AK LNG makes technical progress, economics still challenging

Photo/Tim Bradner/AJOC

Alaska LNG Project managers presented an upbeat report on technical progress of the giant gas project in a Sept. 9 briefing to legislators, but also warned of the economic challenges faced.

Steve Butt, an ExxonMobil official who is manager of the overall project, described the possible complications of an expansion of the pipe diameter requested by Gov. Bill Walker. However, if the expansion were done the goal would be to keep the project on schedule for a 2018 or 2019 construction decision, he said.

Butt said there are about 1,000 people at work on the Alaska LNG Project and spending on the preliminary engineering now underway reached $243 million as of July, Butt told a combined meeting of the House and Senate Resources committees.

The total budget for the preliminary front-end engineering and design, or pre-FEED, is about $500 million, and work is to be done in early 2016.

“The third summer of field work is being completed and we are finalizing the project design and execution basis, including cost and schedule estimates,” he said.

A revised cost estimate will narrow, and update, previous cost estimates that range from $45 billion to $65 billion.

On the LNG plant at Nikiski, near Kenai, the project has acquired about 600 acres of 800 acres needed for the giant LNG plant, and offshore soils data is being gathered for the marine facilities and onshore for the plant itself.

“So far there is encouraging data from the geotechnical work,” said Butt, which was managed by the state’s Alaska Gasline Development Corp., or AGDC, a partner in the Alaska LNG Project. “The state (AGDC) did good work on this.”

Two immediate issues on the table for the project team, he said, include the decisions to be made by AGDC this fall on the location of gas off-take points for communities along the pipeline route and approvals by the project for a 2016 budget to complete the “pre-FEED” work.

“Where the offtake points are located is very important to us because even though the in-state gas use will only be 220 million cubic feet a year (of 3.3 billion cubic feet the pipeline will move daily) where the gas is taken off will affect the hydraulics of the gas movement, which will require designing for that, Butt told the legislators.

On the 2016 budget, the project managers need to know whether TransCanada will still be involved, and putting up its share of money, or whether the state will be buying out TransCanada’s share, a proposal being made by Walker that will cost the state about $110 million.

The Legislature must approve the state taking a larger share, presumably with AGDC expanding its role, and appropriations must be made by lawmakers, Butt said.

Alaska LNG Project managers must be assured that the funds for the state/TransCanada share will be available, and they must know it soon to plan for the 2016 work program, he said.

On the proposed pipe upsizing, the project partners are considering the idea, at Walker’s request, but only one of the four partners — ExxonMobil — has agreed to do the feasibility assessment, which could cost several million dollars, Butt said.

The decision basically involves an addition to the 2015 work plan, which has an approved budget, and all parties including the state must agree to amend the plan to do a 48-inch pipe study. Three other partners, BP and ConocoPhillips and, ironically, the state, have not yet decided on the plan change, Butt said.

Decisions are expected in about two weeks (from Sept. 9), he said.

Meanwhile, ExxonMobil has already agreed to spend $1 million itself to purchase several lengths of 48-inch, high-strength pipe for technical tests that must be done for federal agencies, Butt said.

If the study of an expansion of the 48-inch pipe is agreed to, it could also delay the decision on moving to the final engineering by six to eight months, he said, although there will be great efforts made to keep the overall schedule on track for a Final Investment Decision.

The decision on final engineering is to be made within one year after completion of preliminary engineering, which would put it in mid-to-late 2016 or early 2017 under the current plan with a 42-inch pipeline diameter.

The bigger, heavier pipe would also add to the logistics challenges; 42-inch pipe weighs 5.8 tons per 40-foot length, or “joint,” Butt told the committee, and 48-inch pipe weighs 7.8 tons per joint. That means that a heavy truck trailer can carry six joints of 42-inch pipe but only four joints of 48-inch pipe.

That limitation means that 150,000 truckloads of pipe estimated to move 42-inch pipe to locations along the pipeline route will increase to 225,000 truckloads, he said.

How much this will add to the overall costs of the project wouldn’t be known until the engineering study is done (which hasn’t been decided on), but there are also pluses and minuses. It would involve higher capital costs (for the pipe) but also lower operating costs because fewer compression stations will be needed and less gas would be burned as fuel for compression.

Expansions of the gas “throughput” would be less expensive, too, because of the larger pipe, with about half as many added compressor stations compared with an expansion with the current 42-inch pipe diameter.

There are construction risks with the current design because even at 42 inches the pipe is 22 percent heavier than most pipe used in other gas pipelines in North America, but the 48-inch pipe would be 59 percent heavier than the pipe used elsewhere to ship gas.

There is large diameter pipe used on gas pipelines, Butt said, but not of the heavy, thick-walled type that is contemplated for this project. Also, none of those pipelines are 800 miles in length.

A more bottom-line concern with the added capital expense is that until more North Slope gas is found the same volumes of gas will move through either a 42-inch or 48-inch pipeline, so the “cost of service” for moving North Slope gas will be increased, possibly by 10 cents to 15 cents per million British Thermal Units, or Btus.

In the dog-eat-dog competition for future LNG markets, that may not help Alaska.

“LNG is now selling for about half of what it sold for three years ago when we started this project, so achieving the lowest-cost gas,” supplied to the market is critical, Butt told the legislators.

State officials, however, believe potential customers will take the long view and see that the extra capacity of the pipe will mean lower-cost expansions as more gas is found, and lower costs of service in the long run. Although 33 trillion cubic feet of gas reserves are now proven in two large North Slope fields — Prudhoe Bay and Point Thomson —industry officials say that once a gas pipeline is built large-scale exploration for gas will begin on the slope, which hasn’t occurred before.

Much of the slope, in the “foothills” area of the southern slope and in the National Petroleum Reserve-Alaska, is considered to be more gas-prone than prone to oil.

State and federal geologists estimate that as much as 75 trillion to 100 trillion cubic feet of conventional gas will ultimately be discovered and produced on the Slope.

Updated: 
11/21/2016 - 10:09pm

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