NEB's 2002 Oil Production Data Contains Eye-Opening Figures

Abstract: Data compiled by Canada's National Energy Board shows the U.S. cannot expect to increase imports of light oil from its northern neighbor, although the supply of synthetic crude, heavy oil, and bitumen is increasing.

Analysis: The first act of "Bombs over Baghdad" is still playing in front of billions of TV viewers, so it's much too early to assess the long-term consequences of a war on Iraq on the stability of Middle East oil suppliers such as Saudi Arabia and the United Arab Emirates.

The military strikes launched this week by President George W. Bush and his allies make it timely to review 2002 data on Canada's oil production to see whether this country can step up output and increase energy security for the world's largest importer of oil.

The numbers should interest U.S. readers because Canada is one of the top three suppliers of crude to American consumers. Canada averaged oil exports of about 1.4 million barrels per day (mmbbls/d) last year, meaning it slaked about 7 percent of the United States' thirst for crude.

Figures for this article were drawn from statistics compiled by the National Energy Board, Canada's equivalent to the Federal Energy Regulatory Commission. They consist mostly of actual data as well as some estimates for December, meaning the current numbers may vary slightly from the final totals. However, the differences will be quite small and not significantly alter any conclusions.

The NEB's statistics, which can be found at, break down oil output by both province and type. The sorting is beneficial because it allows users to see clearly the impact of East Coast activities, where oil volumes have been rising because of increased production at Hibernia and last year's start-up of operations at Terra Nova.

The East Coast now accounts for 32 percent of light oil produced every day in Canada, or some 285,700 bbls/d, compared with a 17 percent share in 2000, when the region's daily output averaged 144,200 bbls/d.

Terra Nova's output will probably increase to 150,000 bbls/d in 2003, up about 11 percent from its volume in the fourth quarter of 2002, but Hibernia is already running at close to its maximum at 180,000 b/d. With White Rose, a Husky Energy-led offshore oilfield, not expected to begin producing its 90,000 bbls/d of oil until 2005, there's not much opportunity for supply growth to the U.S. from this region during the next couple of years.

This leaves Western Canada as a potential source of more light oil, but the NEB's data is pretty negative on the chance of this happening without finding the wish-fulfilling genie from Ali Baba's lamp. Production of light oil between Manitoba and British Columbia, the four western provinces, averaged 604,300 bbls/d last year. In comparison, the region pumped 653,600 bbls/d of light oil in 2001 and 681,300 bbls/d in 2000.

The numbers show light oil production in Western Canada has dropped 11 percent during the past three years even though oil prices have averaged more than $26 per barrel, substantially above the long-term average of between $18 and $20 per barrel.

The inability of exploration and production companies to crank up light oil production during a sustained period of unusually high prices amply demonstrates the Western Canadian Sedimentary Basin is mature. This helps explain why firms such as Talisman Energy, Nexen, and Canadian Natural Resources are increasingly focused on international projects. It also means any disruptions in Middle East supply of lighter slates will not be offset by higher imports from Canada.

An eye-opening fact contained in the NEB data was the slip in heavy oil production. The regulator estimated heavy oil volumes averaged 552,200 bbls/d last year, down from 572,200 bbls/d in 2001. The figure was somewhat surprising since most production forecasts for Western Canada call for annual increases in heavy oil, bitumen, and synthetic crude output.

The reason for the slippage was weak oil prices and a high differential, the discount applied to heavy oil because it costs more to refine into gasoline than light oil, in late 2001 and early 2002. Expect a different story in 2003 because strong crude prices and a low differential are making heavy oil plays as profitable as a beer stand at a baseball game on a hot day.

While Canada is offering no help in the war against Iraq, the federal government will be more than happy to ring up a bigger trade surplus with the U.S. through increased exports of synthetic crude. Alberta, the lone source of this type of oil in Canada, pumped 431,100 bbls/d in 2002, up 25 percent from the 344,300 bbls/d averaged in 2001 and 37 percent above the 314,900 bbls/d recorded in 2000.

Increased production of synthetic crude holds a couple of interesting implications. The light, sweet slate could be used to displace OPEC shipments, lessening U.S. dependence on the volatile Middle East.

A longer term, less visible impact is the use of synthetic volumes as a blending agent to ensure tar-like bitumen from Canada flows down pipelines to U.S. refiners.

Condensate, heavier gas liquids such as pentane extracted by gas processing plants, is currently the blending agent of choice. Most pipeliners move a mix of one-third condensate and two-thirds bitumen in their systems.

Condensate output is declining, a result of falling gas production last year in Canada. Output of the gas byproduct fell to 147,300 bbls/d in 2002, down from 152,900 and 165,400 bbls/d in the preceding two years, respectively. The situation is unlikely to improve this year since gas production is expected to fall about 3 percent.

Rising bitumen production, which averaged about 300,000 bbls/d in 2002, will put further pressure on the decreasing supply of condensate. This was reflected in posted prices in Edmonton, a major refining center in Alberta, for condensate rising 41 percent in the past year while oil prices increased 33 percent.

Concern about the price and availability of condensate helps explain why EnCana, Imperial Oil, and others are looking at ways of producing bitumen without using condensate as a diluent. Petro-Canada, for example, has already started mixing synthetic crude with bitumen produced from its MacKay River project, a C$290 million development in northern Alberta expected to average 22,000 bbls/d in 2003.

Replacing condensate with synthetic crude, resulting in a mixture some people call SynBit, yields more middle distillates for refiners, such as jet fuel and diesel, and less low-valued bottoms like asphalt. However, the differing chemical properties of SynBit reduces returns on previous investments in cokers, used to break down heavier hydrocarbons into lighter molecules, since the equipment is not as heavily utilized.

While the numbers from the NEB by themselves are a little dry, they provide a good basis to understand some of the fundamentals influencing the oil industry on both sides of the border. The complex interplay of bitumen, condensate, and synthetic crude supply, for example, is going to be one of the more interesting stories over the next couple of years in the Canadian oilpatch.