A collection of farmers and local landowners packed a conference room in June at the Lakeview Inn & Suites in busy Fort Saskatchewan just east of Edmonton. They’d come to watch Alberta regulators mull over another application for a bitumen megaproject in their community. The public hearing also served as a startling reminder that Alberta’s bitumen boom is unsettling far more than the boreal forest north of Fort McMurray.
The scale of the project was, like everything about the oilsands, otherworldly. Petro-Canada explained that it would take about eight years to build its Fort Hills Sturgeon Upgrader on a nine-square-mile plot of farmland just east of Edmonton at a cost of $14.1 billion. During peak construction, the plant would employ about 5,000 workers and require a camp on-site for workers. Once finished, it would transform a piped stream of heavy bitumen (oil mixed with sand, clay and heavy metals) from Fort McMurray into 280,000 barrels of synthetic crude every day. Over the 30-year life of the project, the upgrader would pour $8.9 billion and $17 billion into provincial and federal coffers, respectively.
The locals didn’t contest the project’s economic benefits, but they did raise questions about the province’s ability to handle its environmental costs. In particular, opponents focused on current air quality as well as the competence of an industry-funded local monitoring program run by volunteers. Donald Blake, a leading expert on air chemistry at the University of California,–Irvine, testified before Alberta regulators that the region already had pollution comparable to Mexico City’s, one of the world’s dirtiest. “It’s not the air quality I’d aspire to,” Blake told the Energy Resources Conservation Board.
That’s just one small scene from the sprawling and uncertain saga about what to do with the growing volume of bitumen being produced in northern Alberta these days. By most estimates, the bitumen boom will grow from one million to three million barrels a day over the next decade. Officially, the provincial government would like to upgrade and add value to more than half the resource in Upgrader Alley before exporting it.
But in reality, the marketplace, Canadian pipeline companies, U.S. refineries and many Canadian producers are busy making their own billion-dollar plans. Some analysts think the ball has already rolled out of Alberta’s court. “The decisions have been made; they happened over the last year. Many of the pipelines have been approved,” says Steven Paget, an analyst at Calgary-based FirstEnergy Capital Corp. In other words, huge volumes of Alberta’s bitumen now seem destined to become another Canadian raw staple for export.
But first a word about dirty bitumen. It is an extremely heavy, poor-quality product, so rich in carbon and so poor in hydrogen that it can’t be processed at an ordinary refinery. “First you have to upgrade it to make a lighter product. That takes time, money and energy. And then you have to refine it more, and that takes more time and money,” explains Martin King, a commodity analyst at FirstEnergy Capital.
Bitumen’s ugly and capital-intensive character explains why, until recently, the resource often sold at half the price of conventional oil and why its pricing is 63% more volatile than benchmark West Texas Intermediate crude. A 2007 report by Alberta Energy noted that “the markets which Alberta crude can currently access do not have sufficient heavy oil conversion capacity to always ensure good prices for bitumen.” But that reality is changing.
The argument for processing bitumen in Alberta’s Upgrader Alley, an area about three-quarters the size of Edmonton, is multifaceted. The region already boasts the nation’s largest petrochemical complex and can draw on Edmonton’s labour and infrastructure. A $50-barrel of bitumen can easily become a $200-barrel if its residues are broken down and refined into more than 50 chemicals, explains Kyle Reiling, co-ordinator of business development and investment for Strathcona County, which occupies much of the region. “We own the resource, and we should add the value here in Alberta.”
A 2006 study for the Alberta government by Houston engineer David Netzer concluded that a cluster of upgraders made good sense because it would create operational synergies and lower costs. As a result, more than $50-billion worth of upgraders and supporting projects have been proposed for the region. “But they are not done deals,” says Reiling.
In fact, the province’s tight labour market, rampant inflation, overstretched infrastructure and high material costs have already put many projects “out of control with no signs of gaining control,” says Dennis Dembicki, an oilsands consultant who has worked in the petrochemical industry all his adult life. “My friends are pipefitters and millwrights, and they tell me they are installing the same pump three times on a project because it wasn’t well thought out,” he says. “We might as well be burning money on some of these projects.”
Dembicki argues that Alberta’s current emphasis on rapid oilsands production driven by cheap economic rent (low royalties) has made the province so unattractive, from a cost point of view, that much of the bitumen upgrading will eventually migrate from Alberta to lower-cost U.S. locations. “And when you sell a valuable resource cheaply and the buyers take it elsewhere to refine,” says Dembicki, “all the benefits and jobs are exported with the bitumen.”
The upgrader boom has already become an uncertain enterprise in Alberta. Two approved upgraders, North West Upgrading Inc. and BA Energy, have virtually stopped construction and are now searching for new investors. Plans for Total’s $8-billion project and Statoil’s $16-billion project have been delayed for two years, while Shell Oil is now reviewing bitumen options for a second upgrader at its massive Scotford complex. Even Petro-Canada told Alberta regulators that, at the end of the day, it might not build in the province, either. Within a couple of years, the price differential between bitumen and conventional crude may narrow to such a degree that the economics of upgrading in Canada may deteriorate further.
Meanwhile, pipeline companies have announced plans to spend US$31.7 billion to export and distribute bitumen across the United States to replace declining oil supplies from Mexico, Venezuela and Saudi Arabia. To date, the federal oilpatch regulator, the National Energy Board, has already approved three massive pipelines that will move 1.6 million barrels of raw bitumen daily to the U.S. Midwest, Canada’s traditional oil market.
The $3-billion Alberta Clipper project, the largest expansion in Enbridge Inc.’s history, will send bitumen-based product from Hardisty, Alta., to Superior, Wis., while TransCanada Corp.’s US$5.2-billion Keystone Pipeline will take the tarry substance from Hardisty across six states to Cushing, Okla. A proposed US$7-billion expansion could send the product to refineries on the U.S. Gulf Coast. Enbridge and ExxonMobil Corp. have also proposed to ferry more bitumen-based products to the Gulf via the Texas Access line from Patoka, Ill.
And that’s just part of the pipeline bonanza that involves more than 36 projects. Enbridge’s Southern Lights Project, for example, will ferry diluent (light oil) from the Chicago area back to Alberta to make all of these bitumen exports possible. Given bitumen’s crudely thick nature, the heavy hydrocarbon can’t move through a pipeline unless blended with light oil or condensate made from natural gas. As one report put it, the Southern Lights pipeline will be “an enormous bitumen exporting conveyor loop,” that will help the United States motor raw bitumen south.
But the limited availability of diluent may slow down the shipment of bitumen south. In its 2008 crude oil forecast, the Canadian Association of Petroleum Producers advises that “diluent supply will not be sufficient to meet the needs of growing bitumen production.”
Still, there are ambitious plans to export bitumen even further abroad. Enbridge, which operates the world’s largest crude pipeline on the continent, has revised its plans to build the $4-billion Northern Gateway Project. It would take 525,000 barrels a day of bitumen-based product from the Upgrader Alley region across the Rockies to the deepwater port of Kitimat, B.C., for sale in California and Asian markets. The dual 1,173-kilometre-long pipeline would also import 193,000 barrels of condensate or diluent to help lubricate the export line. The scheme would bring as many as 18 tankers a month to B.C.’s northern coastal waters.
In the United States, as many as 17 refinery expansions and five brand new refineries to process 1.6 million barrels of bitumen a day have been identified. The Environmental Integrity Project,a U.S. advocacy group, estimates that the bitumen export boom now equates to the construction of 16 new refineries in the United States. Given that no new refineries have been built south of the border for more than 30 years, that’s an amazing development.
The new bitumen pipelines have enormous political and economic implications for the continent. A 2008 report by Wood Mackenzie, a global energy analysis firm, says that the Gateway and Texas Access pipelines alone “could determine the destination of oilsands products in the U.S. and outside North America and influence U.S. import patterns.” According to an economic report by Ottawa-based Informetrica Ltd., the export of 400,000 barrels of bitumen per day represents the loss of 18,000 jobs and a 0.2% subtraction from Canada’s GDP.
A 2008 petition to Ottawa by the Communications, Energy and Paperworkers Union of Canada argued that the approved pipelines could leave most of Canada “vulnerable to offshore supply disruptions” (half of the nation is still reliant on foreign imports) and will undermine “the potential to establish a diversified and sustainable oil and gas industry for Canada.” CEP added that the National Energy Board “has all but abandoned its critical role as the guardian of the public interest.”
Most analysts argue that the upgraders should go where it’s cheapest to build them. You don’t need a lot of diluent to ship bitumen to Alberta upgraders, but the U.S. Gulf Coast already has the largest set of refinery assets on the continent, says analyst Paget. “The U.S. needs more oil than they’ve got, and that pervades everything they do.” He calculates that the potential winners in the megaprojects sweepstakes are companies “who own the best oilsands resource and develop it at the least cost,” as well as the pipeline firms.
But with bitumen, nothing is written in stone. The U.S. environmental lobby and various mayors have raised big concerns about “feeding U.S. refinery expansions with dirty fuel” (see page 69). In contrast, while the U.S. Congressional Research Service notes the expansions “will have environmental impacts,” it says the new infrastructure “could strengthen the flow of oil from Canadian oilsands.”
Alberta may also change its laissez-faire approach to bitumen exports. In September, it is expected to announce a new strategy to take royalty payments for bitumen in kind instead of cash. “That would make them a player in the market and allow them to sell product so it’s processed in Alberta,” notes Strathcona County’s Reiling. “It’s a real change in mindset.”
Oilsands consultant Dembicki also favours a royalty change that would penalize raw bitumen for export while providing maximum relief for bitumen used for petrochemical end products. Such a change, he says, might marginally slow down the current pace of development and even restore the province’s ability to manage and build projects in an efficient manner “without creating a gold mining camp atmosphere.”
Yet the inexorable growth of pipelines and refineries south of the border illustrates a sea change in the economy of energy on the continent. “Canada has become the primary base load provider of oil to the United States,” notes First Energy’s Paget. “And we are the only part that can grow.”