Bitumen royalties accounted for 10% of total Alberta government revenues in 2010-2011, and that is expected (according to the most recent Alberta Budget) to climb to approximately 20% of total government revenues, or $9.9 billion dollars by 2014-2015. Both royalty revenue estimates and royalty rates make for contentious subjects in Alberta, and this post is intended to provide a primer into how the royalty regime works and how it impacts investment decisions. My hope is that every Albertan will become more engaged in how this resource is managed, and the first step in that direction is understanding how it’s managed now, so here you go.
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.
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).
26 responses to “Your oilsands royalty primer”
Thanks for the primer. Your comments on cost inflation are very interesting.
Perhaps we should re-think the bargain royalty rate for “pre-payout” projects. With the bargain pre-payout royalty rate, Albertans eat a lot of the risk from cost overruns related to capital construction. If pre- and post-payout royalty rates were equal, I believe this would dampen cost inflation, with the downside of reducing investment. As you note, you don’t have a clear answer on the effects either way. The question I have is how much impetus still exists for the bargain pre-payout royalty rate? My understanding is that it was historically needed to encourage development of a marginal resource. Is that still the case and is the cost environment such that producers need Albertans to take a hit on royalties for cost overruns? Last, perhaps there are more efficient ways to reduce our royalty losses from cost inflation than equalizing the pre- and post-payout royalty rates.
Second, what are your views on the consequences of moving away from the “net revenue” bitumen royalty calculations to royalty calculations based on the value of bitumen? This would simplify the process for calculating royalties and more importantly, it would reduce the royalty loss to Albertans from producers’ high costs. Again, no free lunch – producers would face higher risk, meaning less investment and production at the margins. However, the “bitumen value” royalty rate could be set in such a way that there would be no change to the expected returns of the average producer.
Any thoughts would be much appreciated.
Thanks Pat. I think there’s a lot of merit in looking at the net revenue royalty regime and thinking about the implications of moving to a gross-revenue-based calculation, but we need to realize it’s not going to come for free. Right now, our royalty regime hedges significant risk of cost-overruns as you point out, but also price downsides. If you were to switch to a gross revenue royalty, with the same expected revenue, you’d be offering less insurance so you’d effectively be charging more for the right to extract – asking the proponent to take more risk as you point out. I think the incentive effects of that (mitigating the incentives for cost inflation) make it worth looking at.
I have a huge problem with the entire structure of Canada’s petroleum industry. Canada is in abusive relationship with the United States and thier oil industry which we cannot escape because of thier proximity and military might. All Canadians pretend not to notice this. But the ticks on these charts show us being bled to death drop by drop http://quotes.post1.org/live-brent-crude-oil-price-chart/ . Without the capacity to process and refine the bitumen Canada is in an economic straight jacket and we will not be allowed to escape.
Thanks, yet another great piece.
Not sure if you take requests, but might be good to get a primer on ‘costs’ (supply costs vs operating costs…) and other economic terms like ‘netback’, and profits, etc that are used in the oil sands discussion.
You have this statement in your post: “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”
-What does CERI mean when it talks about ‘bitumen supply costs’ of $44.75/bbl for SAGD. How is this different from Christina Lake’s $20+$5 op+cap/recl costs? Is it just that CL has really low costs compared to CERI’s avg, or are you and CERI talking about different ‘costs’.
-is “net revenue” the same as “netback” or are these very different terms?
-To laypersons, I think it is very easy to confuse ‘netbacks’ or ‘revenues’ with ‘profits’ that greedy oil companies are just pocketing. so it is hard to understand how an increase in royalties of a few dollars/bbl, can scare off investment, etc. Laypeople might think: ‘Heck, their netbacks are $30-$50/bbl now, what’s so bad about $25-45$ netbacks if we take $5 more/bbl for Albertans through increased royalties?’
I realize this is not an easy thing to explain, but might be worth a crack.
Thanks again for the great info and insights.
Thanks. Christina Lake is a pretty low-cost facility, so that’s part of it. I believe CERI’s numbers are an “all-in” cost, including a rate of return on capital, of 44.75 – i.e. what it would cost you if you were starting from scratch, on a per barrel of bitumen basis. Re: netback, it’s used differently, but it generally implies gross, pre-tax resource revenue net of transportation costs. Since the bitumen valuation is based on Edmonton prices, there would only be a small wedge between netbacks and the bitumen value that I used.
In terms of the “what’s so bad” question, it’s the equivalent of me asking you if you would like a pay cut. You might not starve, or even quit your job, but that doesn’t mean you’re going to be happy about it. I agree that it’s difficult to get your head around not just realized profits, but also risk. Ask the average person who says, “these oil companies are making money hand over fist,” if they would mortgage their house and make a 40 year bet on oil prices. I expect they would look at the easy statements like “oil prices always go up” a little differently.
thanks Andrew, great explanation of some of the economic terms. As for the ‘what’s so bad’ question, I think it is actually more the equivalent of you asking me if I would like my very wealthy neighbour to take a pay cut, and give some of their money to me, answer to that one is always yes 🙂
Great post, Andrew.
I’m interested in your take on one of the OECD’s recommendations from their 2008 economic survey of Canada:
“The deductibility of provincial royalty payments in calculating income for federal tax purposes, introduced in 2003, may have the opposite effects insofar as it shifts part of the burden of provincial royalty payments to the national taxpayer (Dahlby, 2005), creating a significant negative vertical fiscal externality (Dahlby et al., 2000) and accentuating regional inequities. This tax-shifting effect is set to increase with the recent reform of the Alberta royalty regime, which will allow the royalty rate to vary over an increased range of the price of oil (see Chapter 4). In general in Canada, “expenses” such as municipal or provincial property taxes, capital taxes, payroll taxes, user fees, and resource royalties incurred to earn income are deductible in computing income for tax purposes. This treatment might be best reconsidered, at least in the case of royalties. In particular, insofar as provinces fail to capture pure resource rents via their royalty systems, deductions for royalty payments from the federal CIT should be curtailed.” (p.88)
What do you think, should royalty payments be deductible from federal CIT?
Royalty payments, while structured as a net revenue tax, are implicitly a payment for the input (the oilsands ore) to the business of extracting it and producing oil. If a company can write-off real-estate or the lease/purchase of other inputs to production, they should be able to write off payments to the resource owner for the purchase of resources. Treating them differently makes no sense.
I think rather than focusing solely on royalty rate a better metric would be “total government take” as described here:
I disagree. The royalties are for the sale of the resource, which Albertans own. The total government take includes taxes which are charged on any and all businesses. One is the price paid for the purchase of an asset from government, which is why I focus my attention there. If the gov’t sold off real-estate for free, and then tried to count the businesses’ taxes as payment for the real estate, you would call it double-counting. It’s double-counting here too.
“One is the price paid for the purchase of an asset from government, which is why I focus my attention there.”
So why exclude land sale revenues/rents paid by companies to the government to extract this asset? These payments are significant to government revenues and are paid many years in advance of first production. By focusing on royalty rates alone it gives the false impression this is the only form of revenue government receives to produce this resource.
I didn’t exclude those – I talked explicitly about the devaluation of land sales with increase royalties.
Let’s stick to the facts….
According to my calculations Oil Sands companies paid in average royalties of about $7.95 per barrel for the Fiscal Year of 2011/12.
This is equivalent to a 12% effective royalty rate which in my opinion is very low. The problem with Revenue minus costs regime is that the resource owner has no control over revenue or cost. Moreover, you may have a situation when profitable projects pay fewer royalties than poor performing projects due to a cost increases (i.e. expansions, cost overruns, etc)
In order to make my calculations I took the information from the ERCB and Alberta finance:
Condensate 105.358 (10% over WTI)
Bitumen 66.24 (blending ratio: Condensate 30% and Bitumen 70%)
Volume 1.5 547.5
My figures were based on the Alberta budget, which calculates in fiscal years vs. your calculations in calendar years. Not sure why you tell me I should stick to the facts when we are citing the same numbers and issues.
Just a comment that the list of publicly traded stocks in CPP doesn’t include non traded private corps which CPP has invested in in the oil sands such as Laricina.
The Teachers Ont Pension was a large backer of North American Oil Sands and benefited when it was sold to Statoil.
Great piece, I could have used it in my MBA class as a case study..
I enjoy reading your blog. I came across a report today from ForestEthics (http://forestethics.org/downloads/FEA_Tar_Sands_funding_briefing.pdf) that suggests that more than half of the shares of many of the of the Canadian headquartered companies that are operating in the tar sands are actually foreign owned. If this is correct, then I would say that your assertion that “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. ” is somewhat misleading.
I have tried to look at the StatsCan data that you cite but the link to it in your blog is broken and I haven’t been able to find it myself.
Can you offer any further clarity to this situation?
I saw this report earlier today as well. The figures I used were from Statistics Canada, which only has updates as far as 2009, and assesses all oil and gas companies, admittedly not a perfect proxy for oilsands alone. If you look here (http://t.co/QsyFOz9f) you’ll see a graph of the % of profits under foreign control over time. StatsCan’s method for determining foreign control is likely not exactly the same as Forest Ethics’, but it goes far beyond simply assessing companies with Canadian headquarters. I know, for example, that it assesses Canadian subsidiaries of foreign companies as being foreign controlled. From what I can tell, Forest Ethics’ figures make sense, and since they are oilsands-specific, they are potentially more applicable here, but with a caveat: the oilsands share of those companies’ books is pretty small in many cases, so if Canadian ownership is only a small percentage, but that percentage is greater than the share of oilsands in the company’s portfolio, I am not sure what that tells you.
Good post, a lot of information there that people need to know, just the misleading 15 sec sound bits by a lot of agenda pushing lazy media.
One concern not addressed is the access to markets question.
How does us having basically just one market (the USA) affect our ability to increase royalties?
How does Alberta crude, SCO that is backloged in Cushing and being sold at 20-30$ per barrel discount effect our royalty regime?
Thanks Johnnie. The WTI discount, and the fact that this backs up to discounted bitumen and WCS prices clearly affects the margin in the industry, and thus the potential to collect higher royalties, if that were your goal. The WTI discount itself means that you have a lower royalty percentage, and any related discounts to heavy also mean lower revenues in the royalty base, all else equal.
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My question is, when does pay out occur? At the completing of each individual well head, or after the completion of a project involving 20, 40 or 60 well heads?
If it is at the completion of individual well heads the public interest is protected. If it is not then the project could hang for years while they pump out whatever they please, leaving incomplete installations as an excuss not to pay royalties.
It appears to be happening here in New Brunswick with natural gas. Why not elsewhere?
[…] Leach, Andrew (2012). "Your oilsands royalty primer." Rescuing the frog. http://andrewleach.ca/oilsands/your-oilsands-royalty-primer/#more-1125 […]
You speak a lot about how the price of oil is determined by global supply and demand. This is not true, as Canadian oil can go only to the USA through due to a lack of infrastructure. As such, the Canadians receive only a discounted price for Tar Sands Oil.
All the best,
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