By Meghan Gordon

February 15 - The success of a massive Alaska gas pipeline is believed to depend on the participation of all three North Slope producers, and yet the competition between them is only heating up.

When TransCanada rolled out its open season plans in January, it ratcheted up the rhetoric that its proposal is the superior of the two and would ultimately emerge successful.

The company has partnered with ExxonMobil, which leases the largest deposit of North Slope gas.

TransCanada hopes to start fielding interest from shippers when its open season begins in April, followed three months later by the Denali joint venture between the other North Slope producers, BP and ConocoPhillips.

“This is a big, high-stakes game between those two projects as to which one will win out at the end of the day,” said Gerry Goobie, a managing consultant at Purvin & Gertz in Calgary.

 If the competing teams and Alaskan politicians clamoring for the revenue-rich project can agree on anything, it’s that only one pipeline would get built and it depends on gas from all three producers.

“It’s going to be a commercial deal that involves all four of those companies,” nominated federal Alaska gas coordinator Larry Persily said February 2 during his Senate confirmation hearing.

The closer the two get to their open seasons, though, the farther apart they seem to grow.

In public comments, each project only lets on that it thinks its approach is the right one and that it would welcome late-comers under its rules.

Tony Palmer, TransCanada vice president, said during a January 29 conference call explaining the open season filing with FERC that the pipeline depends on the alignment of five players: the state, the three North Slope producers and TransCanada.

He said the company has offered equity stakes to producers that commit large volumes to the open season, but those negotiations haven’t gone far.

Bud Fackrell, president of the Denali joint venture, said such a partnership isn’t likely as long as it’s under the framework of the state Alaska Gasline Inducement Act, under which TransCanada is operating and counting on up to $500 million in state reimbursements in exchange for following certain rules.

“My owners don’t agree with the terms and conditions of AGIA, so that’s problematic for the parties to come together,” Fackrell said February 1. “Even ExxonMobil, while they’ve joined, they have not signed up for the terms and conditions of AGIA.”

Oil and gas economists watching both projects combed through the hundreds of pages in TransCanada’s open season plans the week ended February 5 for fresh indications of whether the team will be able to draw the massive shipper interest it needs to move forward.

The plans detail two options: sending 4.5 Bcf/d of gas about 1,700 miles to Alberta or sending 3 Bcf/d about 800 miles to Valdez, where a third-party would have to build a liquefied natural gas terminal to ship the gas to Pacific markets.

To make the open season more enticing, TransCanada said it found ways to save shippers $500 million a year.

The company cut its rate of return on equity from 14% to 12% and plans to pass along only 80% of its capital costs to shippers through its tolls.

“Just think of how significant that number is when you take $500 million a year over 25 years,” Palmer said. “That shows you how responsive we’re being to competition and, frankly, some would say to the value of AGIA.”

Goobie said the incentives demonstrate that TransCanada is serious about making the project work.

On the other hand, he wondered whether a $500 million annual discount was enough of a draw for a project expected to cost as much as 82 times that amount.

“They’re doing what they can to make their project a winner,” Goobie said. “They’re sharpening their pencil. That’s good from a shipper perspective, but nonetheless it’s an awfully expensive project. I don’t think it diminishes Denali’s competitive position that much.”

Roger Marks, an Alaskan economist and self-described cynic of an Arctic pipeline, pointed to a clause in the proposed precedent agreement that would allow the pipeline to recover the discounted 20% later. (See related map: Arctic pipeline proposals).

If a shipper signs up for another five years at the end of its 20-year contract, the pipeline can start collecting the remaining capital costs in its tariff.

“If this is a risky proposition, you wonder whether to go into it,” Marks said. “If it’s not, all it is is a deferred payment.” Palmer said there’s no guarantee customers would renew their contracts when the original term ends in 2040.

“We’re taking the risk that there’s an adequate gas price and the market is still receptive to Alaska gas,” he said.