The oil-sands region of Canada is steadily becoming one of the most talked about areas in the industry, with companies from every corner of the globe announcing their desire to capture a piece of the action, but at what cost?

In 2006, many of the companies operating commercial oil-sands projects announced either changes to their original plans or cost increases. These have resulted in an average growth in initial capital expenditures (capex) per peak flowing barrel of 32% for integrated mining projects and 26% for in-situ developments.

In addition, the average sale price for land in the oil-sands region was US$114,654 per square kilometer (US$460/acre) in 2006, a 14% increase from 2005 and 434% higher than in 2004. By comparison, the price is 21 times higher than that for leases along the Alaskan North Slope.

In 2006, 857 leases in the oil-sands region were awarded, covering more than 15,000 square kilometers-a dramatic increase from the previous three years during which there were 764 leases awarded involving some 7,000 square kilometers.

Bonus payments far exceeded the combined levels of 2003, 2004 and 2005. They amounted to some US$1.75 billion, almost a fivefold increase from the US$360 million paid in 2005. The Athabasca area attracted the highest premiums and accounted for 75% of the leases awarded.

Marginal economics have always been a concern for companies operating in the play. Breakeven prices are high and rates of return relatively low in comparison with conventional projects, particularly for mining developments. Wood Mackenzie estimates that these have an average breakeven price of US$28 barrel and an internal rate of return of just 16%.

Costs are set to continue their upward journey, with Shell Canada announcing a further three 100,000-barrel-per-day expansions at its Athabasca oil sands project, which will put further pressure on the already tight labor and materials markets within Alberta.

This begs the question as to how long the current pace of development can truly be sustained. Not surprisingly, industry players are contemplating the wider impact of the oil-sands boom. Indeed, the former premier of Alberta, Peter Lougheed, has suggested that the current administration have a more hands-on approach to developing the play, slowing the pace of construction, increasing royalty rates and having more consideration for the environment.

The attraction of the play lies in the longevity of the projects and the scale of the resource base. The play is estimated to hold some 174 billion proved barrels of oil, representing 97% of Canada's proved oil reserves. Bitumen in place is estimated to be in excess of 2 trillion barrels; recovery of more than 10% is possible.

Output is currently some 1 million barrels per day, representing some 35% of total Canadian production. This should increase to around 4 million barrels per day, or 89%, in 2020, which WoodMac forecasts as the year of peak production, based on current discoveries.

For the past 42 years, oil companies have endeavored to commercially produce crude oil from the play. Alberta currently has more than 150 companies from around the globe vying for a piece of this immense prize.

However, the cost of acquiring acreage is negligible compared with the investment required for a commercial development. Since 2005, capex per peak flowing barrel for all projects has increased some 55%. In 2006, operators of all the commercial mining developments, with the exception of Syncrude, announced significant cost increases.

Three projects-Athabasca, Fort Hills and Northern Lights-witnessed larger than average increases in capex per flowing barrel due to changes in development plans. The Fort Hills development experienced the largest increase-69%. The operator, Petro-Canada, and partners Teck Cominco and UTS, have attributed the increases to the tight labor market in Alberta and the growing cost of materials.

As for in-situ developments, the majority also saw large cost growth in 2006. Four projects-Foster Creek, Mackay River, Orion and Sunrise-all experienced larger than average increases. Those at Foster Creek and Orion were due to changes in development plans as a result of a new downstream partner and new operator, respectively.

At Mackay River, operator Petro-Canada provided a budget estimate for the expansion phase in the range of US$700 million to US$1 billion, significantly higher than WoodMac's previous forecast. In addition, costs on the existing development are expected to reach around US$435 million versus the initial forecast of US$260 million. Thus the project is estimated to have seen one of the largest increases amongst in-situ developments: 71%.

Devon Energy Corp.'s Jackfish project broke the trend, avoiding capex increases. Instead, capex has actually decreased there due to a reduction in the number of wells needed to reach peak production.

Development of the play is particularly labor intensive and individual projects can require up to 5,000 workers to reach peak production. Labor demands in Canada will be pushed to their limits by these projects, development of Arctic pipelines from the North Slope and Mackenzie Delta, and ongoing conventional oil and gas activity.

Cost growth due to significant changes in initial development plans can be attributed in part to the relative immaturity of the play, as companies learn best practices and gain experience.

Costs could grow to a point at which smaller companies are excluded and only fully integrated, well-financed companies are strong enough to take it on. In addition, project timelines will more than likely be pushed beyond forecast start-up and interested parties may turn their attention to lower-risk regions of the world.

If oil prices remain above US$50 in real terms, all commercial oil-sands developments modeled by WoodMac will be profitable with rates of return greater than 10%. Although still marginal, the projects have long resource lives and remain attractive investments.

Suncor's mining development has the lowest breakeven price, but it also has the lowest rate of return; the Athabasca project and Canadian Natural's Horizon are the top two mining developments, with low breakevens and high rates of return.

As for in-situ developments, Suncor's demonstrates some of the best economics with a very high rate of return, and the lowest breakeven price among them all. In-situ developments as a whole have higher rates of return as the capex needed is much lower.

Overall, operators will have to control capex going forward to ensure that project breakeven prices do not exceed current levels, thus they remain profitable. Reserves size is no guarantee of economic success.

Perhaps this points to project management and contractor scheduling as the key factors in oil-sands success. A good example of a development that has been able to control costs and remain on schedule is Husky's Tucker in-situ development in the Cold Lake region.



Conor Bint is an analyst, Canada and Alaska upstream research, for U.K.-based energy-research firm Wood Mackenzie. Pauline Dingwall is lead analyst, Canada and Alaska upstream research, for the firm.

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