State awaits key decision from producers on large LNG export project
June 20, 2013
State officials are hoping to hear any day, perhaps as soon as June 20, from companies working on a large natural gas project that they are ready to go to the next stage of preliminary engineering on the project.
Earlier this year in his State of the State address, Gov. Sean Parnell laid out a series of milestones for the project including a commitment to undertake a preliminary Front End Engineering and Design, or “pre-FEED” in the first half of 2013.
The deadline for that, June 30, is fast approaching.
Companies involved are producers BP, ConocoPhillips, ExxonMobil and independent pipeline company TransCanada Corp.
So far the companies have met other milestones, such as reaching agreement on a scope of the project, and key design parameters of the gas treatment plant, the pipeline and a large liquefied natural gas plant at an as-yet undesignated Southcentral Alaska port.
Moving to “pre-FEED” is significant because it would be the first substantial financial commitment to the latest version of the project, and would require an expenditure of several hundred million dollars.
Meanwhile, the project manager for the industry-led group, Steve Butt of ExxonMobil, told a state legislative committee in a briefing on May 30 that part of the gas project is actually under construction.
These are the facilities at Point Thomson, a large gas field 60 miles east of Prudhoe Bay, now being built. While this will initially produce a liquid gas condensate with the produced gas injected back underground the long-term plan is for it to be part of the larger gas project.
Butt said 1,200 people were working last winter on the Point Thomson project. Work is continuing through this summer, with about 550 people working, be said.
ExxonMobil, which is leading that project, achieved a 90 percent Alaska-hire rate through the 35 contractors employed last winter, Butt said.
State Sen. Click Bishop, R-Fairbanks, one of the legislators being briefed May 30, said the local-hire rate was impressive.
“A 90 percent local hire on the project of that size is almost unbelievable,” Bishop said.
Butt said a lot of progress is also being made on planning for the larger gas project. The industry group is now spending about $3 million per month in its work with more than 300 people employed from the companies and contractors.
The overall project would involve an investment of between $45 billion and $65 billion, and would ship between 16 million tons and 18 million tons of LNG annually. It would be operating after 2022, if it is built.
Expenditures in the last year and a half, since work began on the latest pipeline/LNG version of the project, have totaled about $35 million. This is on top of about $700 million spent by the companies on a previous project to build an all-land pipeline to Alberta so that Alaska gas would be shipped to the Lower 48 states.
The fast buildup of shale gas at low costs have taken away the Lower 48 market for now, however, so the companies shifted to an LNG export project partly at the urging of Parnell.
Most of the LNG would be shipped to Asia.
In the latest effort the companies have pooled information gathered by the Denali pipeline project, which was pursued by BP and ConocoPhillips but then ended, and the Alaska Pipeline Project, which was being pursued by TransCanada Corp. and then joined by ExxonMobil.
Technically, the project that is continuing is still the Alaska Pipeline Project with its new plan for a pipeline to an LNG project, with BP and ConocoPhillips in support of that. Those companies have not yet formally joined the APP.
One impediment to that, which will eventually be resolved, is that TransCanada is committed to special terms under the state’s Alaska Gasline Inducement Act, or AGIA, under which the state is also paying up to $500 million to support the companies’ work.
AGIA requires that the companies agree to certain terms on tariff structures and financing to which the three producers have objected.
ExxonMobil, BP and ConocoPhillips have said they cannot agree to AGIA’s terms and that the agreements will have to change if the project were to eventually move forward.
Parnell has said he is open to changes in AGIA once the companies are all in agreement to move forward with the project.
Meanwhile, Butt said May 30 that in achievements so far the companies have completed an integrated design for the gas treatment plant, pipeline and LNG plant, have finished needed hydraulic modeling, and have worked out the heat and materials balancing.
“This assures us that the project can work, from a technical standpoint,” Butt said.
Each of the major components is a mega-project on its own, with the Gas Treatment Plant requiring about 270,000 tons of steel and five sealifts of equipment and materials to the North Slope, he said.
Alaskans have seen previous efforts on large pipeline projects, all failing to advance for various reasons, but what is different now is that all parties are working together, including the state.
Coordination has also been established with the Prudhoe Bay field operators, which comprise the same three producers but in a different organization. This is important because the gas treatment plant is being integrated with the existing Prudhoe field gas processing facilities, Butt said.
There is agreement that 42-inch pipe will be used on the main pipeline.
“This is a standard size of carbon steel pipe that can be sourced from a lot of steel mills in different places. It really opens up the market,” in terms of procurement, Butt said.
Previous efforts have included plans to use larger pipe sizes including more than 50 inches that would have drawn from a very limited pool of suppliers.
The LNG plant in Southcentral Alaska would have three LNG process trains, or production modules, taking an average of 2.5 billion cubic feet a day of gas although the pipeline is being designed to transport up to 3.5 billion cubic feet daily so as to allow for increased seasonal production.
Gas plants are more efficient in cold weather, Butt said, so production might be ramped up in winter, which also coincides with periods of peak demand from customers.
“Our core challenge is to reduce the uncertainties and risks for the project,” Butt told the legislators May 30.
He didn’t mention it, but the uncertainties include the state’s fiscal terms on gas production, on taxes and administration terms of the royalty.
Now that legislation has passed adjusting the state oil production tax, in Senate Bill 21, state officials have said they are ready to discuss special terms on gas production taxes for the big gas project. Talks on those are believed to be underway now.
The oil tax change is important because it will help ensure that oil production will continue and that the infrastructure of the North Slope will be maintained, and paid for by oil production, for the gas project.
Meanwhile, there are still other uncertainties for the gas project itself, Butt told legislators. A big one is a stretch of several hundred miles of discontinuous permafrost soils extending through Interior Alaska. Continuous permafrost, or permanently frozen soil, that exists on the North Slope creates a stable soils environment for a buried gas pipeline, which will be cold.
However, discontinuous permafrost that freezes and thaws, which exists in the Interior, creates challenges is that it may cause the pipeline to move.
The soils south of the Brooks Range, “are a little messy,” Butt said.
A buried 42-inch pipeline is heavy, so it is believed that this problem can be handled, but it will still be an area of special focus for state and federal regulators.
Last spring, in a previous legislative briefing by the pipeline and LNG group, the possibility that parts of the pipeline might have to be built above ground, similar to the Trans-Alaska Pipeline System, was mentioned.
“TransCanada (a member of the industry consortium) has a lot of experience in building Arctic pipelines and has been in discussions for three years with government agencies about this,” Butt said.
Permitting itself is a challenge, particularly with a special federal permit now required for Arctic pipelines.
“We’re just starting to talk with the regulators about this,” Butt said.
Above-ground construction at selected points is also a concern for the state-owned Alaska Gasline Development Corp. in its work on a separate 36-inch pipeline that is a contingency in case the industry-led project fails to advance.
Frank Richards, a senior AGDC manager, told the legislators May 30 that seismic hazards from potential earthquakes at the Denali Fault in the Alaska Range and the Castle Mountain fault in Southcentral Alaska, in the Matanuska-Susitna Borough, may require special construction above-ground so as to allow the pipeline to move in the case of an earthquake.
The Trans-Alaska Pipeline System survived an earthquake in 2002 on the Denali Fault because of a special design incorporated by engineers when TAPS was built in the mid-1970s, Richards told the committee.
The design allowed the oil pipeline to move laterally without breaking in an earthquake. Similar design concepts may have to be built into AGDC’s plan, Richards said.
Butt didn’t mention seismic hazards but the large 42-inch pipeline would also cross the Denali Fault and, if it comes to Mat-Su-Anchorage region instead of Valdez, the Castle Mountain fault as well.