Why would you buy an oilsands lease, or if you had one, why might you chose to invest billions of dollars of your money, up front, to produce oil for the next 40-50 years? The answer is pretty simple – given your view of future oil prices, the costs of building and operating the plant, and the share of your revenues that the government will take in royalties and taxes, you’d have to be confident that you could make a rate of return on your capital equal to or greater than what you could earn on it in a similarly risky investment somewhere else. If not, why do it?
The same is true for the decision to invest in an upgrader or refinery. Upgraders and refineries make money when the value of the output is high enough, relative to the value of the inputs, to earn a competitive rate of return on capital – they are spread bets. For an upgrader, what you’re really interested in is the expected future spread between heavy oil or bitumen and light or synthetic crude oil. If you look at the figure below, bitumen had an implied average price of $65.50/bbl in 2011, whereas a barrel of lighter, higher value synthetic crude sold for an average of just over $102/bbl – a premium of $36.50/bbl – let’s call that the coke spread, since most upgraders or integrated refineries will employ a coker to strip out the heavier ends of a barrel of bitumen. Looking forward, according to Sproule Associates, the average spread is expected to be a little lower than that, at about $32.20/bbl over the next 10 years.
So, can you make money on an upgrader in Alberta with a $32.20/bbl spread? As with anything in economics, the answer is it depends. It depends on how much it costs you to build and operate the upgrader, what tax incentives you might receive, as well as whether you can profit from any synergies between extraction and upgrading. Without tax incentives or significant co-benefits, the short answer is likely no.
Capital costs for building an upgrader in Alberta are likely well-over $60,000 per flowing barrel (per barrel/day of capacity), as this was Suncor’s 2008 estimate for building the 200,000 barrel per day Voyageur project. Even at a more conservative $50,000 per barrel/day of capacity, if you want a 10% rate of return on your invested capital over a 40 year time horizon (yes, I know these are too conservative as well), you’d need to net $15.56/bbl. A more realistic 13% rate of return over 25 years brings the capital costs up to $20.76/bbl, and you haven’t paid to operate the upgrader yet.
Upgraders use natural gas, electricity and chemicals/catalysts as their major inputs. Estimates of fuel and non-fuel operating costs for an upgrader vary significantly, but a low-end is about $7/bbl, with a median estimate of $8-9/bbl, and these costs will increase over time.
There’s one other hitch to this. If your upgrader uses a coker, some of your feed will be converted to low-value coke, which you could either burn or bury. If you bury the coke, which many operators do, you’d lose about 14% of your feed volume, so to produce 100,000 barrels per day of synthetic crude, you’d need about 116,000 barrels per day of bitumen coming into your refinery. That 14% loss of the feed hurts, since that brings your $32.20/bbl spread down to an effective $21.57/bbl of synthetic crude produced. Burning or selling the coke won’t change the deal much.
Given all the assumptions above, the currently expected $21.57 spread between the total cost of feedstock and the value of the end product means that your upgrader will earn 6.6% rate of return on billions of capital initially at risk. At those kind of rates, leverage won’t help you much because you won’t be able to secure debt financing much cheaper than 6.6%. Given that heavy-light differentials are highly volatile (i.e. you can’t guarantee that spread), the likelihood that someone would put this sort of capital at risk unless there were significant process and/or tax/royalty advantages to doing so seems slim. That likely explains why the Northwest upgrading project was only possible with government cost-of service guarantees and why you don’t see other merchant upgraders operating in Alberta.
Daniel Stuckless asked today on Twitter, “how does the value (of bitumen) change with (a requirement for) domestic processing?” Well, Canadian producers (and hypothetical merchant upgraders) are price takers for oil, so work backwards from there using the figures above. If upgraders need to earn a 13% rate of return to find people willing to put that kind of capital at risk, then the expected spread between 1.14 barrels of bitumen and and a barrel of synthetic crude oil has to be at least $30, or about 40% higher than it’s expected to be over the next decade. Since you can’t increase the world price of oil to increase that spread, you have to decrease the capital cost, operating cost, or feedstock cost. That means capital and operating cost tax allowances or subsidies, cost of service guarantees, or discounted bitumen feedstock. If you want more upgrading, it’s likely going to come at the government’s expense, not the oil companies’. Why would the oil companies bear the costs if we’ve passed a law that says the bitumen must be upgraded here? Our bitumen producers would be a captive market.
The real question people should be asking is, “should we be willing to subsidize, either directly or through trade barriers, merchant upgraders and refineries in this country in order to export a higher value end-product?” That boils down to a choice to sell it on the open market and to allow it to be upgraded where costs are lowest, or to sell it to a domestic upgrader for 10% less so that the upgrader can make money producing synthetic oil. Sure, we can have more upgraders and people will work to build and operate them, but we have to be willing to spend the money (or the bitumen) to make water run up hill, so to speak. I simply don’t see why the value from our natural resource should go to subsidizing the processing of our natural resources. In my view, there are far better uses for that value.