Andrew Leach is an Associate Professor of Natural Resources, Energy and the Environment at the Alberta School of Business
If you had an investment portfolio worth hundreds of billions or even trillions of dollars, chances are that you’d keep a watchful eye on how it’s managed. Albertans do have such an asset -- it's called the oil sands. Despite the massive natural wealth in the oil sands, Albertans aren’t asking tough questions about how these reserves are managed during the provincial election.
Bitumen royalties accounted for 10 per cent of total Alberta government revenues in 2010-2011 (according to the most recent Alberta budget), a number expected to climb to about 20 per cent, or $9.9-billion, by 2014-2015. These may sound like big numbers, but on a per barrel basis, the story is different - the province collected just $6.67/bbl in bitumen royalties in the past fiscal year, and expects to collect $11.31/bbl in 2014-2015.
Most people react to these figures with quick soundbites, either by suggesting royalties are too low or that any change in them would kill the industry, but that can’t be the end of the story. Changes in the royalty structure don’t change the value of the bitumen – they change the distribution of that value.
How are royalties determined? Alberta’s New Royalty Framework sets the royalty rates for oil sands projects. The rate is higher when the price of oil rises. Projects are subject to a lower royalty rate -- calculated on gross revenues -- until the project has reached payout, or recovered its capital costs. Once payout has been reached, the project is subject to a higher royalty rate, now calculated on net revenues.
If the price of oil (West Texas Intermediate, in Canadian dollars) is $100/bbl, a project would be subject to an initial royalty rate of 6.54 per cent, which can be paid either in cash or in bitumen. These royalty rates continue until the project has reached payout - the point at which the initial and sustaining capital invested in the project has earned a rate of return equivalent to a Canadian government bond, after which time the project would be subject to a net revenue royalty rate of 35.38 per cent, assuming that the oil price stays constant.
After the project has reached payout, the amount owed to the government is determined by bitumen revenue net of operating and sustaining capital costs, but before taxes. For example, if your project has operating costs of $20/bbl (equivalent to 2011 operating costs for Cenovus Christina Lake) and assuming sustaining capital and reclamation costs of $5/bbl, you would have net revenues of $50.99/bbl, based on the January, 2012, bitumen price of $76/bbl. Royalty payments, at 35.38 per cent, would then be $18.04/bbl, which could be paid in cash or covered in-kind, by turning over 0.237 barrels of bitumen for every barrel produced.
The value of Alberta’s bitumen is determined by world markets, not by its royalty rates. So, the impacts of changes to royalty rates will differ between marginal projects and infra-marginal projects, and for projects already built vs. projects under construction or planned for the future.
For an existing project, an increase in the royalty rate means that a greater share of production goes to the Alberta treasury, which means that a smaller share goes to provincial and federal taxes (calculated on revenue net of royalties) and to shareholders – the change is not creating new revenue, it’s simply re-appropriating it.
For a project in development, a change in royalty regime lowers the expected net present value of the project, and so has the potential to affect the decision to proceed with the project. Some projects will be bankable at much higher royalty rates, while others will not. For all new projects, the returns net of royalties will be smaller, which means that these projects will pay less in federal and provincial tax as well as return less to shareholders than they otherwise would.
Changes in royalty rates will also have an important effect in terms of future lease sales – higher royalties lower the expected value of the lease, and so will lower the amount of land sale revenue. We’ve seen the reverse effect with conventional oil in Alberta – lower royalties (and, of course, high oil prices) are partly responsible for record land sale revenues. Reducing royalties shift some of the future royalty revenue forward into revenue from land sales today.
As any economist will tell you, if you allow open access to a resource, the rents from that resource will be scattered. In oil sands, we see that happening as companies continue to invest, leading to labour shortages and high rates of inflation, so that we are actually seeing lower profitability of some oil sands operations today than when oil prices were lower. Insofar as higher royalties slow development, they would also likely slow cost inflation, leading to lower operating costs than would otherwise exist.
A change to the province’s royalty regime is not a parochial concern: We think of oil sands companies as being foreign-owned monoliths, but the reality is different. These companies are owned not just by the wealthiest of Canadians, but by all Canadians. For example, scan down this list of public equity holdings of the Canada Pension Plan (PDF) and you’ll see Canadian oil sands names like Suncor, Cenovus, and Imperial Oil. The Quebec Pension Plan holds more than $5-billion in oil sands-related stocks.
There’s no single correct answer to whether we should raise royalties, but there are a lot of wrong answers based on incomplete understanding of the tradeoffs involved.
For a longer version of this post, please visit the author’s blog.