Month: February 2012

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.

Read more

Next week, the EU is expected to vote on the Fuel Quality Directive which would assign a higher emissions rating to Alberta oilsands than to other sources of crude oil, including some which may or may not actually have higher emissions than oilsands oil.

One of the many arguments against this policy made by Canadian government and industry officials is that it exempts other similar sources of oil, and turns small differences in actual emissions into large differences in rated emissions.  Environmental advocates, such as Hannah McKinnon, the campaigns director for Climate Action Network Canada, have countered that, “the oil industry was using bogus arguments against the European legislation since bitumen estimates in the policy applied to the resource in all countries, including Venezuela.” As far as I can tell, that’s not true, and the reason is viscosity.

Read more

Yesterday, I had a lengthy Twitter discussion with Green Party Leader Elizabeth May, on the subject of oil pipelines and energy security.  A few things in the discussion surprised me, and it also forced me to think a lot more about oil infrastructure in this country and to put some numbers to the question, “What would it take for Canada to be oil self-sufficient?” What would we have to put in place to supply all of Eastern Canada’s refineries with Canadian oil?

Let’s be clear on a couple of things up front – first, I don’t necessarily think that oil self-sufficiency is the right goal. If we can supply ourselves with oil at a lower net cost by exporting west or south and importing from the east, as we have for years, that’s likely the preferred solution.  Second, I’ll have to leave a lot of details out of this post in terms of oil grades, refinery compatibility, etc. Third, I’ll assume that we run the existing Canadian refinery stock at nameplate capacity, regardless of Canadian domestic refined-product demand, with the balance of production going to export. Finally, I’m going to ignore the fact that the Enbridge mainline system runs through the US, and treat it as a potential bullet line from Western to Eastern Canada.  More to come on each of those elements in future posts.

Read more

After my 1700 word rant the other night, I thought I’d tell you the same story with two figures.

The first figure shows you two things – the difference between crude oil prices in the Midwest US (WTI in PADD 2) and the US Gulf Coast (Brent or LLS in PADD 3) is shown in blue, with the widening Brent-WTI spread as the rising portion on the right. In red, you see the difference in gasoline prices, in $/gallon, scaled on the right axis. Through 2011, averaged weekly, crude oil in the US midwest was $15.75/bbl LESS expensive than on the Gulf Coast, while gasoline was, on average, 11.1c/gallon MORE expensive. The historic depreciation in crude oil in the midwest over the past year actually coincided (correlation, not causation) with higher gasoline prices. The real story, however, is that gasoline differentials do not track local crude differentials.

Read more