweet, to Alberta’s 5-6%, referred to as sour. And it comes with a lot of variance in water content and other impurities. Alberta’s product is at the bad end of every scale.
Hydrogen is used to remove sulfur (desulfurization), remove water and other impurities (hydrotreating), and to separate the heaviest crude from lighter components (hydrocracking). Because Alberta’s product is at the bad end of every scale, it requires a lot more hydrogen than other crude oil products.
The vast majority of the hydrogen used in oil refineries today is manufactured from natural gas, with combined upstream fugitive methane emissions and carbon dioxide emissions from the steam reformation process of 8-10 tons of CO2e per ton of hydrogen. That’s why Canada and Alberta are giving Alberta’s oil industry a C$1.6 billion (US$1.2 billion) present in the form of a blue hydrogen facility a few kilometers from Edmonton’s biggest refinery.
Blue hydrogen, as a quick reminder, captures perhaps 85% of the carbon dioxide from the steam reformation process and sequesters it. Almost uniquely for this kind of scheme, the Alberta facility isn’t being used for enhanced oil recovery. Why are the country and province buying an oil refinery a nice shiny new blue hydrogen facility? To hopefully turn that 8-10 tons of CO2e into 1-3 tons of CO2e.
Of course, that doesn’t do a thing for emissions when the oil is used as intended and burnt, as the lion’s share of emissions are from that process, but it certainly reduces Canada’s emissions within its borders, as 80% of Canada’s oil leaves the country. I recently worked out that Canada’s fossil fuel industry is responsible by itself for roughly 2% of annual global greenhouse gas emissions, but Canada doesn’t count 80% of that as its problem.
Is that hydrogen going to be as cheap as gray hydrogen? Not a chance. Will actually low carbon hydrogen manufactured from green energy and water be as cheap as gray hydrogen? Even less of a chance.
What does this mean for the quality discount on Alberta’s product? It’s going up. How much is an interesting question, and there’s sufficient information available to at least make a guess.
Remember that the US$14 quality discount it’s already seeing is without any price on carbon and with unabated gray hydrogen. The gray hydrogen likely costs in the range of US$1-$2 per kilogram. S&P Global’s price map of hydrogen shows US$1 exists in the US for unabated hydrogen, as an obvious example. We’ll go with US$1.50 as a median for unabated hydrogen.
How much hydrogen is required per barrel for desulfurization, hydrotreating, and hydrocracking? The numbers vary, but the range is 1,000 to 2,500 standard cubic feet (scf) for hydrocracking and 500 scf as the median for desulfurization, per a seemingly solid peer reviewed source.
Given that Alberta’s product is at the wrong end of every quality scale, using 2,500 scf for hydrocracking and 750 scf for desulfurization or hydrotreating seems like a reasonable guess. A kilogram of gaseous hydrogen is 423 scf. A little math suggests 7.7 kg of hydrogen per barrel of Alberta’s crude.
The US$14 quality discount starts to make a lot of sense, doesn’t it? 7.7 kg at US$1.50 per kg is US$11.55, within spitting distance of that quality discount.
But once again, hydrogen is getting more expensive. The fossil fuel industry is by itself one of the biggest global emitters of CO2, and its requirement for hydrogen is a big reason why. As a reminder, about a third of all hydrogen used globally is used by oil refineries for these processes, so a lot of pressure is being put on them to decarbonize their own operations. That means, just as it does for ammonia fertilizer, decarbonizing hydrogen.
So how much does blue hydrogen cost? Well, EEX recently launched a hydrogen index, used to get actual data on actual hydrogen deals globally, including blue and green hydrogen deals. It’s good that they are doing the work, but due to the hydrogen-for-energy fallacy there are two problems with the index.
The first is that it represents hydrogen in units of MWh not tons. This is similar to the DNV study for offshore hydrogen manufacturing at wind farms I assessed recently. It’s a problem because MWh and GWh are units of energy, and hydrogen is actually an industrial feedstock that we don’t use as a store of energy due to its great expense. As I noted in the piece on the DNV study, even the best price of US$0.78 per kg of just manufacturing hydrogen found by S&P Global and in Lazard’s levelized cost of hydrogen workups is 1.9 times the cost of imported liquid natural gas (LNG), which is already the most expensive form of imported energy. At minimum energy costs using existing unabated gray and black hydrogen is a part of the reason why we don’t use hydrogen as a fuel today.
The second is that the EU has shifted away from its empirically oriented choice to use the higher heat value (HHV) for manufacturing hydrogen, the energy required to remove water vapor from the hydrogen, to the lower heating value (LHV) which leaves the water vapor in the hydrogen. The HHV for hydrogen is almost 20% more than the LHV.
There are a lot of off-takers for hydrogen. For ammonia, they like very pure hydrogen with very little water to maximize quality of the ammonia, and to avoid the problems of ammonia becoming a caustic gas and killing people. Fuel cells like very pure hydrogen. Unsurprisingly, burning hydrogen with high water vapor levels reduces the efficiencies of combustion a lot, so you pay the price of water vapor coming or going. Hydrogen for use in oil refineries must be very pure, which is unsurprising because one of its roles is removing water in the oil. Even hydrogen for heating types want very high purity hydrogen, with allowable impurities more related to odorants than water vapor. Everybody wants hydrogen at the HHV end of the scale, not the LHV end of the scale as far as I can tell, including China.
As a result, the LHV numbers significantly understate the actual costs of hydrogen required for industrial processes, something which is undoubtedly contributing somewhat to the economic insanity of considering it as a fuel.
But we have costs from the EEX Hydrix index. Blue hydrogen come in at around US$2.70 per kg. Green hydrogen is coming in at around US$8.30. The EEX makes it clear that these are LHV numbers, so getting them to the right numbers requires uplifting them to the the HHV numbers. That makes the prices US$3.20 per kg for blue hydrogen and US$9.80 per kg for green hydrogen. They assert that those costs do include delivery to the end customer, but that’s clearly for very large amounts of hydrogen.
Some other material I saw recently suggested that by 2030, the cost per kilogram of green hydrogen would come down into the US$4.50 to US$7.50 range, but clearly that’s also an LHV number, so those are actually US$5.30 to US$8.90 per kg for actually usable hydrogen. The bottom end of that range is roughly equal to be best case scenario for 2050 out of the unrealistic DNV scenarios by the way.
Okay, now we have both halves of the cost equation for hydrogen for Alberta’s high-sulfur, tar-like, impurity-laden crude oil.
For blue hydrogen, 7.7 kilograms per barrel works out to roughly US$25 per barrel, well over the combined quality plus transportation discount from 2021 of US$21 per barrel. Transportation costs aren’t going to go down much, even if TMX oil ends up in California instead of Houston where most Alberta product goes today. Call it US$6 per barrel transportation discount for a total US$31 per barrel discount.
For green hydrogen, the numbers are much, much worse. At today’s average from the EEX, 7.7 kilograms would cost US$75.50. For comparison, the Brent crude index price is US$76.81 right now.
Assuming the best case scenario for green hydrogen of US$5.30, that’s still US$41 just for hydrogen per barrel of Alberta’s product. That’s US$47 with the lower transportation discount.
In a world awash in cheap to refine and transport sweet, light oil, there is no economic market for Alberta to sell crude at a discount of US$47 per barrel. Even the US$31 discount is deeply economically unlikely.
Suncor’s cost per barrel to manufacture its product is US$23 to US$25. The best case quality discount using blue hydrogen that they pay for without any profit makes that US$54 to US$56.
Peak oil demand means lowering oil prices per barrel. In a world that needs to decarbonize hydrogen, Alberta’s product will be too expensive to refine. The curves mean that Suncor’s product will be first off the market.
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