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North America's Source for Oil and Gas News
March 2004

Vol. 9, No. 11 Week of March 14, 2004

Oil sands bombshell

Expansion costs at giant Syncrude operation could double original projections; start-up delayed by 12 months; Canadian Oil Sands Trust hammered

Gary Park

Petroleum News Calgary Correspondent

Oil prices of US$25 per barrel are the threshold for the Alberta oil sands to more than double production over the next 13 years to 2.2 million barrels per day and for operators to achieve an “adequate” return on investment of about 10 percent.

So said the Canadian Energy Research Institute on March 3 when it released the findings of a comprehensive study.

The research organization, funded by industry and government, said the target for synthetic crude and unprocessed crude bitumen could reach 2.8 million bpd with oil prices at US$32 per barrel and 3.5 million bpd at an “unconstrained” level.

Bob Dunbar, CERI’s senior research director, rated the future of the oil sands as “very robust” based on his belief that “there is a much higher likelihood of oil prices above than below $25.”

Under the $32-a-barrel scenario, capital spending would average C$4.4 billion (US$3.3 billion) a year between now and 2017, CERI said.

Just as the industry was absorbing this upbeat message it got hit by a bombshell.

Two days after CERI’s study was released, Syncrude Canada set a new benchmark for the cost overruns that have plagued the sector in recent years.

Worst case, expansion could cost double original projections

The consortium owners disclosed on March 5 that an expansion of the world’s largest synthetic crude operation had skyrocketed by C$2.1 billion to C$7.8 billion, with a 50-50 chance that it could reach C$8.1 billion by completion.

In the worst case, the Stage 3 expansion would cost double the original projections in 2001 to boost Syncrude volumes to 350,000 bpd from 253,000 bpd.

At that time, Syncrude Chairman Eric Newell, who turned over the reins to Charles Ruigrok in December, was confident that completing 80 percent of detailed field engineering before major construction started would head off incremental costs.

“We believe this approach will be key to managing the project within budget and schedule,” he said.

Adding to the latest litany of woes, the partners said the project will now not come on stream until mid-2006, close to 12 months behind schedule, potentially costing about 36 million barrels of lost output.

Williams Lacey, institutional research vice president at FirstEnergy Capital, told the Financial Post the escalating cost will increase the cost of a flowing barrel — the incremental output tied to the capital expenditure — to C$58,000 a barrel, compared with C$38,000 at Shell Canada’s Athabasca operation and C$31,000 at Suncor Energy’s Millennium expansion. Both of those projects were at least 50 percent over budget.

Dunbar estimated the expansion’s unit cost will now be about C$78,000 per barrel of new production capacity.

Canadian Oil Sands Trust hammered

In the immediate fallout, Canadian Oil Sands Trust, whose 35.49 percent stake in Syncrude is its sole asset, was hammered on the Toronto Stock Exchange. Its units dropped almost 16 percent on March 6 to C$44.90 and almost C$730 million was wiped off the trust’s market value.

The other Canadian-based partners in Syncrude — Imperial Oil, Petro-Canada and Nexen — escaped the initial backwash, because of their more widely held interests.

Word of the overrun “surprised, stunned and shocked” analysts, with Tom Ebbern, at Tristone Capital, noting that the C$2.1 billion cost was announced after all the engineering work had been completed, 90 percent of materials had been purchased and the project was 37 percent finished.

But construction workers at Syncrude say they have been voicing their concerns for months about engineering-related hitches.

One source told Petroleum News that in his own area, engineers had refused to heed the warnings and were unwilling to discuss solutions.

Canadian Oil Sands Trust Chief Executive Officer Marcel Coutu, who is also chairman of the Syncrude joint venture, blamed the cost increases on upfront engineering and the challenge of building a new upgrader within old operations.

Detailed engineering tasks were completed in the wrong order, he said, adding: “We did not recognize that and could not quantify that until much later on.”

In fact, it wasn’t until a detailed review by independent experts and Syncrude staff was commissioned this winter that problems in project management and engineering were exposed.

“Significant reorganization” triggered by new information

The new information has triggered a “significant reorganization,” including the enlistment of international-caliber professionals, although no executives will lose their jobs, Coutu said.

However, Syncrude will attempt to recover some of the overrun from contractors, who are led by KBR, a unit of Halliburton. “We will be pursuing any potential that we see,” he said, while conceding the chances are slim because Syncrude, in the midst of a tight labor market, used a cost-plus rather than a fixed-price form of contracting.

The labor force, which has ranged from 4,500 to 5,500, was exempted from any blame and will remain on site to cash in on the delays, which will extend their work time by 40 percent to 25 million hours from 15 million.

As for the Syncrude owners, Coutu said they all “remain committed to the project.” Imperial Oil, the second largest partner with a 25 percent interest, is “concerned about the escalating costs and schedule delay, (but is) prepared to support Syncrude in whatever way we can to address these issues,” said Senior Vice President K.C. Williams.

Reaching for any lifeline, Coutu said it was “only fortuitous this setback is occurring during a period of robust crude oil prices, which may prevail for some time and should help Canadian Oil Sands fund much of its (C$700 million) share of this project from cash flow.”

Heaviest cost overrun in oil sands history

The heaviest cost overrun in oil sands history, leaving Suncor Energy and Shell Canada well behind, has given another jolt to the search for alternative strategies, dominated by new thinking that projects are best approached in smaller stages.

Syncrude has an early chance to apply the lessons learned, with Coutu suggesting Stage 3 could be the last multi-billion-dollar undertaking by Syncrude.

“The industry has shown it can pretty handily manage billion-dollar type projects, but multiples of that become a different animal,” he said, referring to strategies favored by newer oil sands players Petro-Canada and Husky Energy, who are opting for staged developments, with each phase financed out of cash flow.

The “bite-sized” approach is expected to be Syncrude’s only hope of gaining owner-approval for its next two stages.

Stage 4 is already identified as less ambitious, scheduled to take place between 2005 and 2010 and raise production from Stage 3’s peak of 350,000 bpd to between 384,000-425,000 bpd.

Stage 5, targeted for 2010 to 2015, is aimed at production of 507,000 bpd-548,000 bpd.

Coutu said Stage 4, with a preliminary capital budget of C$1 billion-$1.5 billion, is unlikely to encounter the logistical problems of Stage 3. Stage 5 is heading back to the drawing boards.

Feeding the oil sands

The demand for natural gas to fuel the extraction and processing of raw bitumen in Alberta’s oil sands could soar to 3.7 billion cubic feet per day by 2017, close to one-quarter of Western Canada’s current gas output.

In a new analysis by the Canadian Energy Research Institute, that prospect was fingered as one of the major obstacles to oil sands growth.

Senior Research Director Bob Dunbar said that even more modest growth in output to 2.2 million barrels per day would need 1.5 billion to 2 billion cubic feet per day, more than the start-up volume of 800 million to 1.2 bcf per day expected from the Mackenzie Gas Project.

The CERI scenarios included an “unconstrained” outlook of 3.5 million barrels per day of synthetic crude and unprocessed raw bitumen over the next 13 years, pushing gas consumption to 3.7 bcf.

With oil prices at US$32 per barrel, production was forecast at 2.8 million bpd and at US$25 per barrel — the level deemed necessary to yield an adequate return on investment — output was set at 2.2 million bpd.

Current oil sands production of 900,000 bpd requires 500 million cubic feet per day of gas.

But Dunbar said operators are “working very hard” on developing greater energy efficiencies, new technologies and alternative sources of energy, which could include a nuclear reactor to generate steam and power.

Nuclear an option, as is igniting oil in reservoir

The nuclear option, although dismissed by Alberta Energy Minister Murray Smith, could still be employed in northern Alberta within a decade, said Jerry Hopwood, director of business development with Atomic Energy of Canada, a Canadian government agency.

He argued at a conference last month that oil sands and heavy oil producers have little choice but to diversify their energy supply sources and “free up natural gas for its most highly-valued uses.”

Dunbar, conceding that gas consumption of 3.7 bcf per day is likely unsustainable, said high gas demand could see some projects deferred and others cancelled.

He said the technologies and alternative fuel sources under study include a C$30 million test project recently approved for Petrobank Energy and Resources, which plans to ignite oil in the reservoir, converting bitumen to 20-degree API gravity crude, allowing it to flow to the surface.

If successful, that technology would lower capital and production costs and reduce gas consumption to minimal levels, Petrobank has claimed.

—Gary Park, Petroleum News Calgary correspondent

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