EXTRACT: On the heels of Shell Canada’s startling revelation that the cost of its proposed Athabasca expansion may have soared 75 percent in the past year to C$12.8 billion…
Total shuffles Joslyn completion; Imperial looks for cost-cutting; Suncor tight-lipped about costs; Enbridge Chinese deal slowed
By Gary Park
For Petroleum News
Even for the topsy-turvy world of the Alberta oil sands the last couple of weeks have been enough to make heads spin as companies wrestled with the timing of mega-projects, clammed up on the costs of future expansions and caused uncertainty about whether a deal with Chinese refiners is still achievable.
On the heels of Shell Canada’s startling revelation that the cost of its proposed Athabasca expansion may have soared 75 percent in the past year to C$12.8 billion there was a confused message emanating from a partnership of Total and Enerplus Resources Fund.
A year after buying an 84 percent stake in the Joslyn project for C$1.6 billion or about C$0.80 per barrel of recoverable reserves, the French energy giant indicated it has rejigged plans for its Joslyn project and found itself at odds with its junior partner in explaining the changed strategy.
Enerplus issued a statement essentially blaming inflation in labor and materials costs for delaying its on-stream date to 2013 from the previous target of 2010-11, adding that was only a “best estimate.”
Total’s Canadian President Michael Borrell surfaced the next day to suggest that rather than starting at 50,000 bpd in 2010 and adding 50,000 bpd in 2014, the new plan might see a single 100,000 bpd come on stream in 2013.
Borrell told reporters that the strategy was being reviewed with the intention of “optimizing the development scheme … nothing is being put on hold, nothing is being cancelled.”
He said it would be more “advantageous” to complete a mine and upgrader, each with capacity of 100,000 bpd, at the same time.
While conceding that cost pressures are a factor, he said Total and Enerplus were being driven more a desire to achieve “economic optimum development in a timely manner.”
Joslyn still needs approvals
Joslyn, formerly operated by Deer Creek Energy, is an integrated undertaking that still needs approvals beyond the current start-up phases from Alberta Environment and the Alberta Energy and Utilities Board.
The multi-phase development is designed to remove 2 billion barrels of bitumen over 30 years through mining and steam-assisted gravity drainage methods.
Once the 100,000 bpd target is reached, the objective is to add 100,000 bpd in 2020 at a final cost estimated at US$9 billion, including a US$5 billion upgrader.
Total opened at office in Calgary eight years ago to examine the heavy oil prospects of North America, arriving with a solid track record from its Sincor heavy oil operation in Venezuela.
Its first move was to take a foothold in the Surmont project (now operated by ConocoPhillips), moving to 43.5 percent in 2003 and now holding 50 percent.
Surmont has a 27,000 bpd commercial phase under construction and due to start in mid-2006 and is aiming for 100,000 bpd.
Jean Luc Guizou, president of Total Canada until the end of July, insisted the parent company was “not going to produce just bitumen,” pointing to downstream ambitions that include a possible 200,000 bpd upgrader — a link in the oil sands chain that is experiencing some of the wildest cost overruns.
He had also talked about Total’s desire to embark on even more upstream operations.
Enerplus said that “given current industry pressures from a significant number of competing projects, timing issues are expected to be ongoing.”
Oil sands facing cost challenges
Whether or not the Joslyn project faces delays or is just involved in a reconfiguration, oil sands players are grappling with undisputed cost challenges.
Veteran operator Suncor Energy is reflecting a new reluctance by developers to put price tags on their projects because of reluctance to take heat from their investors when they are forced to disclose overruns.
Suncor Chief Executive Officer Rick George told analysts that “just like everyone else we are experiencing cost pressures and will particularly do so on future projects … there’s no way that you can avoid that.”
Suncor is currently adding 90,000 bpd to its output of 260,000 bpd and expects to move from there to 550,000 bpd by 2010-12 with its Voyageur expansion that was initially estimated at about C$10 billion — a figure that will not be updated for at least another year, when Suncor will have a better idea of the delays (now 24 months or longer compared with 12-18 months three years ago) it faces in the delivery of major equipment.
Also trying to get to grips with the cost spiral is Imperial Oil, whose Chief Executive Officer Tim Hearn said Aug. 3 that his company’s focus in the next few months will be on “offsetting industry-wide cost pressures in current operations and in future projects.”
The involves financial evaluations of the Mackenzie Gas Project and the planned Kearl Lake oil sands development and finding ways to offset rising capital costs.
Kearl, depending on whether it gets a final green light in early 2008, could start operations in 2010, ramp up to 100,000 bpd in early 2012, 200,000 bpd in 2014 and 300,000 bpd in 2019, recovering 3.23 billion barrels of bitumen, at a cost initially projected at C$4.5 billion-$6.5 billion.
On a positive note, Devon Energy said it has avoided some of the cost pressures affecting its peers and now intends to submit an application this fall for approval of Jackfish 2, alongside its Jackfish project now under construction and scheduled to start production in 2008 at 35,000 bpd. The second phase would double output by 2010.
The company forecasts the initial phase will be within 5 percent of its C$550 million budget, while the second phase will cost about 20 percent more, compared with the others who are swallowing hikes in the 50-75 percent range.
Devon President John Richels said his company “contractually fixed the cost of a lot of surface facilities,” dodging some of the big overruns that have hit mining projects.
Also downstream hitches
As the upstream companies attempt to find their way through a jungle of competition for skilled workers and materials there are hitches in the downstream end as well.
In its ambitious plan to open up new Asian and U.S. markets for oil sands production, Enbridge is experiencing the difficulties of a pioneer in its efforts to bring Canadian producers and Chinese refiners together.
As a result, start-up of its planned 400,000 bpd Gateway pipeline from Edmonton to British Columbia’s deepwater port at Kitimat (and its parallel 150,000 bpd pipeline to import condensate from the Pacific basin) could be delayed a year to 2011, Chief Executive Officer Pat Daniel conceded.
Gateway is “badly needed by Canadian producers to get the optionality they need … and it’s badly needed by Chinese refiners to get the optionality they need in terms of crude supply,” he said.
But the Chinese want a “level of familiarity before they do a deal,” which could see 50-75 percent of the volumes shipped to Asia (Japan and South Korea are also possible buyers), with PetroChina a candidate to take a 49 percent equity stake in the pipeline.
Daniel is confident Gateway will be built — as he is positive about the chances for all of the C$13 billion worth of oil liquids pipelines Enbridge has on the table.
He said Enbridge is trying to open a “brand new market for Canadian crude” and move beyond the traditional pursuit of US markets as the “quick and easy way to get a deal.”