Alberta oilsands expansion has high activity in 2003

by James Stevenson

For a year marked by unprecedented activity and multibillion-dollar development in northern Alberta's oilsands, 2003 had an inauspicious beginning. Start-up of the new $ 5.7 bn Athabasca Oil Sands facility was hampered when a fire broke out just six days into the year.
It caused $ 150 mm damage and led to several months of unexpected delays for Shell Canada and its partners. A week later, US energy giant Koch Industries cancelled a $ 3.3 bn plan to build its Fort Hills project, which was to be Canada's fourth major open-pit oilsands development.

Fort Hills' demise briefly rekindled oilpatch fears that Ottawa's ratification of the Kyoto climate change accord would put undue cost pressures on the energy industry and snuff out further big-ticket investments. But the soaring cost of building new mega-projects in northern Alberta was also a key factor in the Fort Hills decision.
The same concerns were echoed in the spring when Petro-Canada announced it would halt $ 5.8 bn worth of oilsands expansion plans in favour of less costly alternatives. Yet even those setbacks couldn't outweigh the progress made, nor the raft of go-ahead decisions to follow.
"This was a very big year for us," says Neil Camarta, Shell's senior vice-president for oilsands. "After working on this thing since '96 and going through all that development construction, to be finally in the black -- making oil and making money -- is a very big deal for us."

The high price of oil in 2003 was perhaps the biggest boon for Shell and all others involved in the expensive business of pulling gluey oilsands, or bitumen, from the ground and turning it into synthetic crude. The war in Iraq and continued concern over the security of energy supplies kept oil above $ 30 per barrel for most of the year -- roughly a 20 % gain from the average price in 2002.
And while energy companies don't make huge spending decisions based on temporarily high oil prices, it helps with their overall financial health, says Joseph Doucet, an energy economics professor at the University of Alberta School of Business in Edmonton.
"A year or two of high prices provides cash flow, and hence more flexibility for these firms as they go forward," says Doucet. "They won't make decisions based on that price in and of itself but they will have more money for exploration. And they'll ask themselves if today's $ 30 spot price is indicative of an upward trend for the next 20 years."

With Canada's conventional oil supplies on the wane, extra cash among the biggest energy companies tends to turn heads north, towards the oilsands where plentiful supply is not a problem. While debate rages over how much is recoverable, the size of oil deposits in the northern Alberta ground are second only to Saudi Arabia. And it's next door to the biggest energy market in the world, a country that will gladly buy all that can be produced.
The advent of steam technology in recent years has allowed companies to access oilsands reserves that lie too deep for conventional open-pit mining. Steam is piped down one well to melt the oily mud, which is then sucked up to the surface by another nearby well and sent off to upgraders.

The other plus is that steam-assisted oilsands plants tend to be smaller, cheaper facilities with less danger of running into the massive cost overruns that scare off management teams and investors alike. Suncor Energy added to its open-pit oilsands supply this year with the completion of its $ 600 mm Firebag steam-assisted facility. Then, in the final three months of 2003, several international energy heavyweights announced plans for steam-assisted plants of their own.
Oklahoma-based Devon Energy is proceeding with its $ 550 mm Jackfish project, while Houston-based ConocoPhillips and French partner Total will build their $ 1.1 bn US Surmont facility. Calgary-based oil and gas producer Nexen intends to give its stamp of approval next February for its half-stake in the $ 3 bn Long Lake steam-assisted plant and upgrader.
"Certainly there's a lot of activity that's been generated in the last year," says John Richels, president of Devon Canada. But rather than a sudden, unexpected burst of activity, Richels says 2003 was "a culmination of some years of planning as companies have realized the potential in the oilsands as really a world-class resource."

All of this planned increase in oilsands production can't happen in a vacuum. Pipelines need to be built or expanded to take the crude farther afield, and refineries need to be retrofitted to handle more sulphur-heavy oilsands crude.
"As we went into this, it was our expectation that the we would see some pipeline expansion to take more blended crude out of Alberta," said Richels. "Some of the developments we've seen over the last little while is validating our thoughts and, yeah, we're happy with that."

Calgary-based oil shipper Enbridge unveiled bold plans to buy the Cushing-to-Chicago pipeline, with plans to reverse the flow and take Canadian crude deep into the US Midwest by 2005. The company is also proposing to build a Southern Access pipeline for about $ 800 mm, linking its terminal at the west end of Lake Superior to a hub in southern Illinois. And it is entertaining thoughts of a $ 2.5 bn project to take oilsands crude to the British Columbia coast for export.
Vancouver-based competitor Terasen, formerly BC Gas, is working on plans to expand its existing Trans Mountain pipeline from Edmonton to the BC. Lower Mainland in a phased-in approach. And subsidiary Terasen Pipelines says it will go ahead with expansion of its Express oil pipeline from the oilsands to the United States and will increase capacity by 63 %.

Meanwhile, Petro-Canada will spend $ 1.2 bn upgrading its Edmonton refinery to handle nothing but oilsands crude in the future, while Suncor bought a refinery in Denver for $ 300 mm with plans for significant upgrades over the next three years. And with all the attention, it's not likely that the pace of oilsands development will slow much in 2004.
Calgary-based Canadian Natural Resources completed public regulatory hearings for its $ 8.5 bn Horizon open-pit oilsands mega-project in the fall and expects a go-ahead decision to come sometime next summer. Toronto-based Imperial Oil is also continuing to explore the possibility of building an open-pit project called Kearl Lake with its sister company ExxonMobil Canada that could cost up to $ 8 bn.

Oilsands analyst Steven Paget of FirstEnergy Capital in Calgary says continued oilsands expansion in northern Alberta could lead to ongoing tight labour and supply markets, not to mention overly taxed infrastructure like the one road that leads from Edmonton to Fort McMurray in north-eastern Alberta.
"Will the costs remain tight? To some extent, yes," says Paget. But he says it depends on the timing of the larger projects.
"The difficulty is that the (expansion) cycle seems to be hitting at same time for too many companies, like Suncor and Shell doing a lot of their work at the same time." As a result, Paget says there may be more cost-crunch coming in 2007-2008. But it also might be avoided with the growing trend towards incremental oilsands expansion, rather than doing it all in one huge mega-project.
"We've often said it's 'Go big or go home' in the oilsands," says Paget. "Now we're modifying that to some extent to: Go smart or go home."

Here's a look at some of the major milestones in the northern Alberta oilsands in 2003:
-- Athabasca Oil Sands project:
After years of construction and cost overruns that bumped the final price tag by 50 % to $ 5.7 bn, Shell Canada and partners Chevron Canada and Western Oil Sands celebrate the start-up of Canada's third open-pit oilsands mine and upgrader.

-- Fort Hills cancelled:
TrueNorth, a unit of privately held US energy giant Koch Industries shelves $ 3.3 bn Fort Hills oilsands project. Rising labour costs, tight financial markets and uncertain impacts of implementing the Kyoto environmental accord blamed.

-- Petro-Canada changes strategy:
Fearful that cost pressures would send its $ 5.8 bn oilsands strategy much higher, Petro-Canada comes up with much cheaper plan to spend $ 1.2 bn retro-fitting its Edmonton refinery to handle nothing but oilsands crude while striking a deal with competitor Suncor Energy to use its northern Alberta upgrader.

-- Surmont facility approved:
Houston-based ConocoPhillips and French energy giant Total give go-ahead for $ 1.1 bn-US Surmont oilsands plant that uses steam technology to access deep bitumen reserves.
-- Jackfish facility approved:
Oklahoma-based Devon Energy proceeds with $ 550 mm Jackfish oilsands plant, which also uses steam technology instead of larger, more expensive open-pit mining.

-- Syncrude ownership changes:
Canadian energy giant EnCana sells its 13.75 % of Syncrude Canada joint venture to Canadian Oil Sands Trust, making Canada's largest income trust Syncrude's largest shareholder. An unscheduled shutdown of one of its cokers, or primary upgrading units, cuts annual production by about 8 % to about 77 mm barrels.

-- Suncor buys US refinery:
Suncor Energy spends $ 300 mm to buy a Denver-based refinery with plans for significant upgrades to handle oilsands crude. Suncor also finishes first stage of $ 500 mm Firebag steam-assisted plant and muses about $ 3 bn worth of continuous expansions to double production to more than 500,000 bpd.