This week, the question of whether or not and, if so, how, the Government of Alberta should encourage upgrading and/or refining of bitumen in the province is back on the front page. Much of this coverage is due to backlash over the Government’s decision to not proceed with the Alberta First Nations Energy Center (AFNEC) under the Bitumen Royalty in Kind (BRIK) program. There are as many myths as ever bouncing around this, and so I’ve spent the last little while trying to untangle them for myself. Here are some thoughts and, as always, your comments and clarifications are welcome.
What was the proposed project? The project would have processed 125,000 barrels of bitumen per day, producing diesel fuel, jet fuel, gasoline, and other refined products. The price tag for the project has been published at $6.6 billion, or $52,800 per flowing barrel of production. For what it’s worth, that figure seems staggeringly low given the price tag for the Northwest Upgrading integrated upgrader-refinery is estimated at a little under $5 billion, or $100,000 per flowing barrel, for a facility less than half the size. It’s likely that uncertainty over these capital costs was one of the stumbling blocks in finalizing the deal – more on that later.
Would this facility have made money? Well, that’s hard to say – if I could predict oil price spreads, I’d be rich. If they could meet their capital cost estimates, and guarantee last year’s spreads between the value of refined products and the value of bitumen, they almost certainly would. Even at NWU’s capital costs, the historically high spreads seen last year make a refinery project look very attractive – the question is whether the government should be betting on those spreads.
As you can see from the Figure below, price spreads in regions where prices are set based on WTI (the benchmark against which Alberta crudes are generally priced) have been historically high over the past 2 years (see here for a longer history of light:heavy differentials in Alberta), and this is compounded in Alberta due to discounts applied to our crudes relative to WTI, and larger discounts applied to Alberta heavy oil and bitumen relative to light-heavy differentials on the Gulf Coast. The bitumen spreads are positively massive, estimated at over $70/bbl in the previous month, and that’s simply a difference to a barrel of Brent Crude – the added value of the refined products would add another $10/bbl.
FirstEnergy Capital, Integrated Oils, Large Caps, Oilsands - Crude Price Differential Sensitivity, February 2012.
This graph should make every single Albertan very angry – your natural resources are being sold at prices up to $40/bbl below comparable world prices. Unfortunately, anger does not always make for the best decisions. You can likely build a refinery anywhere on the planet and make money with an $80/bbl bitumen:diesel spread, but that doesn’t mean we should build more refineries in Alberta today. A refinery is not a short term investment, so you can’t make a decision based on today’s spreads.
To get a sense of where that spread would have to be in the long term in order for these operations to make money, you have to start with the capital cost. If we assume that you can build the facility for $52,800 per flowing barrel, as the published AFNEC claims suggest, you’d need to earn $15.94/bbl based on a 25 year amortization. Add another $2.41/bbl for each additional billion dollars in capital cost, again based on the AFNEC 125,000 barrel per day facility. You’d then need to cover energy and non-energy operating costs as well as any sustaining capital expenditures. We don’t really have a perfect benchmark for AFNEC operating costs, but assuming they are close to comparable integrated facilities such as Cenovus’ Wood River and Borger refineries, $7-9/bbl in operating costs is likely a lower-bound. With an assumption of another $5 in sustaining capital expenses (someone please fill in the blanks with a reliable number I should cite for this), you are breaking even at $30-32/bbl, assuming a 10% cost of capital throughout.
Where have spreads been historically? Since 2006, the average 3:2:1 crack spread, which is an approximation for the gross return to a refinery’s output, has been US$10.39/bbl on the Gulf Coast, and a little higher than that in Chicago. Add to that, the average price at which heavy oil has traded at Edmonton relative to light oil of CDN$17.14/bbl, and you start to see why the investment is risky. For all intents and purposes, if the Edmonton bitumen to global gasoline price spread averages what it has for the last 7-10 years, you’d be barely in the money with a commercial upgrader/refinery in Alberta, assuming your costs stay competitive.
The last sentence above is crucial, since trends and policies suggest that neither will be the case. The WTI-Brent spread is at historic levels, and so projects both in Canada and in the US including but not limited to the Keystone XL and Northern Gateway pipelines are aimed at narrowing it. Most forecasts expect the WTI-Brent spread to be under $10/bbl by the end of the decade. As the light-oil differential narrows, so too will the discount to Alberta bitumen relative to other crudes. The heavy discount in the Midwest will also narrow as new coking capacity is added at Wood River and Whiting, among others, but will tend to expand as more bitumen production comes on-line in Alberta if pipelines to new markets are not built. Of course, it’s also difficult to assume that operating costs in Alberta will not increase rapidly, or that capital costs are not going to be subject to escalation.
The combined price and cost risk explains why the NWU contract was not simply a contract to provide Alberta bitumen via the BRIK program, but rather a cost-of-capital and cost-of-service processing agreement. Under the BRIK program, NWU does not take significant spread risk – they will be a regulated utility processing bitumen. The same would have likely been true for AFNEC, although the specific details of the agreement have not been released. What does that mean? Under the terms of the contract with NWU, the Government guaranteed that the proponent would receive a 10% return per annum on prior capital costs of $329 million plus facility construction costs of up to $5 billion, and that they would be reimbursed by the Crown for operating and sustaining capital costs as long as those costs do not exceed specific benchmarks. In other words, the downside risk that the spread collapses is borne by the government, not by the refiner, since they would still be paid to process the bitumen even if they were doing so at a loss. It seems to me that this type of long-run oil price arbitrage is not where the Government should be. We’re already leveraged to oil prices – why double-down on a spread?
I’d be happy to see more refining done in Canada, either in Alberta or elsewhere, if the comparative advantage is there but I think we need to look at it like any other industry. In the same way as I would be hesitant to say that Ontario should agree to guarantee the rate of return and operating costs of an automobile assembly plant, I don’t think Alberta should be doing so for a refinery. If the government were proposing to hire workers at market rates, and sub them out to a refinery or any other industry at a discount, people would likely scream and yell. Somehow, the same reaction is not present when the conversation turns to the government providing bitumen at below market rates, or taking on downside risk to make a business work. In the budget, at the end of the year, it amounts to exactly the same thing.
I do think Alberta should take a hard look at why were are selling our natural resources at far below their global market price and ask whether this is entirely due to infrastructure constraints, but that’s not an excuse to decide that we should instead look to sell our natural resources at below the global market price to encourage domestic processing. We should look to get the maximum value for our natural resources, not look to apply the maximum processing before export or look to offer a hometown discount.
I do think Alberta should take a hard look at why were are selling our natural resources at far below their global market price and ask whether this is entirely due to infrastructure constraints, but that’s not an excuse to decide that we should instead look to sell our natural resources at below the global market price to encourage domestic processing.
Right, we should instead look to sell our natural resources at below global price to encourage foreign processing. Oh wait, that’s obviously what we are doing.
As always, I look forward to the evidence to support your assertion that preferential pricing of resources exists for those who process abroad rather than in Canada.As always, I also expect none to be forthcoming.
My proof is, “…your natural resources are being sold at prices up to $40/bbl below comparable world prices.” Clearly we already are discounting it to sell it abroad for processing.
Great proof. Unfortunately, the royalty regime disagrees with you, as the resources are generally “sold” at a cheaper price if they are processed here, given the royalty treatment of integrated extraction and upgrading facilities versus extraction here combined with refining elsewhere.
Thanks.
The simple killer argument, of course, is that if there was easy money to be made in upgrading in Alberta then the companies would already be doing it. The $20-bill-on the-sidewalk-argument.
I assume that it’s cheaper for others to upgrade Alberta’s bitumen because they have spare capacity, their capital is sunk and the operating costs are low (especially with the low price of natural gas today).
My question: how much spare upgrading capacity is there in the US (or the world) and when will it be used up? Will the extra supply from KXL (if it’s built) be enough to use up that capacity in the US?
YEs, that’s right. It’s hard to say how much spare capacity there is likely to be into the future, since many refineries currently incapable of processing Alberta bitumen can be retrofitted. That’s what you’re seeing with BP Whiting and COnoco/Cenovus at Wood River among others. Those tend to be cheaper on a per flowing barrel basis than building a new, greenfield site. FirstEnergy Capital has some good analysis of US refinery stock which is capable of processing AB bitumen now, and some of the planned refits.
Andrew
One other factor to consider is that we’re running out of condensate to dilute bitumen for pipeline shipment elsewhere. That’s why Northern Gateway proposes importing condensate — from Tanzania or Qatar! — and piping it to Alberta, then shipping the 30/70 blend back over the mountains and across the Pacific. One calculation in the NEB filings estimates this reduces the energy return on energy invested (EROEI) from about 6 for upgraded crude in Edmonton to about 2.4 landed in China, largely because of the double shuttle of condensate. I don’t know what it does to the dollar economics, but surely there would be big savings in capital and operating costs if the trans-oceanic and trans-montagne condensate shuttles were eliminated. It would also substantially reduce tanker traffic in the Douglas Channel. I think there’s a strong strategic case for building sufficient refining and upgrading capacity so that refined products and synthetic crude could replace condensate as diluent. This should be part of any “national energy strategy.”
Good question. Yes, there is a tradeoff with sourcing and recycling condensate for diluting bitumen, and not doing so would entail lower shipping costs, but not necessarily lower total costs of delivering the product to market. The tradeoff is between upgraders/refineries here and more pipeline and transportation infrastructure, and right now the financial calculations come back in favour of shipping dilbit. If you change the regulations and require upgrading, given current financial conditions, you’d de-value the bitumen feedstock by imposing costly constraints on how it’s used. Not sure why that should be part of an energy strategy.
Andrew
I haven’t thought this through, but it’s worth noting that BC imposes a levy on export of raw logs. What does a levy on export of raw bitumen do to the equation?
If we feel that others are profiting on market imperfections and earning excess rents from Alberta bitumen, we should increase the price we charge for bitumen to capture those rents, but we should not do it under the guise of encouraging more processing here. The argument that we should not let others earn windfall profits on the processing and resale of our resources is valid on its face, without the upshot that we should do more processing here.
If not here in Alberta, how about upgraders in Prince George and/or Kamloops? They’ve got hydro and natural gas for energy and hydrogen, and could ship a cleaner product down the line and across the seas. They’re even closer to markets for sulphur. That way BC could get some of the benefits missing from current proposals. Right now energy strategy seems to be dictated by the interests of Houston and Beijing, and it would be nice to put Canadian interests first.
The upgraders at Lloydminster and Regina could also be expanded so we ship higher value products east and south. And it’s worth remembering the original Cold Lake project included an upgrader.
As you can tell, this condensate issue really bothers me. There should not be such a huge disconnect between the energy economics and the dollar economics.
Again, I am not against upgrading in Canada, but I am against disguising a subsidy for upgrading as a trade barrier on bitumen. By doing so, you implicitly discount the bitumen for provision to domestic suppliers. If people can work through a full value accounting, including the losses associated with the foregone value of bitumen and accounting only for net changes in labour surpluses and taxes, go for it – you might even be able to make a case, although I am not sure why it would be better for the gov’t to subsidize refining vs. some other industry. You bring up the example of the lloyd upgrader, which is a perfect example of the problem with trying to force water to run uphill. If there’s no free lunch there, it’s not a windfall but a transfer – from the people who own the oil (the Crown) or the people who pay for the upgrader/take the risks (tax payers in this case) to the people who work to process it and who own the facility. Good for some, but bad for others, but usually net negative.
The condensate issue, in and of itself, shouldn’t bother you too much. Sure, it lowers the EROI, but as you correctly point out, what matters with all products including energy products is the value at market. You can’t judge an energy source purely by GJ, in the same way as you can’t judge a car by HP or a book by the number of pages – it’s one factor among many. Sure, the N/A gas market is out of sync right now relative to world prices, but long term differences between value/GJ don’t reflect a market that isn’t working.
Thanks for reading.
Andrew
Hi,
Can you please tell me where you are getting the numbers 6.6 billion and 5 billion, respectively? I am preparing a report on refining in Alberta and I have had a hard time tracking down the actual capital costs of these projects.
Regards,
Tanya
I don’t know whether this discussion is still open.I stumbled on this site looking for the difference between upgrading and refining. Surprisingly, he majority of people don’t know the difference.
I don’t feel the broad overall picture is being considered in this discussion.
I know refineries cost billions of dollars to build.
But isn’t shipping the resource to another country and then buying the finished products (that used the raw material) back in the form of manufactured products ultimately more expensive?
After all: Resource $ sold = finished $$$ paid.
What happens to the economy of Canada when we sell all our natural resources abroad? No country has grown great economically selling its natural resources to other countries.
In other words use our natural resources for education, manufacturing and research to create an extensive and ongoing economy. When the economy gets better in the next five years the price of a barrel of oil will rise to $200 – $300. The Asian manufactured products shipped back to us won’t be so cheap then.
Let us start now to prepare for the inevitable.
I don’t know if the conversation is still open but I have been looking for answers to the upgrading dilema
I am having trouble understanding the upgrading issue particularly with respect to the Gateway project .I have sent information requests to several organisations including the CAPPtains of industry without response . I thought that Andrew with his extensive background would be able to answer the questions .
The project in its current form appears based on poor financial economics , poor energy economics ,inadequate engineering and questionable politics .
The concept of moving oil to Asia to diversify the market for Alberta resources is an excellent idea but it should not be shipped as dilbit. An upgrader should be built in Alberta ( or BC)and it would :
-save at least 10 mega tonnes of ghg emissions/yr in reduced pumping , unloading, and loading energy
-require one 750 mm D pipeline instead a 500 mm and a 900 mm. This would reduce the steel required by at least 50% and the associated costs and GHGs
-provide thousands of incremental man years or construction jobs
building the up grader and hundreds of permanent jobs running the upgrader
-provide an attractive investment for the CAPPtains of industry
-utilise and remove from the AB/ BC gas market about 0.5 bcf of gas per day (similar to a small LNG plant without the requirement for liquefaction)
Something appears to be skewing the economics and I suspect it is the involvement of a large SOE. GHGs , helicopter economics and job creation are not a concern of Enbridge but they should certainly be of concern to the Alberta and Federal government. If rational economics do not prevail in the current environment then one would hope that the governments would provide the carrots and sticks to alter the economics .They are currently providing a billion dollars for CCS . If the upgrader option were chosen there would be a savings of 1/3 of the GHGs that the Quest project will pump into the ground and at no cost to anyone
I note that there has already been a casualty of the skewed upgrader economics and that is the cancellation of the Suncor Upgrader.I was hoping that there may be more rational economics that would prevent the loss of these opportunities
Actually, I think if you have a look at the life-cycle GHGs, you’ll see that the produce-upgrade-ship-refine pathway generally has higher GHGs than the alternative of either shipping as dilbit and running through a full-conversion refinery. The reverse would be true if you were upgrading all the way to refined product at site in McMurray, but you’re fighting significant cost pressures to do that. I can’t see how the SOE involvement in Gateway is relevant here.