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State, AGPA, OFC update Alaska LNG Navigant consultant says liquefied natural gas good option for US, state’s natural gas, but other projects could block out Alaska Kristen Nelson Petroleum News
While the Alaska Oil and Gas Congress got updates on North Slope natural gas projects Sept. 18-19, the conference was a bit early for what will be breaking news at the end of September.
The end of the third quarter occurs after this issue of Petroleum News goes to print, and that’s the target set by Gov. Sean Parnell for Alaska’s North Slope natural gas owners to harden numbers for an Alaska liquefied natural gas project and to identify a pipeline project with an associated work schedule. It’s also the deadline Parnell set for the mainline project, under the Alaska Gasline Inducement Act, and the in-state line under the Alaska Gasline Development Corp. to complete discussions determining the potential to consolidate the projects.
Those are two of five benchmarks the governor set in his January 2012 State of the State address.
The benchmarks are summarized in an Aug. 13 transition report to legislators from Kurt Gibson, director of the state’s Gas Pipeline Project Office.
The state and major leaseholders resolved Point Thomson litigation, the first item on the governor’s list, on March 29.
The second item, the governor’s call for the North Slope producers to align under the AGIA framework and include work on an LNG project to tidewater by the end of the first quarter, was ticked off March 30 when CEOs for the producers signed a letter to the governor announcing an agreement to work together in an effort to “commercialize North Slope natural gas resources within the AGIA framework.”
The fifth item on the governor’s list is contingent on other milestones being met and specifies that if those milestones have been met, the 2013 Legislature can take up gas tax legislation.
Alaska Gasline Port Authority Bill Walker, general counsel and project manager for the Alaska Gasline Port Authority, formed in 1999 by voters in Valdez, Fairbanks and the North Slope Borough, told the congress Sept. 18 that the authority was looking at three options for a liquefied natural gas plant in Valdez. The borough has since dropped out.
The first option came out of a 1998-99 LNG study by the Alaska North Slope LNG Project, organized by ARCO Alaska (later Phillips Petroleum) and including Foothills Pipe Lines Ltd., Marubeni Corp. and CSX Corp. through subsidiary Yukon Pacific Corp. (Yukon Pacific dropped out in 1999 and was replaced by BP).
Walker said one of the options that group studied was co-locating the LNG facility at the Alyeska Valdez Marine Terminal, using acreage available at the terminal and making use of excess berths.
Another option is at Anderson Bay, some five miles toward the Valdez Narrows on the same side as the Alyeska terminal. Walker said that is the location Yukon Pacific Corp. selected; that site was permitted by the Federal Energy Regulatory Commission for a three-train project.
The port authority has been working with Excelerate Energy on a third option, a floating LNG facility, an option possible because of technology advances, he said. Walker said the port authority became interested in that option when it heard the price: compared to $1,200 per ton for liquefaction onshore, the estimate for floating liquefaction was $450-$600 per ton.
The port authority did a nonbinding solicitation of interest, with a goal of 2.7 billion cubic feet per day, plus an estimated 0.5 bcf per day of existing and projected in-state use.
Walker said there was interest totaling 2.8 bcf per day from the Asian market.
As for what’s next, he said AGIA is not working and the state should exit or renegotiate.
The competitive picture Bob Gibb, associate director of the Fuels Group with Navigant consultants, addressed the competitive issue, providing background on Lower 48 natural gas and LNG export projects in the works in Canada and the Lower 48.
The development of shale gas in North America has changed the natural gas availability picture on the continent, Gibb said. And it isn’t just the U.S. and Canada. Mexico also has a tremendous amount of recoverable shale gas, but it’s cheaper for Mexico to import U.S. natural gas than develop their own resources, so they’re putting their development on hold, he said.
In the U.S. the situation has changed from needing gas and looking at import facilities for LNG, to the conversion of import facilities for export.
But there are issues for shale gas development, he said, using resistance to the Keystone Pipeline as an example. Gibb said that people forget that when the original Keystone line was built five years ago, there was no resistance; that’s how quickly things change, he said.
Another issue is drilling. While rigs drilling for oil now exceed those drilling for gas, that’s a function of lower-priced gas and efficiencies, he said. The current count is just over 600 rigs drilling for dry gas in the U.S. compared to 1,275 in 2008, but Gibb said what doesn’t show up in the statistics is that the time to drill a well has been cut by more than half and the efficiency of hydraulic fracking as increased. He said fracking is still a relatively new science and it’s being improved. There’s also associated gas — when you drill for oil you usually get some gas. Associated gas in the Bakken is still growing, even with the drop in rigs, he said.
With the increasing supply of natural gas, a number of people are looking to export LNG to get that gas out of the U.S. and by 2020 the U.S. is expected to be a net exporter of LNG.
He said Navigant expects that some six to eight export facilities will be developed, and that does create a certain urgency for Alaska because the further along other facilities get, “the tougher it’s going to be ... to find the markets that are going to take the Alaskan gas.”
Regulatory issues Larry Persily, federal coordinator for Alaska Natural Gas Transportation Projects, addressed the issue of whether politics or laws would get in the way of selling North Slope natural gas.
Department of Energy approval is required to ship natural gas out of the U.S., he said, and while it’s easy to get that approval to ship to a free-trade partner, those partners are countries like Australia, Bahrain and Chile, which is not where you want to ship LNG. South Korea was added last year, Persily said, but that’s a small market, only some 4.5 bcf a day, compared to the 80-plus bcf a day of natural gas utilized in North America and a global LNG market which was about 32 bcf a day last year, about a third of that Japan, a third the rest of Asia and a little less than a third Europe. But approval to ship to other nations is not so easy to get.
Last year the Energy Department approved an export license for Cheniere Energy, the only approval it’s ever given other than to Alaska, Persily said.
But after approving Cheniere, the department put a hold on all other applications, pending two studies, one of which has been completed but the other, on the overall economic effect of exports on the U.S. economy, has been repeatedly delayed and now won’t be out until after the election.
Another requirement is a FERC certificate for the liquefaction facility, he said, and FERC has the option to exercise authority over an export pipeline.
Then there is a presidential determination that exports of North Slope natural gas, except to Canada or Mexico, won’t hurt U.S. utilities. And while such a determination was made in 1988, allowing exports, “is that 24-year-old presidential determination still valid?”
No one has asked, he said.
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