Alaska Dispatch

TransCanada Corp. now estimates it would cost between $32 billion and $41 billion to lay a 1,700-mile natural gas pipeline from the North Slope to Alberta and would take about two years longer to launch the project than originally expected when it was first announced in 2007.

The revised price tag was revealed in a federal filing Friday amid concerns that potential shale gas developments in the Lower 48 could delay an Alaska gas pipeline. But Tony Palmer, TransCanada's vice president of Alaska development, said at a press conference Friday that despite an "epic financial crisis" and the development of huge shale gas finds, expectations for natural gas prices and demand 10 years out still make the project feasible.

TransCanada and its partner, an Exxon Mobil midstream arm, are proposing the "Alaska Pipeline Project" under a license granted by the state of Alaska that includes $500 million in subsidies. Under their plan, gas would flow by 2020, with full operations slated in 2021.

On Friday, TransCanada reached a milestone by filing plans for an "open season" with the Federal Energy Regulatory Commission. If FERC approves the plan, TransCanada will hold an open season between May 1 and July 30 during which the pipeline builder will seek bids from companies with gas to move. For those companies, it's a matter of weighing risk and reward. They'll shoulder the bulk of the hefty price tag, but stand to gain if they can link their gas to markets.

One of the big issues for producers is the tariff they'll be charged to move gas. With production infrastructure already in place on the North Slope due to years of oil development, the transportation costs are the big unknown in commercializing Alaska's gas.

Those tariffs came in above original estimates in the high $2 per million British thermal unit range, but were kept in check somewhat by TransCanada and Exxon's decision to shoulder more of the capital costs. Now the tariff is estimated at between $2.80 and $3.50 per million Btu in 2009 dollars, but that's only to the mega-line's terminus at Alberta. Companies will have to pay more to send gas down existing lines to Lower 48 markets.

Bids will likely be contingent on a variety of conditions, which would have to be mostly resolved in order to hammer out "precedent agreements," still shy of actual contracts, Palmer said. No one will know the results of an open season until those agreements are reached, a point TransCanada figures won't arrive until the end of 2010. The final go-ahead on construction isn't expected until the end of 2014.

Some say a pipeline of this scale will require buy-in from all three major North Slope producers: ExxonMobil Corp., ConocoPhillips and BP. BP and ConocoPhillips are pursuing their own pipeline, dubbed Denali, and expect to start the open season process in April.

Denali President Bud Fackrell said today's announcement doesn't affect his project, and that he still has concerns that companies may not buy into any pipeline plan until big issues can be worked out -- namely, the increased gas supply in the Lower 48, the legal status of a North Slope unit housing a third of Alaska's proven reserves, and state tax matters.

"Everything we are doing is focused on Denali's open season process," he said.

But with TransCanada and Exxon willing to shift $6 billion to $8 billion of capital costs from producers to the pipeline builders, companies holding leases to develop North Slope natural gas could be more interested in jumping into the deal. TransCanada plans to take on 20 percent of the capital costs, and is cutting a planned return on equity from 14 percent to 12 percent. Those changes should save shippers $500 million a year, Palmer said.

"We are aware that we're in a competitive environment, not just between parties that want to move Alaska gas," Palmer said. "We want folks to advance this project early, and we're providing them an incentive to do so."

Federal loan guarantees could also help ease financial risks. Under the 2004 Alaska Natural Gas Pipeline Act, the government is guaranteeing up to $18 billion for the project. U.S. Sen. Lisa Murkowski hopes to increase that to $30 billion and allow project players access to the Federal Financing Bank, which would lower interest rates for investors. But her proposal, added to the energy bill, is tied up indefinitely in Congress.

TransCanada's project filings offer two alternative routes, both including a costly gas treatment plant near Prudhoe Bay -- estimated at about one-third of the total project cost. The more popular 1,700-mile route to Alberta -- carrying 4.5 billion cubic feet of gas in a 48-inch steel pipe -- is the plan TransCanada now says could cost as much as $41 billion to build. An alternative route would carry 3 billion cubic feet of natural gas about 800 miles south to the port city of Valdez, where another party could pay for a plant to liquefy the gas for export. That line would run $20 to $26 billion. Route selection is expected to be determined based on input from the participating oil and gas companies.

Contact Rena Delbridge at This e-mail address is being protected from spambots. You need JavaScript enabled to view it

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