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Pipeline plans swamp regulator U.S. appetite for Canadian crude sends NEB into ‘high gear’; Enbridge ponders interim option for final connection to Gulf refineries Gary Park For Petroleum News
Canada’s National Energy Board is feeling the crunch from growing oil sands production, handling applications last year for 885,000 barrels per day of new pipeline capacity, compared with a mere 40,000 bpd in 2006.
It’s all part of the wholesale shift from a period when natural gas ruled in Western Canada to the hunger for crude in the United States and the urgent need to head off pipeline apportionment in the next few years.
The demand is partly driven by the Canadian Association of Petroleum Producers forecast of an increase in oil sands volumes to 3.4 million bpd in 2015 from 1.1 million bpd in 2006 and the anticipated reduction in shipments from Mexico and Venezuela to the Gulf Coast refinery region.
NEB Chairman Gaetan Caron said that “without a doubt” the federal government’s energy regulator “shifted into high gear throughout 2007.”
“Furthermore, it is becoming clear that not only is the Canadian oil and gas industry changing in terms of supply and demand, so too is Canada’s regulatory regime,” he said.
The largest applications were TransCanada’s Keystone line that will start deliveries of 590,000 bpd to Oklahoma and Illinois in 2010 and could expand to 1.3 million bpd by 2013-14 and Enbridge’s Alberta Clipper system to Wisconsin, with an in-service date of mid-2010 at 450,000 bpd initially, expandable to 800,000 bpd.
When it releases an updated supply forecast later in May, CAPP expects the rate of expansion in the oil sands will require even more pipeline to new markets in Texas, the North American West Coast and eastern Canadian destinations.
But, to avoid production outpacing available transportation capacity, the industry and regulators must start planning five years ahead, given that a regulatory application now takes two years — a timeframe that is expanding as opposition builds from environmentalists, landowners and aboriginal communities — and construction needs another three years.
Enbridge shelves expansion plans But not everyone is taking a sky-is-the-limit view of the demand for pipelines.
Industry heavyweight Enbridge has shelved for now plans for a $2.6 billion joint venture with ExxonMobil to extend its Alberta Clipper pipeline from Patoka, Ill., to the Nederland hub near Houston, establishing the first complete link from Alberta to Texas.
Instead it has opted for a measured approach after an extended open season to find an anchor shipper for the Texas Access connection that failed to attract sufficient shipper interest.
Enbridge Chief Executive Officer Pat Daniel raised the first clear warning flag that the pace of oil sands development could be entering a slow-down phase.
“We are sensing that producers are a little hesitant to make big commitments to a (pipeline) project until they’ve got more certainty with regard to their upstream development,” he said.
He said timing has become an issue for both mining and in-situ upstream projects.
“We would have loved to have had overwhelming support (from the open season) to move right into it immediately. On the other hand, with all of the projects that we’ve got on the go, a little bit of a delay certainly isn’t going to hurt us,” he said.
“We want to get the timing right for customers in terms of providing that service.”
As a result, Enbridge has sidelined its Texas Access plans — designed to carry 400,000 bpd by 2012 and possibly double volumes at a later date — and is now considering a scaled-down $500 million scheme that would rework existing infrastructure to deliver 150,000-200,000 bpd of crude to Portland, Maine, and from there to the Gulf by tanker.
But that does not rule out the prospect of Texas Access proceeding at a later date, Daniel said.
He remains steadfast that Texas Access is ultimately the best way to get Alberta crude to the Gulf and improve crude oil pricing for all Enbridge customers.
In the final quarter of 2007, Alberta-produced Western Canadian Select crude returned about $11 per barrel less than similar Mexican Mayan crude, which is priced on the Gulf Coast.
Daniel said that such a price spread, the result of not having access to the Gulf, cost Alberta producers about $1.5 billion.
He said Texas Access could be built for about $2.6 billion, “significantly cheaper” than the estimated $6 billion it would cost to build a complete new line from Alberta to the Gulf — the sort of proposals on the table by rivals TransCanada for a 750,000 bpd system, Kinder Morgan and Altex Energy, each eyeing 300,000 bpd bullet lines.
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