A plan for a large-diameter pipeline bringing North Slope natural gas to major commercial markets officially shifted Wednesday from one that would send Alaska's gas to the Lower 48 through Alberta to one that would end in Southcentral Alaska and liquefy gas for export on Asia-bound tankers.
Two state commissioners signed a letter approving a new direction for a project being developed by pipeline company TransCanada. In doing so, Natural Resources Commissioner Dan Sullivan and Revenue Commissioner Bryan Butcher formalized a shift outlined in March.
TransCanada and its partner, Exxon Mobil, will continue to do some work on the Alberta route, the state said.
But their prime target now is a pipeline to tidewater in Southcentral Alaska, either tracking the route of the trans-Alaska oil pipeline to Valdez or ending up at Nikiski, where Conoco Phillips already is operating a plant that exports Cook Inlet gas to Asia by super-chilling and condensing it.
TransCanada was granted an exclusive state license in 2008 to develop a pipeline under terms agreed to by the state. It can get up to $500 million from the state for work leading up to construction of what is expected to be a 48-inch pipeline carrying 3 billion to 4 billion cubic feet of gas a day. As of Dec. 31, it had received $146 million in reimbursements, state officials said Wednesday.
With an unexpected glut of cheap natural gas in the Lower 48, TransCanada struggled to sell the idea of a line through Canada to potential shippers. To recharge the stalled project, Gov. Sean Parnell began calling for the route change last year and pushed the other two big North Slope oil producers to get behind it. In March, BP and Conoco agreed to join TransCanada and Exxon in the pipeline venture. The three companies control the vast stores of North Slope gas.
While Japan especially is in the market for imported natural gas, Alaska could face tough competition from Australia or China in providing it.
The amended project plan puts off for two years what had been an October deadline for TransCanada to seek approval from federal regulators for a pipeline to Alberta, state officials said. That approval may never be needed.
"The challenge to this project is it's so big and moves so slowly because of its size -- and the costs and risk associated with it -- that by the time it generates some momentum, the market conditions have changed," said Kurt Gibson, director of the state gas pipeline office, which oversees the big pipeline project.
In particular, three changes in circumstances justify the shift to an export line, according to Sullivan and Butcher's summary of TransCanada's position:
• Large-scale production of natural gas from shale rock deposits in the Lower 48;
• A projection by the U.S. Energy Information Administration that the United States will begin to export more natural gas than it imports; and
• The agreement by all three North Slope oil producers to support the in-state gas pipeline with its alternative for exporting natural gas. The March agreement by the producers marks the first time they've all lined up behind a way to bring North Slope gas to commercial markets, according to the state.
TransCanada also cited a January report by the energy agency that natural gas prices range from $4 per million British thermal units in the Lower 48 to four times that in Asian markets, where gas prices have been linked to oil prices, the state commissioners said in Wednesday's letter to TransCanada vice president Tony Palmer.
The project will still fall under the framework of the Alaska Gasline Inducement Act, a Palin-era measure that provides for state reimbursement of up to 90 percent of upfront costs.
About half of the work done on the Alberta option, including engineering and environmental options, will be put to use on the in-state pipeline, state officials said. The project plan amendment lays out an orderly transition, state officials say. Some work on the Alberta route will continue to a logical stopping place. That work will be inventoried and may eventually be turned over to the state.
Two years ago, TransCanada estimated it would cost $32 billion to $41 billion for the 1,700-mile line to Alberta, or $20 billion to $26 billion for the 800-mile Valdez line. The company didn't look at the Nikiski option. And the Valdez estimate did not count the cost of special tankers or the massive gas-chilling plant that would be needed. Current cost figures weren't immediately available Wednesday.
By September, TransCanada should have completed initial work on a plan for a liquefied natural gas project. By the end of the year, it should have completed a serious assessment of interest in the project from "all potential market participants," the state commissioners said. That includes North Slope producers, explorers, LNG terminal developers and import entities.
The commissioners also directed TransCanada to determine whether it can use the work of a separate state agency, the Alaska Gasline Development Corp. That agency was created to get Alaska natural gas to Alaskans by creating a small-diameter pipeline. But legislation to advance its work died in the Legislature this year. Lawmakers did provide $21 million but didn't give approval for the agency to spend another $200 million already set aside. The state agency could shift and work on a spur line off TransCanada's big line, officials say.
As it stands, the Conoco plant in Nikiski is the only LNG export plant operating in the country though others have been approved by federal regulators.
"When it comes to LNG export, we are the leaders," Gibson said.
Still the 43-year-old plant is smaller than what would be needed. It could process 240 million cubic feet of gas a day, according to Conoco. That's much less than the billions a big pipeline would carry.
One area of study, Gibson said, is whether to expand the Nikiski plant, build a new one there, or build one in Valdez.
Reach Lisa Demer at email@example.com or 257-4390.