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Too little, too much Oil sands production expected to outstrip Alberta’s processing capacity Gary Park For Petroleum News
Oil sands producers in the Canadian province of Alberta face a double-edged problem — not enough upgrading capacity and too much export pipeline space — according to new reports.
The Alberta Energy Resources Conservation Board said June 7 the rapid growth of oil sands production, which could more than double to 2.95 million barrels per day by 2019 (1.35 million bpd of synthetic crude, up 77 percent from 2009, and 1.6 million bpd of raw bitumen), is expected to outstrip Alberta’s processing capacity.
In its annual report, the regulator said only half of the anticipated synthetic volumes will be upgraded in Alberta because of the narrow price spread between bitumen and light crude.
Mined bitumen is forecast to comprise the bulk of bitumen upgraded to synthetic crude in Alberta, while in-situ production will account for only 18 percent by 2019.
That is a sharp downward adjustment from the ERCB’s 2008 report, when it predicted the industry would be producing 3.2 million bpd of raw bitumen, of which 70 percent would be upgraded in Alberta.
In 2007, 62 percent of all bitumen production was processed in Alberta, a number that dropped marginally to 60.9 percent last year
The regulator said its new production targets are likely to exceed Alberta’s upgrading capacity by 50 percent for at least the next decade as most companies with upgrader plans remain on the sidelines rather than risk getting caught in another round of cost overruns that dominated their sector until 18 months ago when the recession prompted a host of deferrals or cancellations.
Only two upgraders are currently on the active file — a joint venture by Canadian Natural Resources and North West Upgrading which is the front-runner to gain 75,000 bpd of royalty-in-kind bitumen from the Alberta government as feedstock for a 150,000 bpd facility that is tentatively scheduled to come onstream about 2015 and Total’s plans, currently before regulators, for an upgrader to be integrated into its Joslyn project.
The ERCB said the price spreads between light and heavy crude are now so narrow and likely to persist, undermining the economics of upgraders.
Soaring costs, uncertain demand The last 18 months have also hit plans for more than 1.6 million bpd of future pipelines because of soaring costs and uncertain demand, while a combined 885,000 bpd of new capacity being introduced by TransCanada and Enbridge is spreading aftershocks among producers who are dealing with a sobering new reality.
The Canadian Association of Petroleum Producers estimates that the volume of oil previously expected to be carried on Enbridge’s 450,000 bpd Alberta Clipper system by 2011 will now be delayed until 2018 — a seven-year lag that has already seen Enbridge pull back from its plans to build an extension to the U.S. Gulf Coast after it was unable to obtain shipper support.
The excess capacity has prompted Suncor Energy and Imperial Oil to ask the National Energy Board for relief from higher tolls on Enbridge’s Canadian mainline system to recover the costs of building Alberta Clipper. The board has scheduled a hearing for Nov. 9.
In addition, privately held Altex Energy, which in 2005 launched the first proposal for a bullet line from Alberta to the Gulf Coast, has scrapped the 425,000 bpd scheme.
Having wrestled with historical production growth trends, Altex President Glen Perry concluded it would take 10 years to fill the Altex line, which he said could cost up to C$8 billion and run at half capacity for five years — a prospect he described as “pretty tough economics.”
Enbridge v. TransCanada As the belief grows that the Gulf Coast will not need as much crude as previously thought, there have been some sharp exchanges between Enbridge and TransCanada.
Enbridge has argued that TransCanada’s Keystone XL project to access Texas with a 510,000 bpd of additional capacity — a proposal approved by the National Energy Board — would cause an “unnecessary and unprecedented” level of excess capacity.
TransCanada’s outgoing Chief Executive Officer Hal Kvisle has conceded there could be four or five years of oversupply, “but it won’t be on our system.” Keystone’s initial phase, with capacity of 1.1 million bpd, has contracted space of 910,000 bpd.
Russ Girling, Kvisle’s chosen successor, said there is “no question that there will be more exit pipeline capacity leaving Alberta than there is production. The U.S. Midwest is fairly saturated already with Canadian crude. But there won’t be excess capacity to markets that need the crude.”
Others are less troubled by the longer term outlook, even if Perry is on the mark with his assessment that pipeline tolls could triple from their current level of about C$3 per barrel.
Jim Carter, a former president of Syncrude Canada, said substantial toll hikes will not eat too deeply into producers’ profits.
“People will understand that this is a temporary thing until the capacity gets soaked up,” he said. “After that, the toll rates will come down.”
Brenda Kenney, president of the Canadian Energy Pipeline Association, told the Globe and Mail the alternative of being “pipe short has some severe consequences. The key is to look long-term and know that pipe capacity will not be a constraining factor in economic growth.”
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