How are royalty payments determined?
The Government of Alberta New Royalty Framework (PDF) sets the royalty rates for oilsands projects according to a schedule (PDF) which adjusts both on the financial state of the project and based on the price of oil. The royalty rate is higher the higher is the price of oil, and 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.
What does that mean? Let me explain with a basic example. Assume that the price of oil (West Texas Intermediate, in Canadian dollars) is $100/bbl – at that price, a project would be subject to an initial gross revenue royalty rate of 6.54%, and eventually a net revenue royalty rate of 35.38%, assuming that price stays constant. So, now we have the rates, we need to know the value of production. Since there is not really a fluid market for dry bitumen, the Alberta government derives values bitumen for royalty purposes based the price of diluted bitumen, or dilbit - the value of a barrel of bitumen is determined by what you can sell a barrel of diluted bitumen (WCS) for, less the value of the diluent.* So, in the early years of your facility, if oil prices remain at $100, the project will remit 6.54% of the implied revenues from bitumen sales to the government. Based on market prices in January of this year, the implied price of bitumen was $76/bbl, and the royalty share would have amounted to $4.97/bbl.
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. The time to payout will depend on the construction and operating cost of the project, as well as the bitumen revenues net of royalties, so projects pay out more quickly at high oil prices, and less quickly if costs are high.
After the project has reached payout, it moves to a net revenue royalty regime, where the amount owed to the government is determined by bitumen revenue net of operating and sustaining capital costs. For example, if your project has operating costs of $20/bbl (equivalent to 2011 operating costs for Cenovus Christina Lake) and sustaining capital and reclamation costs of $5/bbl, you would have net revenues of $50.99/bbl, based on the derived price of bitumen for January 2012 used above. Your royalty payments would then be the equivalent of $18.04/bbl. As above, you could remit your royalty in-kind, by turning over 0.237 barrels of bitumen for every barrel produced.**
If you look at Alberta’s 2012 Budget, you’ll see that bitumen royalty revenues are expected to be $4.1 billion on 1.85 million barrels per day of production, or an average of $6.10 per barrel. Now you’ve got an idea of why – a lot of new projects paying pre-payout royalties, and high operating costs leading to longer times to payout and lower net revenue royalties from post-payout producers.
Should we raise royalties?
The question of whether we should raise royalties is, for the most part, a two-part issue. First, it’s a distributional question – who should get the rents? Second, it’s a development strategy question – higher royalties imply, all else equal, slower development, lower pre-royalty costs per barrel, and a host of other effects. The important thing to remember is that royalties do not determine the value of the bitumen, but rather they determine whether it will be produced and who gets the value/rents***.
The value of bitumen is determined by the world market for oil. Refiners will not pay more for oil produced in Alberta because we charge a higher royalty rate. Insofar as we are the marginal producer, increasing royalties in Alberta could have a small impact on the world price, but more likely they would simply lead to substitution to other sources at the margin. Assuming that world prices are invariant to small royalty rate changes (on the order of +/- 25%) in Alberta, what would the impact be? The impacts 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 Crown, which means that a smaller share goes to provincial and federal taxes (calculated on revenue net of royalties) and to shareholders – it’s not creating new revenue, it’s simply re-appropriating it. Since royalty rates are initially low, and eventually calculated on net revenue, it’s hard but not impossible for a change in the royalty regime to cause an existing project to outright lose money, but such a change will erode returns to shareholders and lead to a transfer from some Canadians to others – it’s not an entirely free lunch.
It’s easy to think of oilsands companies as being foreign-owned monoliths, but the reality is different. According to Statistics Canada, overall in oil and gas, 35% of assets were foreign-owned in 2009, with 22% being US-owned. Similarly, 41.5% of operating profits were earned by foreign-owned entities. So, for every dollar of what would otherwise be operating profit which is captured by increased royalties, 58.5 cents would be from Canadian companies. 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 oilsands names like Suncor, Cenovus, and Imperial Oil. Don’t stop there though – check out this list of CPP holdings in foreign, public companies and you’ll see Exxon, Conoco-Phillips, Total and BP. The Quebec Pension Plan holds over $5 billion in oilsands-related stocks. If you have a company or government pension or hold mutual funds, they’ll likely have significant holdings in oilsands firms.
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. All else equal, you would expect higher royalties to lead to a lower pace of development, with the impacts being larger the larger are the changes in the royalty rate. Some potential projects will be bankable at much higher royalty rates, while others will not. In the long run, there is also an important effect in terms of lease sales – the amount firms will be willing to pay for a lease is determined by the net present value expected from future development on that lease. Higher royalties lower the expected value for the proponent, and so will lower the amount of land sale revenue (of course, we’ve seen the reverse effect with conventional oil – lower royalties are partly responsible for record land sale revenues in the province).
There’s another important link between development and royalties – cost inflation. As any economist will tell you, if you allow open access to a resource, the rents from that resource will be dissipated. In oilsands, we see that happening as companies continue to invest, leading to labour crises and high rates of inflation, so that we are actually seeing lower profitability of some oilsands operations today than when oil prices were lower, and we are also seeing lower royalty revenues per barrel as a result of these higher costs. Insofar as higher royalties slow development, they would also likely slow cost inflation, leading to lower operating costs than would otherwise exist in the province. I don’t have a clear answer as to whether that effect is more or less important than the production slowdown effect in determining total royalty revenues, but it’s the question we should be asking.
Bottom line – if you reduce royalties to zero, you’d have maximum production and rents would be dissipated through inflated wages and operating costs, and any remaining rents would be captured through taxes and corporate profits. If you increase royalties toward 100%, you get no production and thus no revenue or realized rents to anyone. Somewhere in the middle is the combination of production, economic activity, rent collection and rent dissipation that works for you. There’s no single right answer, but there are a lot of wrong answers based on incomplete understanding of the tradeoffs involved. I hope this helps you to think about the ones which matter to you.
Conclusion
If you consider the oilsands resource is owned by all Albertans and amounts to over 170 billion barrels of bitumen which can be profitably produced given expected prices with today’s technology, the management of this asset should be a primary concern for all of us. If it costs, on average, $40/bbl to produce that bitumen, and it’s worth $70-80, the rents are potentially worth over $1 million dollars to every Albertan. Collecting those rents is a challenge, and some will be dissipated no matter what the policy. But, you own the resource; don’t be afraid to ask the tough questions about how it’s being managed.
* If you sell more than 40% of output on the open market, you can use actual revenues, not derived revenues, for royalty purposes.
** The net revenue royalty, calculated at 35.38%, per barrel produced is $18.04. Given the implied bitumen price of $75.99, you could remit royalties in-kind by providing 23.7% of your production to the Crown.
*** When economists use the term rent, they refer to profits over and above a market return on capital. There are potential rents in finite resources because that natural capital is finite and so the owners of it have market power (firms can’t simply decide to extract oilsands in Manitoba because Alberta charges royalties).
Original Article
Source: andrewleach.ca/
Author: Andrew Leach
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