Shell Canada Ltd. is betting on two things in pushing ahead with a $4-billion expansion at its Athabasca Oil Sands Project.

The project, which came onstream in June 2003, includes the Muskeg River Mine north of Fort McMurray and the Scotford Upgrader northeast of Fort Saskatchewan.

The company intends to submit a regulatory application next year for the expansion, to double bitumen production from an average 141,900 barrels a day (b/d) in the second quarter this year to between 270,000 and 290,000 b/d by 2010.

Shell owns 60 per cent of the Athabasca project, while Chevron Canada Ltd. and Western Oil Sands LP each hold 20 per cent and have the option of taking part in expansions. Western Oil Sands says it will participate while Chevron is still taking a look.

In going ahead, Shell is betting that world oil prices will continue to stay high for at least the next few years.

Shell Canada’s parent firm, Royal Dutch/Shell Group, said last week that oil prices have shifted “structurally higher.” Based on that view, Royal Dutch/Shell is planning a total of about $45 billion US in capital expenditures over the next three years.

This includes about $11.5 billion US a year on exploration and production activities, up from $10.7 billion last year.

Even if oil prices take a nasty tumble in the near future – which is highly unlikely – Shell Canada will still go ahead with its oilsands expansion.

The company knows the bitumen is there and can be mined for a predictable price. On the other hand, hunting for big oil pools elsewhere is an expensive and risky proposition, especially in geo-political conflict zones.

The only conflict zone such as that in Canada is whenever Premier Ralph Klein and Prime Minister Paul Martin find themselves in the same room.

The other thing Shell Canada is betting on is that it can control the huge cost overruns that have plagued oilsands mega- projects, including a 50- per-cent hike in the Athabasca Oil Sands Project’s original $3.8-billion budget.

Shell says it learned a lot from building the original project – mostly not to take too big a bite of construction all at once. The company also now has roads, pipelines and offices for the project, so it won’t need to build these from scratch.

Also look for Shell to hedge its bet by requiring contractors to set a firm price for the work they bid to do and pay for any cost overruns themselves.

All in all, it looks like a pretty safe hand to play.

But with so many oilsands mega-projects on the go at the same time, the one thing that could upset Shell’s construction timetable is finding the 6,500 skilled workers required to actually do the job.

Hot Oil Prices Can’t Cool Costs

It looks like most of the oilpatch is betting on oil prices to stay high.

Worldwide spending by companies on “upstream” activities – exploration, development and production – increased by nine per cent to $161 billion last year, says a study by John S. Herold Inc. and Harrison Lovegrove & Co. Ltd.

The jump in upstream spending in 2003 was a marked contrast to the 4.4-per-cent drop the previous year, according to an Oil and Gas Journal report from Houston.

Driven by oil and gas prices, the worldwide industry’s cash flow reached a five-year high in all six global regions reviewed in the study, which was based on the public records of 194 oil and gas companies.

In Canada, all that cash hasn’t offset costs that have exceeded cash flow by nearly 40 per cent over the last five years, the study said.

Most of the spending in Alberta has been on new and expanding oilsands projects. And it will take a few years to start seeing a return on this investment from increased production.

A worrisome note in the study is that upstream spending in North America has fallen by 22 per cent since 2001, while spending in South and Central America, Africa and the Middle East has risen by more than 60 per cent.

These figures corroborate a trend by major oil and gas firms that are selling their assets in the already well-explored and developed reservoirs of the Western Canadian Sedimentary Basin, in favour of hunting for a big oil or gas strike in other countries.

The figures also underline former premier Peter Lougheed’s warning last week that the provincial government should be pumping billions of oil and gas revenues into the Alberta Heritage Savings Trust Fund.

Whether oil and gas prices take a big drop in the near future or not, the resources are finite and the rainy days will inevitably come.

Gone Without The Wind

It’s too bad that Calgary-based ATCO Group and SaskPower International aren’t going ahead with a joint $250-million, 150-megawatt wind-energy project in Saskatchewan.

But ATCO’s decision to bow out shouldn’t keep SaskPower from looking for another partner for the project, especially among oil and gas companies that have already built impressive wind farms and are looking for new opportunities.

In notifying SaskPower of its decision last week, ATCO didn’t offer any reasons publicly for not taking part in the project.

All Nancy Southern, ATCO Group president and CEO, said in a cryptic release was that her company has the “highest regard” for SaskPower International’s people and that previous joint ventures by the two firms “have been notable for their significant success.”

Such scant communication begs the question: So why abandon this wind-farm project even before one turbine blade starts turning?

SaskPower should call Suncor Energy Inc. or Enbridge Inc. Along with partner EHN Wind Power Canada Inc., SaskPower officially opened the $48-million Magrath Wind Power Project near Lethbridge this month.

The project’s 20 turbines can produce 30 megawatts of “green” electricity – enough to power about 13,000 homes.

Enbridge has purchased one-third of the wind farm’s power for its pipeline operations. The remaining electricity will be distributed through Alberta’s grid.

The Magrath wind farm will also keep about 82,000 tonnes of the greenhouse gas carbon dioxide out of the atmosphere each year. That’s like taking some 12,000 vehicles off the road.

Suncor and Enbridge also jointly own and operate the 11-megawatt Sunbridge wind farm near Gull Lake, Sask.

So SaskPower, unplug ATCO and pick up the phone to an oil company!

CBM Activity

Here’s another sign of Alberta’s quickening pace in coalbed methane (CBM) development.

TRAFINA Energy Ltd., a Calgary-based junior energy firm, has an agreement with Nexen Inc. to develop CBM in the Wetaskiwin area between Edmonton and Red Deer.

Nexen plans to drill between eight and 10 wells to evaluate the coal seams and the conventional hydrocarbons before March 31 next year. In return for a 60-per-cent interest in 20 sections in the Wetaskiwin area, Nexen will also pay an undisclosed cash bonus to TRAFINA.

Nexen will tap the coal gas by drilling wells that range from 150 to 1,300 metres deep into the Horseshoe Canyon and the lower Manville coalbed formations.

Most shallow CBM wells in the Horseshoe Canyon formation produce little of the water that’s often contaminated by salts and metals and has caused problems for landowners near CBM projects in Wyoming and Colorado’s Powder River Basin.

Some analysts are predicting there could be up to 3,000 CBM wells drilled in Western Canada next year, compared with about 1,500 drilled this year.

Along with Nexen, other major players in CBM development in Alberta include EnCana Corp., Husky Energy Inc., Apache Canada Ltd. and MGV Energy Inc.

(Mark Lowey can be reached at mark@businessedge.ca)