On March 19th, the Canadian federal government provided its 2007 Budget (pdf), which changed the fiscal regime for oil sands. More specifically, it phases the elimination of the accelerated Capital Cost Allowance (CCA) 41.
When the National Oil Sands Task Force (NOSTF) originally proposed the accelerated CCA 41 in the mid 1990s, the industry and governments believed that oil would be stuck in the $20 – $30 real price band forever. Although oil is a depleting natural resource, most believed technology would allow oil companies to find and exploit smaller pools of oil economically. Oil sands projects are huge mega-projects which take several years of engineering and design work prior to construction. Construction typically takes four to six years. After at least five years of spending money, the developer finally begins to start earning money as production begins. And then production usually lasts about 40 – 50 years. Under a moderate or low price scenario, oil sands projects are not attractive and are very risky. If a project happened to come on stream during a four or five drought of low oil prices, it would likely never recover its cost of capital. Moreover, there was a fear that within 50 years, there stood a strong chance that some other energy source might be developed and the oil sands would become worthless. Thus, there was a desire to monetize the oil sands by encouraging production as soon as possible.
To help reduce the risk and to encourage oil sand developers, the Alberta and Canadian governments put in place a fiscal regime that is extremely attractive. On the royalty side, the Alberta government allows the developer to earn the long term bond rate before paying meaningful royalties (payout). Prior to payout, the company only pays 1% gross revenue royalty. The industry wanted 0% but the Alberta government thought that was unpalatable. On the taxation side, the federal government allowed the accelerated CCA 41. At the time, the accelerated CCA 41 was a huge bonus to the industry.
The accelerated CCA 41 provides is a mechanism where a developer can recover its capital back quickly and the governments' taxation benefits are deferred. Under the prior rules, the developer was able to write-off its development capital at 100%. Now, it will use a 25% deduction.
When the NOSTF used moderate prices and reasonable costs, the accelerated CCA 41 provided roughly one-quarter to one-third more value on a net present value basis. Today, I was curious about how the change in CCA 41 would affect oil sands developers. I created a hypothetical case and ran a complicated financial model. My hypothetical case was pulled out of thin air and does not represent any real project. I used the following major assumptions:
- Mining Project only;
- C$40 bitumen price;
- 300,000 barrels per day production;
- Capital: $4.8 billion (40% of a $12 billion integrated project);
- Sustaining capital of 4% of construction capital;
- Operating costs of $15 per barrel;
- 50 year life;
- Alberta tax rate of 10%
- Federal tax rate of 19% throughout the time period (it is a bit higher today);
- 2% inflation; and
- 12.5% discount rate.
Using these hypothetical assumptions and using the accelerated CCA 41, the project has a 27.5% IRR and an NPV of $6.5 billion. Using the same assumptions but without the accelerated CCA 41, the project has a 26.5% IRR and an NPV of $6.3 billion. So yes, the change has an impact, but that impact is nowhere as important today as it was before under much lower prices. Using the set of assumptions above, the change in value to the developer is only 3% on a net present value basis. A very slight change in bitumen price would easily overwhelm this change.
To recap, when prices were lower and oil sands projects were marginal, the accelerated 41 CCA was a huge value driver. It added significantly to a developer's net present value. When prices are higher and the developer already has very attractive returns, the value of the accelerated 41 CCA as a percentage if net present value is not significant.
And to emphasize again, these assumptions are just my wild guesses. I have not calibrated my assumptions against any existing or proposed projects. I began with a capital cost intensity of $40,000 per barrel per day for an integrated project. I then assumed that mining was about 40% of that amount. The rest of the numbers tumbled out from those initial assumptions. I chose a mining project as opposed to an integrated project—one that includes an upgrader—because of the royalty complexity and uncertainty for an upgrader.
As an aside, most of the existing, perhaps all of the existing, oil sands operators were given the option of whether to have the upgrader included in the royalty calculation. To cut to the chase, if a developer believes that light heavy differentials will remain wide, it will elect to have the royalty on bitumen to maximize value. If a developer believes that light heavy differentials will quickly return to historical norms, then it will elect to have the upgrader as part of the royalty to reduce risk. This topic is a whole article in itself and will not be dealt with in further detail in this article.
I found the results interesting. I had expected more of an impact because of the attractive nature of the immediate write-off of capital. But pragmatically, with a rich project, it is of little consequence.
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