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“Conduit & Trucks.” A web of above ground thermal conduit piping typical of the SAGD operations throughout the oil/tar sands. This network is part of Suncor’s Firebag facility in Alberta. Louis Helbig | Beautiful Destruction


Black Snake in the Grass

The business case for new pipelines is terrible.

There has rarely been a worse time to build pipelines in Canada than now. One wouldn’t surmise this from listening to the business elites of Toronto and Calgary, gung-ho for the newly approved Trans Mountain expansion, Line 3 replacement, and Keystone XL. Yet, economic conditions have changed greatly since the Keystone XL was first proposed nine years ago.

There has rarely been a worse time to build pipelines in Canada than now. One wouldn’t surmise this from listening to the business elites of Toronto and Calgary, gung-ho for the newly approved Trans Mountain expansion, Line 3 replacement, and Keystone XL. Yet, economic conditions have changed greatly since the Keystone XL was first proposed nine years ago. The heated arguments surrounding the pipeline then cannot simply be warmed up again because the business arithmetic undergirding new export-pipelines no longer adds up like it once did. For all of the much-ballyhooed “public interest” that these projects supposedly represent, only a small segment of Canadian business will benefit and many pipelines will ship nothing but air.

Like the current Keystone pipeline, the proposed Keystone XL connects Hardistry, Alberta to Steele City, Nebraska, except by a more direct route. From there, the hydrocarbons would go to Cushing, Oklahoma, and from there, further pipeline additions already in place connect to port cities and refineries on the Gulf of Mexico.

The original purpose of the Keystone XL was to capture the highest possible price for tar sands crude. The US price benchmark, named the West Texas Intermediate (WTI), and the benchmark price of crude from the Brent North Sea field (a representation of international prices) have floated in tandem for decades, so in the past, it didn’t matter that landlocked Albertan hydrocarbons were sold at WTI prices. In the 2000s however, WTI and Brent began to diverge as production of Albertan bitumen and fracked petroleum from North Dakota and Montana increased faster than nearby refining and shipping infrastructure could accommodate. Greater demand than supply for pipelines and refineries in the middle of the North American continent gave pipeline owners leverage over tar sands producers, allowing them to dictate prices. As a result, WTI prices for hydrocarbons dropped, and the gap between WTI and Brent peaked in September 2011 at nearly $30, more than a quarter of a barrel’s price. Suddenly, there were two separate markets for petroleum.

Many pipelines from Alberta terminated in the small town of Cushing, Oklahoma. There, crude oil pooled in vast vats, sitting in queue until it could be shipped to the heavy-oil refineries ringing the Gulf of Mexico. Those with well-placed pipeline capacity could buy crude cheaply from the continent’s interior and ship it from the Gulf of Mexico to regions that paid international prices, like the US North-East because it was not connected by pipeline to Albertan and North Dakotan producers.

The Albertan commercial class and their allies within the provincial government fumed at subsidising US pipeline firms, refiners, and drivers in the Rocky Mountains states. The crash of petroleum prices in 2014 relieved some pressure on the WTI-Brent gap.

Barack Obama’s rejection of TransCanada’s application for the Keystone XL in 2015 led to a lull in the debate. Pipeline firms looked to slightly less contentious projects to ship product, such as reversing Line 9 even though it passes through major Canadian cities including Toronto.

Why then is there such enthusiasm to build new pipelines at all?”

Although the election of Donald Trump has breathed new life into the Keystone XL, the economic context that animated it in the first place no longer exists: the price gap between WTI and Brent has evaporated.

This is due to two reasons. First, new pipelines connecting the US Gulf Coast to its fossil-fuel-saturated heartland have been built over the past five years, such as the Seaway and Keystone XL South. Secondly, the US government ended its four-decade ban on petroleum exports in 2015 (originally, the US put the ban in place as a measure against oil scarcity, but that condition no longer applies). These two measures mean that it is physically possible to bring more petroleum to the Gulf of Mexico (instead of keeping it pent up in Cushing) and international markets could soak up this extra supply, equalizing the WTI and Brent indices. It now matters little if the tar sands product gets to the coast or not, since it will garner more or less the same price anywhere. Indeed, there is no point seeking the much-vaunted Chinese market, despite Albertans’ obsession with it, because the US hosts most of the world’s heavy-oil refiners (Canada’s oil is classified as a heavy oil). Mexican heavy oil gets eights dollars less per barrel in China than it does in the US because China has fewer facilities that can process it.

Without the need for new coast-bound pipelines, the existing Canadian infrastructure suffices to export all the bitumen that Alberta is likely to produce. There is no need to build any new pipelines at all. Even if tar sands production increases by another million (m) barrels per day (bpd), then Canada will still have a 16 percent buffer of excess capacity. In 2015, Canada exported 3m bpd, almost all to the US. The existing network can handle 4.1m to 4.5m bpd (estimates vary), and rail could carry another 0.8m bpd. Indeed, according to a report by the Natural Resources Defense Council, as recently at 2012, only half of Canada’s export-pipeline capacity was being used. Currently, tar sands operators can produce about 2.5m bpd and conventional petroleum output is 1.3m bpd. In a decade, however, I estimate conventional production will decline to less than a million bpd (since Canada is running out of conventional petroleum). CAPP predicts it will drop to 1.1 million by 2025. This drop in conventional production will free up space on the pipeline network, and domestic consumption will likely stay the same as now – to use roughly 1.2 m bpd of Canadian production. (Canada also imports about .7m bpd.) If one does the sums, it’s clear that current export capacity suffices.

“McKay River & Mine Expansion.” Forest-clearing, as part of a process known as overburden removal, in preparation for the expansion of the Syncrude’s open pit North Mine in Alberta. This clearing is immediately adjacent to the McKay River which flows into the Athabasca River at Fort McKay a settlement surrounded by industry on almost all sides. A further expansion known as the Mildred Lake Extension (MLX) is planned for 2018 and will include mining west of the Fort McKay River. Louis Helbig | Beautiful destruction

It’s quite possible for tar sands production to be fixed at this maximum, some 3.5m bpd, for a while. It is the limit at which the provincial carbon pollution cap of 100m tonnes will take effect. This was imposed by Edmonton in 2015 after negotiations with tar sand producers and the coalition of environmental NGOs who led the anti-Keystone XL campaign. Even if this promise was made insincerely, it is hard to imagine production increasing drastically anytime this decade. Tar sands projects are capital-intensive and take years to come online, so unlike the nimble fracking industry, it is easy enough to predict future production. There are few large projects proposed beyond the ones already underway due to depressed prices – indeed, some Big Oil firms have pulled out of Alberta including Statoil and Shell. As Rystad Energy, an independent oil and gas consultancy firm notes, “The contribution from unsanctioned [unapproved] projects is not likely to be visible before 2020, as operators postpone their final investment decisions.” Even the Canadian Association of Petroleum Producers (CAPP), the fraternity of tar sands bosses, has tempered its expectations of the rate for production in 2030 production from 5m bpd to 3.67m bpd – and CAPP tends to overestimate.

Why then is there such enthusiasm to build new pipelines at all? To answer this, one has to understand the role of pipeline firms within the broader fossil fuels market, and how their position shapes that market. Pipeline companies like Enbridge, Kinder Morgan, and TransCanada, want to go ahead and build infrastructure whether it’s needed or not because they signed long-term contracts with tar sands oil producers before the fall in prices in 2014. These contracts are very lucrative because they locked-in prices twice as high as today’s prices for sometimes as long as 25 years. If contracts were negotiated now, they would likely be worth only half as much. All of these firms would get paid by shippers, whether or not the shippers have fuel to ship or if it became cheaper to ship by another route. The share price of pipeline firms depend on these projects being realized.

The tar sands industry either remains silent or demonstrates its support of the pipeline industry when it proposes new projects because of their adversarial relationship. Even though there may be enough pipe to ship all of Canada’s hydrocarbon production, pipeline firms often have the upper hand in negotiations. Jennifer Hocking, an Albertan energy lawyer, interviewed several representatives from tar sands firms and found that in their opinions, “pipelines still hold a natural monopoly, and therefore the general absence of objections from shippers in tolling applications [the process of setting rates to use the pipeline] by pipeline companies to the National Energy Board (NEB) ought not to be taken as active support from the shippers for the tolls proposed by the pipeline company.” In other words, hydrocarbon shippers admit to feeling like they can’t oppose pipeline companies because they have a monopoly on the market.

Before 1997, pipelines were regulated like railroads used to be or the Internet today – as a “common-carrier.” This means that the owners of infrastructure could not discriminate between its users, but left capacity open to short-term contracts so firms shipped their goods when necessary. The slow shift since pipeline regulations were changed in 1997 has meant that more and more pipeline capacity is tied in long-term contracts, forcing firms to compete for space.

Today, of the four pipelines that bring petroleum out from western Canada, only one, the Enbridge Mainline, remains a common-carrier. Large producers buy up space on pipelines to ensure that they have space when they need it, something that seemed pressing during the bitumen bubble before 2014. The need to secure space on a pipeline was driven by the decreasing share of capacity set aside for short-term contracts, between a fifth and a twentieth. This shortage of common-carrier capacity is the true problem, rather than a shortage of space overall. Imperial Oil argued that “converting existing common carriage capacity to contract was inappropriate given the shortage in capacity,” Hocking reports that during the Trans Mountain expansion application to the NEB, Chevron, a multi-national oil corporation, argued that Trans Mountain was a monopoly. Despite these objections, the NEB approved Trans Mountain’s application.

Securing reliable space on a pipeline is especially important if hydrocarbon producers have to fulfill orders at specific times and places. For example, firms that hope to ship bitumen to East Asia co-ordinate the delivery of fuel through the Trans Mountain pipeline to arrive at Burnaby’s tanker terminal at the right time and in sufficient quantity when their ship arrives, otherwise the whole operation is moot. This need for certainty allowed Trans Mountain’s owner, Kinder Morgan, to extract higher prices for longer contracts. Kinder Morgan even tried to stop bidders from communicating with one another by including controversial confidentiality clauses in its contracts, hoping to extract a better deal by muddying the market. Although the National Energy Board (NEB) eventually responded to the tar sands producers’ howls of protests and forced Kinder Morgan to remove the clauses, it rarely pushes pipeline firms very far. When Total and Suncor complained that Kinder Morgan was using its monopoly power to gouge shippers because there was no fair way to determine prices, the NEB applied little more than a slap on Kinder Morgan’s wrist. The Canadian government seems unwilling to support its supposed favoured child, the tar sands industry, and instead aids the dominance of pipeline firms.

This favouritism stems from Ottawa’s dependence on pipeline firms. Only these firms have the expertise to build and operate such infrastructure, because Canada is one of the only countries that does not have a state-corporation-run pipeline network. In Canada, only private firms can get bitumen to markets, making the state and tar sands firms dependent on them. Transportation, after all, rather than production, is more susceptible to monopoly power. In another example of this, Standard Oil colluded with railways to dominate the petroleum industry; it actually owned relatively few wells. “Given the importance of the expansion to the Canadian economy,” Hocking ventures, “the NEB appears to have decided that it was appropriate to interfere as little as possible.”

Furthermore, it is doubtful if either Calgary or Ottawa take their climate change initiatives very seriously. Both would likely welcome higher petroleum prices and renewed investment in Northeastern Alberta. If that were to happen, new pipelines might be necessary, even if that might not happen for another decade or two.

Both the federal and provincial governments seem to be indulging in wishful thinking if they believe it was a shortage of pipeline capacity rather than petroleum’s price that has dampened investment in the tar sands. This line of thought is laid out by Jackie Forrest, a director at the ARC Energy Research Institute, “If we were in a scenario where we had excess capacity, you could make the argument that, all things being equal, you would see more capital invested here than what otherwise would have been the case.”

If all three recently approved Canadian pipeline proposals are built (Line 3, Trans Mountain expansion, and Keystone XL) export-pipeline capacity in Canada would increase by three-quarters. Even if the tar sands were ripping out 3.5m barrels per day (bpd) of fuel and there was another million bpd in conventional production, that still leaves a surplus of 2.7 million bpd in excess pipeline capacity. These underused new pipelines would remain a monument to carelessness; a frittering of twenty-five billion dollars of capital due to the NEB’s ineptly regulated faux market. Yet, the pipeline owners would be happy, for regardless whether their infrastructure is used or not, they will become fat from the terms of their pre-2014 contracts. Tar sands operators and the Canadian government would remain in a bind, but both would see the excess capacity as useful if the boom returns. If it does not, then eventually these expensive, underused projects might undermine the pipeline industry, weakening its grip over tar sands producers and the Canadian state. At that point though, all of these pipelines will have ripped up thousands of square kilometres of forest and poisoned too many streams, rivers, aquifers, and coastlines in a much hotter world.

Troy Vettese is a doctoral student at New York University, where he is writing a dissertation on the history of the tar sands industry.