Collapsing oil prices have delayed at least two North American liquefied natural gas export projects, but they haven’t stopped Alaska’s massive LNG venture in part because of its size, projected timelines and a partnership involving some of the world’s largest companies, officials said.
“Our mission hasn’t changed, and to my knowledge none of the investing companies are looking to change that at this time either,” said Steve Butt, senior manager for Alaska LNG and an Exxon employee.
Butt has referred to the proposal — which comes with an estimated price tag between $45 billion and more than $65 billion — as a “gigaproject,” a supersized megaproject involving the state, Exxon, BP and ConocoPhillips as equity partners.
If realized, the project would tap the North Slope’s vast quantities of natural gas, ship it down an 800-mile-long pipeline, super-chill the gas at a Southcentral Alaska plant, then load liquefied gas aboard tankers bound for Asia.
With multiple huge facilities to construct, it is a giant among the dozens of LNG export projects being pursued for development in the U.S. and around the world.
Most aren’t expected to be built, despite growing demand for LNG, said Larry Persily, federal pipeline coordinator.
Persily said he never heard analysts put much faith in one delayed project — a floating liquefaction facility off the Texas coast. Officials involved in the Excelerate Energy project recently told federal regulators they had at least temporarily suspended the project following the dizzying drop in energy prices.
“Excelerate has never been a producer,” Persily said. “They have nowhere near the balance sheet of Exxon.”
And although the Pacific Northwest LNG project in Canada has also been delayed, it is still considered a leading contender for construction in British Columbia, according to Persily.
But that project — which involves the Malaysian-owned energy company Petronas — has its own unique circumstances. “They have some political problems back home in Malaysia,” Persily said. “Companies are getting pressured to keep money at home.”
Also, the company has not found enough buyers at adequate prices, he said. “They are going back to the proverbial drawing board, to see if they can drive project costs down,” Persily said.
One key difference between the two deferred projects and the larger Alaska LNG effort is they’re on much different timelines. Those projects expected exports to begin in five years or less, with Petronas, for example, facing a final decision to invest.
Meanwhile, Alaska LNG is still in an early study phase.
Officials with each of the equity partners for Alaska LNG told Alaska Dispatch News they are still committed to the project as they were before, with all parties focused on completing the preliminary engineering and design efforts expected to wrap up this year.
A critical decision point comes next year when the companies decide whether they’ll move to more extensive studies in a phase known as front-end engineering and design, or FEED, before they face the final critical decision to invest in 2018 or 2019.
Then, following an estimated seven years of construction, gas isn’t expected to flow off the North Slope until 2025 or 2026, although some, including Gov. Bill Walker, want that schedule expedited.
By then, today’s LNG prices may be a distant memory.
Economy of scale
Another factor that might help the Alaska project is its enormity. With gas expected to flow for three to five decades, it will be designed to weather fluctuations in the price of gas, said Butt.
“Short-term price movements don’t impact a project with a very long life the same way they impact projects with a very short life,” Butt said. “Alaska LNG has a very long life.”
Alaska LNG has other advantages, officials said. Long since discovered, the gas is a known quantity so there’s no exploration risk and expense. The project is closer to Asia than others, reducing transportation costs. And the gas owners can control nearly all aspects of the project, from the gas fields to the docks where tankers are loaded.
Another advantage to Alaska’s project is its equity partners, BP, ConocoPhillips and ExxonMobil, three of the world’s largest companies, said Persily.
Keeping the project as inexpensive as possible is key, Butt said. “We’re trying to reduce risks, costs, get permits,” he said. Those steps will help the companies determine if going to the FEED stage makes sense, Butt said.
John Minge, president of BP America, said next for the project this year is the state’s Department of Natural Resources must decide whether Alaska will take its royalty gas in kind, meaning as gas, or in equivalent value. Taking the gas as royalty means the state sells its own gas.
Additionally, the parties have to agree to fiscal terms to be ratified by the Legislature, he said.
“The projects could be delayed” if those things don’t happen, Minge said.
Senate Bill 138, passed last spring, laid out the details. “The legislation allows the state to take ownership of about 25 percent of the gas produced for the project in lieu of receiving payments for its royalty share and production taxes,” Persily wrote in April. “The state would then sell its 25 percent of the gas and use the proceeds to pay its processing, pipeline and liquefaction expenses, depositing the balance in the state treasury.”
The state’s royalty share for oil and gas production is typically 12.5 percent.
This article was written by Alex Demarban from Alaska Dispatch News, Anchorage and was legally licensed through the NewsCred publisher network.