The growth in extraction and production has been matched by significant investment opportunities in upgrading facilities and transportation infra-structure.

Transportation

Over 80 percent of bitumen produced in Canada is exported to the U.S. through existing pipelines. The bulk is delivered to upgraders in Petroleum Administration for Defense District (PADD) II (U.S. Midwest region), with the balance delivered to PADD III (Gulf Coast) and PADD IV (Rocky Mountain). The National Energy Board’s most recent oil sands report indicates that the industry should maximize its volumes in its traditional markets of PADD II, PADD IV and Washington State, with further market expansions and extensions later in the decade into California, PADD III and the Far East.

As demand for oil grows, markets with great potential for Canadian crude continue to emerge. California and the U.S. Gulf Coast both provide significant demand for medium and heavy crudes. Crude oil is currently shipped to California via pipeline and tanker. The U.S. Energy Information Administration predicts that a new or expanded pipeline to California will eventually be required to serve the growing demand of that market.

Proposed pipeline expansions to new and existing markets include proposals by corporations such as Enbridge Inc., Kinder Morgan and TransCanada Pipelines Limited to build and operate new pipelines and storage terminals.

Enbridge, for instance, has proposed the Northern Gateway Pipeline that would transport crude oil from Edmonton, Alberta, to a new marine terminal in Kitimat, British Columbia, whereby it would be shipped to China and other Asia-Pacific markets. The Northern Gateway Pipeline is currently seeking regulatory approval, and would represent a further expansion to Enbridge’s existing pipeline systems in Canada and the U.S. Enbridge’s Southern Lights diluent delivery system came into service July 2010 and carries product through 2,556 kilometres of pipeline originating near Chicago, Illinois, and terminating in Edmonton, Alberta. The Southern Lights project also includes the LSr Project, a 313-mile, 20-inch crude oil pipeline from Cromer, Manitoba, to Clearbrook, Minnesota. It added needed capacity for light/sour crude (thus the LSr name) between Cromer and Clearbrook. The LSr Pipeline was brought into operation in February 2009. Construction and line fill of Enbridge’s Alberta Clipper Pipeline from Hardisty, Alberta, to Superior, Wisconsin, was completed in October 2010. Current capacity of the Clipper is 450,000 bbl/d, with ultimate capacity of up to 800,000 bbl/d available.

In June 2010 TransCanada commenced commercial operation of the first phase of the Keystone Pipeline System. Keystone’s first phase was highlighted by the conversion of natural gas pipeline to crude oil pipeline and construction of an innovative bullet line that brings the crude oil non-stop from Canada to market hubs in the U.S. Midwest. An extension of the Keystone Pipeline from Steele City, Nebraska, to Cushing, Oklahoma, went into service in February 2011.The further proposed extension, the Keystone XL Pipeline, is currently on hold while the U.S. government conducts an additional environmental review, but TransCanada believes the pipeline will still be operational by 2013. The Keystone XL Pipeline is a 2,673-kilometre (1,661-mile), 36-inch crude oil pipeline that would begin at Hardisty, Alberta, and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska. It would incorporate a portion of the Keystone Pipeline (Phase II) through Nebraska and Kansas to serve markets at Cushing, Oklahoma, before continuing through Oklahoma to a delivery point near existing terminals in Nederland, Texas, to serve the Port Arthur, Texas, marketplace. The Keystone XL Pipeline is cited as having an initial commercial capacity of 500,000 bbl/d and is estimated to cost approximately US$7 billion.

Kinder Morgan completed construction in late 2008 on the Anchor Loop project, its Transmountain Pipeline expansion, which runs across Jasper National Park and Mount Robson Provincial Park. The addition of the Anchor Loop increased the capacity of the Trans Mountain pipeline system from 260,000 bbl/d to 300,000 bbl/d, and helped to alleviate capacity constraints on Kinder Morgan’s existing system resulting from increased oil sands production.

Upgrading

Essentially all of the bitumen extracted from the oil sands must be upgraded; oil sands operators must therefore decide whether or not to do field upgrading. Upgrading transforms bitumen into synthetic crude oil, which commands a higher price when sold to refineries. Upgrading requires substantial capital and technological resources. The process enables producers to eliminate risks arising from the heavy oil/light oil price differential and further eliminates diluent cost risk and supply issues. Ultimately, the question for producers is whether the promise of higher, more stable netbacks (that generally result from an upgraded product) will offset the substantial capital costs.

The location of upgrader facilities has been influenced by economies of scale and cost factors such as shortages of skilled labour. Integrated oil sands operators have chosen to locate, expand existing and convert existing upgraders in the U.S. where larger facilities provide cost advantages over Canadian greenfield or expansion projects.

In October 2006, Encana and ConocoPhillips entered into a US$15-billion joint venture that includes Encana’s heavy oil projects in the North Athabasca region, along with ConocoPhillips refineries in the states of Illinois and Texas. The partnership plans to expand processing capacity at these facilities from approximately 60,000 bbl/d to 550,000 bbl/d by 2015.[1] Husky Energy and BP have entered into a similar arrangement in their Sunrise project, where Husky transferred 50 percent of its oil sands holdings for 50 percent of BP’s refinery near Toledo, Ohio. Husky acquired the Lima refinery in Ohio and plans to reconfigure and expand it to process heavy crude oil and bitumen.[2]

The possible regulatory and environmental impediments to the addition of oil sands upgrading/refining capacity in the U.S. have yet to be adequately assessed, but in Alberta they are better known and quantifiable. The issues companies confront in acquiring U.S. upgrading/refining capacity may ultimately prove more disruptive to project timelines than the constraints faced in Alberta projects. In addition, there is a significant governmental push to encourage producers to upgrade in Alberta. Currently, there are five upgraders in Alberta with a capacity of almost 900,000 bbl/d.