Providing coverage of Alaska and northern Canada's oil and gas industry
October 2012

Vol. 17, No. 41 Week of October 07, 2012

Pegged at $45-65B

Producers say LNG project would require competitive oil, gas fiscal terms

Kristen Nelson

Petroleum News

The North Slope producers and TransCanada are wrapping up work on concept selection for a Southcentral Alaska liquefied natural gas project, but appear to be telling the state that the ball is back in its court over fiscal issues.

ExxonMobil, ConocoPhillips, BP and TransCanada told the governor in an Oct. 1 letter that the current cost estimate for a liquefied natural gas project is $45 billion to $65-plus billion in today’s dollars. The project described includes a gas treatment plant either on the North Slope or in Southcentral Alaska; a 42-48 inch pipeline; a three-train liquefaction plant; LNG tanks and a terminal.

The companies said they have looked at 22 potential sites for the liquefaction plant, including “Cook Inlet, Prince William Sound and other Southcentral sites.” The plant would have a footprint of 400 to 500 acres and a peak workforce of 3,500 to 5,000.

The gas treatment plant would have a footprint of 150 to 250 acres, a peak workforce of 500 to 2,000 and be among the largest such facilities in the world.

The pipeline, estimated at some 800 miles and with a capacity of 3-3.5 billion cubic feet per day, includes five state off-take points for 300-350 million cubic feet per day and would have a peak workforce of 3,500 to 5,000 people.

Overall there would be a peak construction workforce of 9,000 to 15,000, with some 1,000 operations jobs in Alaska.

Meets benchmarks

The governor said in an Oct. 3 statement that the information provided meets his benchmark of hardening numbers and identifying a gas project by the end of the third quarter and also addresses another benchmark of completing discussions with the in-state gas project, the Alaska Gasline Development Corp., on the potential to consolidate the work of the two projects.

But for the project to proceed from concept selection to pre-FEED (front-end engineering and design) the companies said in a diagram of key decision points, requires a competitive oil tax environment, predictable and durable LNG project fiscal terms and resolution of AGIA (Alaska Gasline Inducement Act) issues.

In a footnote to the chart of the project’s phases the companies list items which could extend the duration of the phases, including: “protracted resolution of fiscal terms, permitting and regulatory delays, legal challenges, changes in commodity market outlook, time to secure long-term LNG contracts, labor shortages, material and equipment availability, weather, etc.”

Governor encouraged

Parnell said he is “encouraged that the companies have made significant progress in advancing a project and an associated schedule for commercializing North Slope gas.”

He said that his administration has been working on outreach to Pacific Rim markets and other key stakeholders including U.S. government officials in charge of export licensing.

In his State of the State address in January, Parnell laid out benchmarks to achieving a gas line.

In his Oct. 3 statement he said that ExxonMobil, ConocoPhillips and BP met two earlier benchmarks: On March 29 the state and companies resolved the Point Thomson litigation and on March 30 the companies announced alignment on commercializing North Slope natural gas under the Alaska Gasline Inducement Act framework.

The end-of-third-quarter benchmarks included numbers hardened for an LNG project and an associated work schedule. The governor also called for completion of discussions on the potential to consolidate projects between the AGIA and AGDC projects.

In their Oct. 1 letter the companies said “TransCanada, on behalf of the APP (Alaska Pipeline Project) parties, has advised that a cooperative framework has also been established with the Alaska Gasline Development Corporation for information exchange.”

The governor said in January that if those milestones were met, “the 2013 Legislature can take up gas tax legislation designed to move the project forward.”


The letter from the companies, signed by Randy Broiles of ExxonMobil Production Co., Trond-Erik Johansen of ConocoPhillips Alaska Inc., John Minge of BP Exploration Alaska and Tony Palmer of TransCanada, makes it pretty clear, however, that not just gas taxes are at issue.

Existing oil production facilities “need to be available over the long-term for producing the associated gas for an LNG project. For these reasons, a healthy, long-term oil business, underpinned by a competitive fiscal framework and LNG project fiscal terms that also address AGIA issues, is required to monetize North Slope natural gas resources,” they said in the letter to Parnell.

The Alaska Legislature has been unable to agree on oil tax changes and the administration has said oil tax changes will be proposed when the new Legislature convenes in January.

Deputy Revenue Commissioner Bruce Tangeman told the Alaska Oil and Gas Congress in September that the administration would be ready to discuss oil tax changes in January (see story in Sept. 30 issue).

He told the Associated Press Sept. 25 that Econ One Research has been hired to advise the administration on oil taxes, specifically to look at the oil production picture over the last 10 years in Alaska and other oil-producing regions, research which Tangeman said will lay the groundwork for changes to the state’s oil tax structure.

Work to date

The companies said work to date has cost some $200 million, building on more than $700 million in past work by the companies, and involving more than 125 employees and more than 100 contractors. BP leads the commercial team and ExxonMobil the technical team. Within the technical team, BP has the lead on producing fields, the Alaska Pipeline Project (TransCanada and ExxonMobil) on pipelines, ConocoPhillips on the LNG plant and ExxonMobil on the integration team.

Following completion of the concept selection phase, and a decision to move forward, the project would move into a 12-18 month pre-FEED period which will cost hundreds of millions and involve staffing of 400-500, a phase which includes preliminary engineering and the start of individual gas and LNG sales and shipping efforts.

If a “go” decision is made after the pre-FEED stage, the FEED stage would involve a cost of billions, staffing of 500 to 1,500 and take two to three years, the companies said in a chart describing key decision points.

If a decision were made to build the project it would move to the engineering, procurement and construction stage, estimated to cost tens of billions, require staffing of 9,000 to 15,000 and last five to six years.

The decision point

Where is the project now?

The concept selection technical work is reaching closure, the companies said in their letter, and “additional commercial agreements as well as support from the State of Alaska will be required in order to progress this world-class opportunity.”

“Our next steps are to complete the concept selection phase and work with the State to make meaningful progress on the items detailed above. This work is critical as we consider decisions to progress the next phases of an LNG development project,” the companies said.

Some of the challenges the companies list — “cost, scale, long project lead times” and reliance on production facilities supporting declining fields — aren’t directly things the state can address. Some required permits would come from the state, others from the federal government, so that’s a mixed bag.

What is under the state’s control is fiscal issues — taxes on oil and gas.

So, the ball appears to be back in state’s court.

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