After my post last night got me reading Budget 1980 and the National Energy Program, I stumbled upon something completely fascinating: the hated National Energy Program proposed an indexed price for synthetic crude from oil sands projects which, had it been followed until today, would have been above the Canadian dollar price of WTI in every year but 1980, 1981, and 2008.
By Andrew on August 8, 2013
It’s been a week since TransCanada announced that it had secured sufficient commercial commitments and would be proceeding with the Energy East project. Their announcement included a few surprises – a larger-than-expected capacity of 1.1 million barrels per day, and a $300 million marine terminal in Saint John. What follows is a Q&A addressing some of the fact and fiction that’s been tossed around this week.
Is this pipeline a done deal?
Not even close. Securing commercial commitments is an important step, but there remains a long process ahead. The project will still face at least National Energy Board approval, but more likely a federal joint review panel including both the Canadian Environmental Assessment Agency and the National Energy Board, similar to the proceedings currently underway for the Northern Gateway Pipeline. There will also be consultations with First Nations, negotiations with landowners with respect to the new sections of pipeline, as well as dealings with the 6 provincial governments affected by this project among other requirements. Provinces do not have to approve energy pipelines in order for them to be granted a Certificate of Public Convenience and Necessity by the National Energy Board, but the process will be much smoother for the proponent if the respective provinces are on side.
Will Energy East lead to lower gas prices?
The answer to this comes in two parts – first you need to ask what Energy East will do to crude costs for refineries across Canada, and then you need to ask whether such a change will alter gasoline prices at the pump.
Energy East will serve as a link between Eastern Canadian refineries and the western crude oil market, where crude oil had been discounted significantly since mid-2010 until these price differentials converged rapidly over the last couple of months. By providing this link, the pipeline will alter future differentials from what they would otherwise be. If we assume that the marginal barrel out of Western Canada is still moving by rail, then you would expect western Canadian oil to be priced at approximately $12-15 below prevailing prices at the coast, reflecting the cost of rail transport. In such a scenario, a refiner who owned firm shipping capacity on Energy East could purchase oil at Edmonton and deliver it to Montreal, Quebec, or Saint John at a lower cost than that at which they would otherwise be able to obtain oil. Refiners without their own firm shipping capacity on Energy East (or Enbridge’s Line 9) will continue to pay world prices for oil, regardless of whether that oil is Canadian or imported. If the marginal barrel is moving by pipeline, the difference between oil in Alberta and oil on the east coast is likely to be comparable to the shipping tolls on Energy East, and so running Canadian oil would not save refiners any money at all relative to running imported crude.
There is some evidence that recent crude oil discounts in Western Canada have been partially passed through to consumers through lower gas prices. Statistics Canada reported in The Daily in November that, “gasoline prices have increased at a slightly faster pace in the central and eastern provinces than in the west, resulting in a spread between some provincial gasoline indices…associated with the dual crude oil market in Canada and the recent price differential between crude oil benchmarks.” The image below shows that this pattern has continued for the last 6 months since the Statistics Canada report.
Source: Statistics Canada
However, you need to keep in mind that we are not talking about a systematic lowering of crude oil costs in eastern North America – we are talking about an increase in crude costs in Western Canada, combined with a potential small decrease in costs for some eastern refineries. As a result, you may see a small increase in refining margins for those refiners with firm shipping capacity on Energy East, along with a decrease in refining margins for in-land refineries in Alberta. If you’re going to see a change at the pump as a result of this project, I’d expect to see an increase in Western Canada rather than a decrease in Eastern Canada.
Will Energy East increase oil sands development?
As with the question above, this question should really be followed with an alternative scenario. If you evaluate Energy East against an alternative scenario where no other pipelines out of Alberta are ever built and no existing pipes are expanded, you could expect a marginal impact on future oil sands development. I say marginal because you simply can’t look at it as enabling 1.1 million barrels per day of new production which would otherwise not occur – you have to look at the impact on profitability between the two scenarios and ask whether that impact is sufficient to have an impact on the pace of development. For a bitumen project, the difference between pipeline and rail is small, once diluent transport is factored in. In order to ship a barrel of bitumen by pipeline, you’d need to ship 1.4 barrels of diluted bitumen, so if your pipeline heavy oil toll is $7/bbl, it is going to cost you $9.80 to get a barrel of bitumen from Alberta to Saint John. You can ship bitumen by rail with little or no diluent added, so the rail vs. pipe trade-off is likely to be only $3-5 lower netback per barrel. That type of decrease in expected profit certainly matters, but it’s not likely to reduce oil sands production by 1.1 million barrels per day.
You might argue that the rail system will, at some point, reach a capacity constraint. That’s possible, but unlikely. Despite all the attention to oil-by-rail increases, crude and fuel oil still only accounted for less than 5% of Canadian rail car loadings in May, 2013. Nickel, iron-ore, coal, and potash each accounted for more rail car loadings than crude oil. Access to pipelines matters, but given the alternative of oil-by-rail, the profitability impact is not as large as some have made it out to be and that’s what will drive development.
Should we have built this pipeline a long time ago?
There’s a strong nationalist element which seems to think we’d be somehow better off had we not been importing oil on the east coast while exporting oil from western Canada to the US Midwest. That sentiment ignores the market reality for much of the last 25 years. Here’s an admittedly simple simulation using crude oil prices since 1987. Assume you could have built a pipeline and put it in service from Alberta to an eastern refinery center, with a pipeline toll of $7/bbl in today’s dollars, adjusted for inflation (the toll would have been $3.89/bbl in 1987). Assume that your alternative project would have been the Keystone Pipeline to Cushing, with tolls equivalent to today’s tolls on that line to Cushing, OK, again adjusted for inflation. Now, here’s your choice – you can either ship your oil to Cushing, and sell it there and use the revenues to buy oil on the east coast, or you can ship your oil all the way to the east coast, and sell it (assumed price of Brent +$1.50). (the simple part of this simulation is that I’ve assumed that prices in Cushing and in eastern Canada are not affected by your choice). The Figure below shows how much you would have lost on every barrel if you chose the Canadian option.
From 1987 to 2010, you’d have been better off in every single month making the trade we have been making – exporting to the US Midwest and importing on the east coast. In fact, the from May 1987 to May 2013, the average loss from shipping 1 million barrels per day of oil east rather than south would have been about $250 million per month in today’s dollars. If you assume you could have moved it east for free, you’d have still lost money, although not much of it.
The oil market in North America has certainly changed, and the expectation is that the marginal barrel will be moving to the coasts, so oil in the mid-continent will no longer trade at a premium as it has. As a result, the economics of Energy East are likely better today than they would have been at almost any point in the last couple of decades. It’s certainly the case that perfect foresight would have led to more pipelines being built to the coasts instead of to the Midwest in the late 2000s, but not before that.
By Andrew on August 4, 2013
Today, what I initially thought was a mildly controversial statement about upstream vs. downstream profitability and value-added led to me finding myself with a little bit of egg on my face and also completely baffled about the way we use the term value-added.
Let me start off by saying that, as a economist, I tend to think of all resources as having an opportunity cost. In rare cases, that opportunity cost may be zero or close to it, but there are very few inputs to production which exist in infinite supply. Some things are certainly priced well below their actual opportunity cost, but we’ll get to that later.
When I think of the term value-added, I’ve always defined it in a real sense – the value of the product, net the value of the resources used to produce that product. It turns out that matches Statistics Canada’s definition which states that value added is, “total output (or sales) less intermediate inputs.” In such a calculation, I’d take as given that labour inputs have a value (perhaps reflected imperfectly by wages paid), capital has a value, and resources such as oil, gas, pollution releases, or water used have values as well (even if these are not usually priced efficiently). I’ve been scornful of those who confound this definition of value-added with the production of higher value products too many times to count.
Why do I have egg on my face? Well, after I posted the initial tweet, Erin Weir and Ian Gillespie both jumped on me for confounding value-added and profit. I went off to the Economist to arm myself with a useful definition for the argument and here’s what I found: “the value of the firm’s OUTPUT minus the value of ALL its inputs.” I thought I was on solid ground, but I missed the next line. “It is therefore a measure of the PROFIT earned by a particular firm PLUS the wages it has paid.” This baffled me, since I tend to think of labour as an input to production and treating all wages as added value assumes implicitly that the labour input itself has no value or opportunity cost.
I thought this could not be right, so I jumped over to Industry Canada and sought out a definition of manufacturing value-added. It turns out that this definition applies here too. “Manufacturing value-added consists of the value of manufacturing revenues plus net change in the inventory of goods in process and finished goods, less the costs of materials and supplies and of the energy, water and vehicle fuel used.” So, energy, water, fuel, materials and supplies all count as valuable inputs to production, and are deducted from revenues to yield value-added, but wages paid to labour (as though somehow that is not the purchase of a valuable input to production) are left out of the net calculation.
The final nail in the coffin came from Mr. Gillespie, with a link to StatsCan’s Guide to Economic Accounts, which makes it very clear that value added is defined gross of labour income. It turns out that Erin Weir actually put it well when he described the wages as being the part of value-added which is distributed to labour.
As Erin Weir suggested, I shouldn’t try to redefine value-added, so I won’t go that far, but I will suggest that treating labour as different from other purchasable inputs ignores its opportunity cost (at best, it ignores the value of leisure or the foregone potential productivity in non-labour market roles). In other words, from the national accounts’ definition of value-added, the opportunity cost of labour is an externality – it’s a cost which is borne by someone (the worker providing labour to a given activity) but which is not reflected in the measure of value-added. Wages are not gifts, but rather payment for services provided and I would humbly suggest that they should be treated as such.
Now, I have always been on the wrong side of national accounts because of my focus on environmental and energy economics. In this respect, there are clear externality problems in that the measures of value-added we use do not include non-priced inputs to production such as emissions (waste disposal service) or potentially under-priced inputs (resource royalties which do not reflect the true opportunity cost of the resource being provided to the extracting firm). It had not occurred to me that these calculations also implicitly treated the opportunity cost of labour as zero – it just seems un-natural. That raises some serious questions, so I guess it’s off to do some reading. Perhaps there is something I am missing in space between micro and macro.
Thanks to Erin and Ian for the challenge. I learned something today – normally I’d say that was value-added for your time spent arguing with me, but I don’t think I can say that with any confidence now.
By Andrew on July 19, 2013
I read Dan Healing’s article on the CNRL surface emulsion release incident at Primrose/Wolf Lake, Emma Pullman’s DeSmog Blog piece, and the Alberta Energy Regulator’s news release release. I’ll admit I dismissed it all at the time – sounds like an isolated incident, I thought – and I assumed it was from a well-head or pipeline. I didn’t make much of it. Today, Ms. Pullman called me for a comment on her story in the Toronto Star, and that triggered me to dig into this a little more. What I have found so far is not encouraging. I think I should have paid a little more attention a while ago.
First, a little background. Primrose and Wolf Lake is an in situ oil sands production facility. Unlike many new facilities which use steam-assisted gravity drainage (SAGD) technology, Primrose and Wolf Lake relies on cyclic steam stimulation (CSS), or huff and puff technology, where a single well is used both to inject steam to heat the bitumen and for bitumen production, in cycles. A variant of this technology, high pressure CSS (HPCSS), uses pressurized steam to penetrate deeper into the reservoir, accessing more bitumen.
It turns out that the issues at Primrose with respect to surface emulsion releases are not new. As Dan Healing points out, this incident, “appears similar to one that occurred at the same project on Jan. 3, 2009.” If you dig into CNRL’s performance presentations, you can get a timeline for this first event. Here are the key events for the previous incident:
- Jan. 1,2009 – steaming / producing 1st cycle in 4 pad ( 80 well ) development
- Jan. 3, 2009 – bitumen emulsion flow to surface discovered on Pad 74 ; steam injection shut in and ERCB notified ( ERCB Incident 20090005 ) Note – ERCB’s role has now been assumed by Alberta’s Energy Regulator.
- May 4,2009 – submitted Pad 74 Interim Investigation Report
After completing the Interim Investigation Report, CNRL continued to undertake a series of diagnostic steaming tests to try to diagnose the issue which was allowing bitumen to escape to the surface. All of the results of these tests were shared with the regulator and new rounds of testing were periodically approved through 2009. This so-called static investigation was followed up with a more detailed dynamic investigation which lasted through August 2010. At the end of this investigation, in February 2011, CNRL submitted its final incident report to the then-regulator, the ERCB. The ERCB completed its analysis and the ERCB (PDF) and CNRL reports were released to the public (PDF) in January, 2013 (the link to the CNRL investigation report appears to be broken). The ERCB’s key regulatory action was to put limits on the steam injection volumes allowed at Primrose East.
Yesterday, the regulator announced that it was imposing further steaming restrictions and increased monitoring requirements on CNRL at Primrose South in response to the recent emulsion release. From what I can tell from the documents I’ve gone through this evening, this incident has the potential to have significant implications for both the regulator and for CNRL. The important caveat here is that you’re dealing with an economist with no training in geology (I took a computer programming class instead of Intro to Geology), so take what follows for what it’s worth.
First, we still don’t really know what happened the first time. The ERCB’s report makes it clear that, while CNRL proposed three scenarios for what might have allowed the initial bitumen emulsion release in 2009, “a detailed flow path could not be determined with certainty.” The ERCB concludes, based on the evidence, that, “it is likely that the Clearwater shale was breached by high-pressure steam injection not related to a wellbore issue,” and that a pathway to the surface, “likely involved a wellbore or a series of pre-existing faults.” My reading of this is that the investigation was inconclusive, so it was not possible to say whether similar incidents would occur in the future under similar conditions. The ERCB eludes to this in its conclusions, saying that, “the ERCB continues to review and assess its requirements with respect to both caprock and wellbore integrity issues,” broadly in similar production facilities.
Second, the ERCB concludes that there were likely some operational decisions which contributed to the 2009 release. In particular, the ERCB found that, “steam volume injected…was significantly higher…than past HPCSS operations at Primrose due to reduced well spacing. This likely contributed to the bitumen emulsion surface release.” The ERCB reports that, “CNRL stated that a localized weakness in the Clearwater shale may increase the potential for a breach by high-pressure steam when the injection volume is larger.” So, this leads to a couple of further questions: was the injection volume again increased above that of past operations at Pad 22, involved in the most recent release, and/or does this release indicate that caprock integrity issues are more pervasive in the Primrose subsurface?
In its report, the ERCB found that, “HPCSS can be safely conducted at Primrose East.” Hopefully we will not have to wait 4 years to find out what’s happened this time, what the causes may be, and what implications that has for future production at Primrose and for in situ production in Alberta in general.
By Andrew on July 8, 2013
The scale and scope of the terrible tragedy in Lac Mégantic, Quebec is only begining to sink in, and my thoughts are certainly with the victims and their families at this time.
In the midst of the shock and sadness of this event, already there are those who have concluded that this is an advantage for the pipeline industry. I strongly disagree, and I say so in this post at Macleans.
By Andrew on July 5, 2013
Last night, Darcy Henton filed a story which detailed a memorandum of understanding between the Alberta government and TransCanada with respect to the proposed Energy East Pipeline from Alberta to Eastern Canada.
“The province has signed a memorandum of understanding to take up to 100,000 barrels-a-day of firm capacity on TransCanada Corp.’s proposed Energy East pipeline.” –Financial Post, July 4, 2013
I think there are three things people need to consider when evaluating this decision. First, this is not an equity stake in the pipeline or a financial contribution, but a promise to pay for shipping on the pipeline if it is built. Second, Alberta’s move will not in and of itself enable this project. Third, the government of Alberta takes bitumen (and conventional oil and gas) royalties in kind, and their responsibility is to market those products to maximize the value to Albertans. In that sense, what matters is what happens to the oil once it gets east.
What has the government signed? They’ve signed a memorandum of understanding to take up to 100,000 barrels per day of firm capacity on the line if it’s built. What this likely implies, having not seen the MOU, is an option on a take-or-pay contract for shipping services. Under such an arrangement, the government would commit to paying the shipping tolls for up to 100,000 barrels per day regardless of whether or not they actually moved that much product – it’s a subscription service. The government is not taking an equity stake in the pipeline, and will not have to pay anything if the pipeline is not built. Alberta is a player in this market, and there is no escaping it. The Alberta government expects to receive over 200,000 barrels per day of royalty bitumen (PDF) by the time Energy East is in service. They have a couple of choices with respect to shipping – they can sign firm shipping agreements, or hope there is capacity available if they wait for spot shipping at time of receipt. The government has chosen a lower-risk option, but Albertans should ask whether this is the best low-risk option for the government among the many pipeline proposals currently looking to move oil to tidewater from the mid-continent.
There is some risk to the province, which Richard Masson outlines well in the Henton article. First, Energy East may end up being an expensive option. If the tolls are higher on Energy East than on other systems serving similarly priced markets, the netback to Albertans will be lower for shipping on that line. The province is also subject to market risk, in that prices on the Atlantic coast may not be higher than other pricing points by the time this line is built. I also argue below that they may have increased political risk by going east.
The approval process for a project like Energy East requires the proponent, TransCanada, to demonstrate the need for the pipeline – in short, to show it will operate near capacity and will not simply remove product that would otherwise be shipped on other lines. This process is designed to avoid what Richard Masson discusses in the Henton article – too many pipelines. Generally, firm shipping agreements are the way in which a pipeline company demonstrates that need.
The Energy East proposal is expected to move north of 800,000 barrels per day of product, so the 100,000 MOU from Alberta will not in-and-of-itself make the project viable. In other words, this is not akin to the Northwest Upgrader processing agreement, in which the province single-handedly enabled the project by signing-on. On the other hand, if the province decided not to become involved in the firm shipping market, they would distort the signals received by the regulators in terms of the demand for shipping services, leaving the system short of capacity and lowering the value of Canadian oil in the process.
Now, what worries me about this? I’m worried about what happens to the oil at the other end of the line. The Alberta government’s responsibility is to maximize the value of the resource, and so they must recognize that in-kind oil has a value, and treat it as they would cash. Don’t give someone discounted oil if you wouldn’t give them money, plain and simple.
We’ve seen a lot of discussion of the potential for Energy East to preserve or create refinery jobs in New Brunswick. This is where Albertans should be concerned. If the purpose of the pipeline, from a shippers perspective, is to get world prices for oil, then why would this have any effect on refinery economics in Saint John? They can already access world prices for oil as they are on a port. If the presumption is that, as part of gaining support for this pipeline, the Alberta government is prepared to market barrels at prices below what they would fetch at market, that’s another kettle of fish.