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.
Source: Data from Sproule Associates (January 31, 2012)
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.
Capital costs for building an upgrader in Alberta are likely well-over $60,000 per flowing barrel (per barrel/day of capacity), as this was Suncor’s 2008 estimate for building the 200,000 barrel per day Voyageur project. Even at a more conservative $50,000 per barrel/day of capacity, if you want a 10% rate of return on your invested capital over a 40 year time horizon (yes, I know these are too conservative as well), you’d need to net $15.56/bbl. A more realistic 13% rate of return over 25 years brings the capital costs up to $20.76/bbl, and you haven’t paid to operate the upgrader yet.
Upgraders use natural gas, electricity and chemicals/catalysts as their major inputs. Estimates of fuel and non-fuel operating costs for an upgrader vary significantly, but a low-end is about $7/bbl, with a median estimate of $8-9/bbl, and these costs will increase over time.
There’s one other hitch to this. If your upgrader uses a coker, some of your feed will be converted to low-value coke, which you could either burn or bury. If you bury the coke, which many operators do, you’d lose about 14% of your feed volume, so to produce 100,000 barrels per day of synthetic crude, you’d need about 116,000 barrels per day of bitumen coming into your refinery. That 14% loss of the feed hurts, since that brings your $32.20/bbl spread down to an effective $21.57/bbl of synthetic crude produced. Burning or selling the coke won’t change the deal much.
Given all the assumptions above, the currently expected $21.57 spread between the total cost of feedstock and the value of the end product means that your upgrader will earn 6.6% rate of return on billions of capital initially at risk. At those kind of rates, leverage won’t help you much because you won’t be able to secure debt financing much cheaper than 6.6%. Given that heavy-light differentials are highly volatile (i.e. you can’t guarantee that spread), the likelihood that someone would put this sort of capital at risk unless there were significant process and/or tax/royalty advantages to doing so seems slim. That likely explains why the Northwest upgrading project was only possible with government cost-of service guarantees and why you don’t see other merchant upgraders operating in Alberta.
Daniel Stuckless asked today on Twitter, “how does the value (of bitumen) change with (a requirement for) domestic processing?” Well, Canadian producers (and hypothetical merchant upgraders) are price takers for oil, so work backwards from there using the figures above. If upgraders need to earn a 13% rate of return to find people willing to put that kind of capital at risk, then the expected spread between 1.14 barrels of bitumen and and a barrel of synthetic crude oil has to be at least $30, or about 40% higher than it’s expected to be over the next decade. Since you can’t increase the world price of oil to increase that spread, you have to decrease the capital cost, operating cost, or feedstock cost. That means capital and operating cost tax allowances or subsidies, cost of service guarantees, or discounted bitumen feedstock. If you want more upgrading, it’s likely going to come at the government’s expense, not the oil companies’. Why would the oil companies bear the costs if we’ve passed a law that says the bitumen must be upgraded here? Our bitumen producers would be a captive market.
The real question people should be asking is, “should we be willing to subsidize, either directly or through trade barriers, merchant upgraders and refineries in this country in order to export a higher value end-product?” That boils down to a choice to sell it on the open market and to allow it to be upgraded where costs are lowest, or to sell it to a domestic upgrader for 10% less so that the upgrader can make money producing synthetic oil. Sure, we can have more upgraders and people will work to build and operate them, but we have to be willing to spend the money (or the bitumen) to make water run up hill, so to speak. I simply don’t see why the value from our natural resource should go to subsidizing the processing of our natural resources. In my view, there are far better uses for that value.
Great article!
Sometimes you must feel like quoting Rev Lovejoy from the Simpsons…
“Short answer is “Yes” with an “If”; long answer is “No” with a “But””
Nice read..wonder if in equilibrium we are indifferent between upgrading and shipping.
That should be the outcome – also explains why you only see upgraders in integrated facilities where they can capture some “external” benefits from being located at the extraction site. I read a couple of other piece which suggested the break-even point for a refinery refit to handle heavy-sour feeds was around $15/bbl – so as long as transportation cost differences are that large, then US refinery refits should come before merchant upgraders here, in a free market.
Very interesting. What happens if you add a cost for “emissions” or “externalities”, be that a price for carbon or another instrument?
Thanks Annette. GHG emissions frm upgrading would depend on where you draw the line between the extraction facility and the upgrader. Brandt (2011) has upgrading emissions at just a little more than mining extraction emissions per barrel. I’d need to go through the numbers in detail to get an exact value, but roughly 0.04t/bbl for upgrading. For every $25 in carbon price, you’d be adding $1/bbl to the average operating cost.
You say $50,000 is more conservative. I would argue it should be termed aggressive. Not sure anyone in the financial world would believe a $50,000 number given the consistent story of cost over-runs, delays, etc. However, you note costs are higher so you actually paint a much rosier picture than is possible. Further, what would provide a better absolute economic benefit: running a mining/in situ operation at a loss for longer and paying lower royalties for longer before jumping to the higher royalty level but having the upgrader built with associated tax revenues remembering the upgrader won’t pay taxes for years as they recoup their investment?
Hi Jeff,
I agree. $50,000 was a low estimate, as was $7/bbl operating cost, as was the 2% annual cost inflation. Point was, even if you low-ball all the costs, you still need a big spread to break even.
Your last point is exactly what I was trying to illustrate. Higher value end-products, when driven by fiat, are not generally net-positive. You’ll be giving up value somewhere else in the supply chain, or using gov’t revenues, to make it work.
Andrew
A thorough and objective analysis. Guess we’ll be seeing lots of you on TV, radio and in the press, again. Great work.
Any thoughts on new technology like paraffinic froth?
http://www.albertaoilmagazine.com/tag/paraffinic-froth-treatment/
Lower oil recovery at start but when combined with a second treatement, the recovery is improved. See Titanium Corporation Inc. http://bit.ly/wCiQlP
Combined, the claimed benefits are impressive. Huge savings in capital costs, produces equivalent of Mayan heavy crude, high oil recovery, oil and mineral recovered from tailings, no tailings ponds, no massive energy hit as in upgrading and hence some reduction in carbon tax exposure.
Thanks. Paraffinic froth is not really new, but this particular implementation seems to be. I’ve just been reading up on it over the last couple of days. Anything that can get partial upgrading of oilsands feeds at low capital and labour costs is a positive for the province. Titanium Corp is an interesting company – they have been on my students’ energy briefing note lists for a couple of years now, and no one has taken them on, which I find odd. Neat business model.
Andrew
First of all, why are you talking about upgraders when everyone is talking about refineries. Second, your numbers are meaningless without a comparison to numbers in areas where the oil is shipped for upgrading (ie. Texas).
Robert, some people are talking about refineries, while others are talking about upgrading which would allow more refineries to handle Canadian crude, including those in Eastern Canada. As always, if you think my analyss is useless or irrelevant, you are most welcome not to read it.
I’m not too sure if I trust the source here. They seem to be saying that Canada shouldn’t be builing refineries because the costs are too high. If the costs are so restrictive how come other countries have figured out how to refine at a profit. Heck, they were even able to refine when prices were below $50 a barrel. There’s something a little smelly about your whole report Andrew.
Hi Cal,
By all means, question the numbers but I thibk that you’ll find the #s line up if you do some research. Two things: first, upgrading and refining are different elements, but one reason that equilibrium spreads are low is that it’s relatively inexpensive to retrofit an existing refinery to process heavy oil into higher value end products, and the US and Canada both have a lot of refinery capacity, including some idled plants. Second, even within Canada and the USn building in Alberta is very expensive since you’re competing for the same labour and service firms as oilsands production. So, building a new facility is a hot labour market to compete w existing facilities in soft labour markets is not usually going to end with profits. Finally, if you look at historic refining spreads, they are generally small with periods of high profits.
Andrew
Andrew
Two questions, rather than comments. First, what’s wrong with using coke to fuel the upgrading process & why is in uneconomic? I remember in Holland using coke to fuel our stoves & central heating systems and it seemed to be quite effective (although it didn’t have lasting overnight qualities; for that we used anthracite. Secondly, what’s wrong with underground, in situ upgrading like Petrobank’s THAI methodology?
Thanks.
Nick
Hi Nick,
Thanks for reading. Some do burn coke, while others bury it, and Nexen is a bit of a hybrid since they run an asphaltine gasifier. The reasons for this I know only superficially, and keep in mind that I’m an economist not a refinery engineer. Coke is generally quite high in impurities and so burning it is a bit of a challenge, especially if you have to meet stringent local air quality regulations. Some of it was also policy, which Alberta reversed in 2008 (http://www.pembina.org/media-release/1783) preventing some operators from burning coke, although the Alberta Specified Gas Emitters Regulation on co2 went into effect in 2007, so that likely negates some of the impact. Here’s a little explainer from the Alberta Government on properties of oilsands pet coke: http://www.energy.alberta.ca/OilSands/792.asp
Re THAI, it’s really taken a kicking from the low gas prices, since a lot of the upside on that was that you’re not using much natural gas to produce it as you’re essentially using the bitumen which would otherwise have remained in the ground to produce bitumen. Petrobank did not really have an in situ upgrading angle to the same degree as Shell or some others did (Shell actually had a Peace River Pilot which effectively produced diesel fuel directly from the ground), but they do get a little bit of in-situ cracking and they also have a pre-commercial pilot for a catalytic casing (CAPRI) that might get them another 7-8 degrees API. Combined, I’ve seen a few different projections, but the most ambitious ones get them to an API 20 final product, equivalent to a conventional heavy like a Lloyd blend. So, they’re getting some upgrading but not to the same degree as a Syncrude, Suncor, Nexen or CNRL which produce in the 30-40 degree API range (Nexen’s is really light at almost 40). So, nothing wrong with it – it’s just less cost-competitive now than when people were expecting $15-$20 natural gas, and it’s not really a substitute for full upgrading.
Andrew
[…] written at length about the first two questions here and here, so that leaves the issue of the long-term spread. A good benchmark for a long-run […]
How did you get from $32.20/ bbl to $21.57/bbl?
I do $102.00-$65.50*1.16 = $26.02/bbl
Good read. Thanks.
First is the spread between bitumen and light, but since you need to used 1.14 bbls of bitumen to produce a barrel of SCO, you are losing 14% of the value of a barrel of bitumen for each bbl of SCO you produce – that’s why the second, effective spread is lower.
Your observations last February looked at the upgrading question from a largely micro-economic perspective, i.e. does upgrading make sense from the point of view of a firm in the oil patch.
Yoy & I both know that what matters in the oil industry is less what you have by way of reserves but what you can get out of the ground & on to markets.
I look at the forecast growth for oil sands output, do the math and come to the conclusion that to move the incremental output to market we need the Keystone AND the Kinder Morgan expansion AND the Northern Gateway AND a pipeline to Eastern Canada. And right now, I see problems with all four.
The Keystone is really being driven by Gulf Coast refineries needing a replacement source of CHEAP nheavy crude due to falling supples from Vennie & Mexico; from a macro-economic point of view the US economy is much better off with Bakken oil because it 100% US-sourced while in the of oilsands bitumen a significant portion of the benefits generated stay in Canada.
Kinder Morgan so far seems to have been able to stay largely under the radar; let’s hope it stays so.
Eastern Canada isn’t looking for oil per se; it’s looking for CHEAP OIL. The moment the hoi polloi become aware of that, someone will start yelling “NEP 2.0”, and that outlet is in trouble.
One of objections having been raised about the Northern Gateway line is that pipelining bitumen is more risky than pipelining other products. That argument may, or may not, hold water but the reality is that it is now firmly established in the public mind, and that’s all that really matters. One way to spike the guns of those who argue that would be to upgarde the stuff here. And looking at the situation from a more holistic perspective, the cost of doing so would be offset to some extent by eliminating the need to build a twin, inward-bound diluent-carrying pipeline and by the fact that the efficiency of the outward-bound pipeline would be enhanced by the fact that it would no longer be necessary to carry the diluent on its journey back to the Coast.
To me, Priority NO. 1 is to make sure that Alberta can get its oil sands oil to market. For some time I have been increasingly fearful that Alberta faces far too many obstacles to be able to do so in a timely fashion, And if that were to become a more general perception, we’re in trouble! So in my mind, the time has arrived for Ms. Redford et. al. to start thinking more creatively, among others about revenue “optimization”, rather than “maximization”.
I write a weekly review reporting & commenting on what I see happening in the world of economics & finance that now goes out to several hundred friends & acquaintances around the world whose place of business ranges all the way down from ministerial offices & corporate board rooms to a press room in Africa. This week’s edition, that is supposed to go out overnight Thursday but sometimes doesn’t make it until noon Friday, touches more fully on this issue and, if you weere to send me your email address, I will sned you a copy.
Nick RvT
Thanks for your input. My printer is on the fritz right now. Could you perchance be so kind as to send me a copy directly to the above address so I can save it on my hard drive?
As to your analysis, it’s interesting & useful, but only as far as it goes. For it suffers from the same limitation as all upgrader valuation exercise to date (at least those that I am aware of: they approach it from a micro-economic perspective.
I would like to see someone do it from a macro-economic point of view, even though I appreciate it would be less straightforward than the simple micro-economic one because some of the cost- and benefit factors that it would come into play would be less easy to quantify. The government should be doing this but to the best of my knowledge hasn’t done so to date, and in any case may well be disinclined to do so for any number of reasons that, while they may make sense to the decision makers, may not be to the best interest of the Province as a whole.
Following is a partial list of what I am thinking off :
– according to the CIBC the ‘double discount’ cost the industry $16BN in 2011 (and more in 2012)- my guess is that it therefore cost the government $5-6BN in lost revenues;
– more upgrading in Alberta would time generate more personal- & corporate tax revenues;
– the cost/risk of much of the oilsands becoming a “stranded asset”;
– the value of having a source of economic activity that will “bridge” the hiatus until more pipeline capacity becomes available (which in my opinion could be quite a while – but that’s an issue for another day);
– the greater efficiency & longer useful life of pipelines used for shipping out upgraded product rather than dilbit;
– the value of being less of a captive supplier & of having a more generally market-acceptable product to ship to a greater variety of markets;
– the PR value of reducing the effectiveness of environmental activists’ spectre of ‘black crud’ spoiling an otherwise pristine landscape (a spill of honey coloured lighter oil may be just as, if not more devastating, but doesn’t have the same emotional appeal – we have been genetically imprinted to equate “black” with “bad”.
I would be happy to follow this up with you, if you were so inclined.
Nick RvT
[…] economist Andrew Leach has looked at the economics of refining in Canada (here, here and here) and claims that producers can make more money by selling raw […]
[…] economist Andrew Leach has looked at the economics of refining in Canada (here,here and here) and claims that producers can make more money by selling […]