oint Thomson, located on Alaska’s North Slope 60 miles east of Prudhoe Bay, has an estimated 8 trillion cubic feet of natural gas and 200 million barrels of natural gas condensate, approximately one-quarter of the total projected gas available on the North Slope. That gas has been “stranded” for more than forty years by the economic and physical realities of bringing it to market via either the construction of a pipeline hundreds of miles long or the need to ship it across arctic waters.

When crude oil is produced in Alaska, it is usually accompanied by gas, which is generally reinjected back into the ground. This is a benefit if a field needs additional pressurization.

But “this is an especially difficult problem for Point Thomson because the pressure of that particular field is so high that reinjecting the gas is cumbersome,” says Christine Resler, president and CEO of ASRC Energy Services. “Having the ability to export the natural gas makes the economics of Point Thomson significantly more attractive.”

Qilak seeks to capitalize on that fact, says Qilak Chairman and CEO Mead Treadwell, former lieutenant governor of Alaska. “We believe we’re competitive by starting first with a field that benefits from gas production on the oil production side, but also by starting with a small enough quantity that the risk in the marketplace is less.”

There are currently two proposed plans to bring natural gas reserves at Point Thomson (which began operations in 2016) to market: an 800-mile pipeline or, as proposed by Qilak LNG, directly exporting the gas from Alaska’s North Slope to Asian markets via icebreaking ships.

In October 2019, Qilak LNG signed a Heads of Agreement with ExxonMobil to reserve at least 560 million cubic feet of natural gas per day for the proposed Qilak LNG North Slope project.

Initially the proposed project would have an export capacity of 4 million tons per year over a twenty-year term, using an off-shore liquefaction plant to process the gas into liquefied natural gas (LNG) before it would be loaded into icebreaking LNG carriers to take it to its final destination.

Qilak had already conducted a pre-feasibility study of its proposal, supported by Aker Arctic, which specializes in development, design, engineering, consulting and testing services for ice-going vessels, icebreakers, offshore marine structures, marine transport solutions, and ports.

The study examined the company’s plan to pipe gas a few short miles from Point Thomson to an offshore LNG processing facility, in this case a gravity-based structure that would be floated in and grounded in about 45 feet of water. It would be equipped with storage facilities, a liquefaction plant, and off-loading arms to serve ships.

A gas conditioning plant at Point Thomson would remove CO2 before the natural gas was moved offshore.

According to the pre-feasibility study, shipping LNG directly from an offshore facility in the Beaufort Sea would have lower capital costs than constructing a pipeline. “If you take the latest cost for three gas pipelines, which is $1,900 per ton of capacity of production, we’re at $1,250 per ton, so we’re much less expensive,” says Treadwell.

The success of the Russian Yamal project, which employs icebreaking LNG carriers to bring LNG from the Yamal LNG plant in Sabetta through the Russian Arctic, points to the feasibility of the Qilak proposal. Qilak could use similar icebreaking carriers: “Qilak concluded that with the available gas supply, competitive project economics, and a partner willing to utilize Alaska’s gas for power and city gas in Asia, the Qilak LNG 1 project can be economically and technically viable,” according to Aker’s pre-feasibility study fact sheet.

With global demand for LNG approaching 400 million tons per year (it increased to 360 million tons per year in 2020, according to Shell’s latest annual LNG outlook), Qilak’s 4 million ton per year projection for the first phase of the project is just about 1 percent of current global demand. And the small size of the project “might be a good thing,” says Resler, “because it will give the market time to accommodate the additional supply.”

While 2020 was a volatile year for LNG with periods of both oversupply and tightness, overall, “LNG is set for stronger growth, as domestic supply in key gas markets will not keep up with demand growth,” according to McKinsey & Company’s Global Gas Outlook to 2050 report.

LNG demand is expected to grow 3.4 percent a year to 2035, “with some 100 million metric tons of additional capacity required to meet both demand growth and decline from existing projects.” Growth is expected to slow from 2035 to 2050, though an additional 200 million metric tons is still expected to be needed.

LNG is a cleaner source of energy and has lower CO2 emission than coal. As such, it’s a resource that’s already being produced that many anticipate being a transitional fuel on the pathway to zero emissions. Though some argue that the dependence on fossil fuels should be eliminated more quickly, the reality is that reduction and eventual elimination will take both time and new technologies.

After signing the Heads of Agreement in 2019, ExxonMobil and Qilak LNG anticipated starting a full feasibility study in 2020 with the target of reaching an investment decision by 2022. As it disrupted many things, the pandemic delayed the formal feasibility study, says Treadwell.

But while plans have slowed down a bit, they definitely haven’t been halted. “We’ve spent a lot of time in the last year and a half designing the feasibility study and doing some preliminary work on it in terms of shipping and ice conditions and assembling partners for the feasibility study, which include contractors that we would name at the start of the study as well as potential funding partners and some Asian engineering off-takers and ship operators,” says Treadwell. “So we’ve been spending a lot of time in the marketplace, and the biggest challenge of COVID is we were just getting started with some very interested trading companies, ship operators, and liquefaction folks, and the inability to meet with people face-to-face has been a big challenge.”

In light of ongoing trends away from the use of fossil fuels and increasing interest in the reduction of carbon footprints, Qilak LNG has taken advantage of the delay to add a screening study on ways to further reduce carbon emissions during production, liquefaction, and shipping to the feasibility plan.

Qilak LNG is now hoping to commence the full feasibility study this year. At the end of the feasibility study, if the project continues to show potential, the company will move into Front End Engineering Design (FEED).

“If the feasibility study continues to show that the process is valid, we will go into FEED,” says Treadwell. The feasibility study, FEED, and permitting are estimated to cost about $150 million, and that’s where those potential funding partners would come in. The offshore plant and the pipeline are estimated to cost about $5 billion total, which could include equity as well as potential funding from some form of public debt. At present, the project is not seeking funding from the State of Alaska.

Assuming there’s final determination to construct the project after the feasibility study, FEED, and permitting phases, Qilak LNG anticipates delivering LNG in 2027 or 2028. “The feasibility study, FEED, and permitting will all take time, and then you need to install the gravity-based structure during a summer season, and you have to have done your testing and pipeline construction,” says Treadwell.

Resler of ASRC believes the project has merit both economically and environmentally.

“Prudhoe Bay is a giant gas field with reasonable proximity to Asia, and if there isn’t a gas pipeline, the only way to transport natural gas long distances is to liquefy it. It is in the best interests of Alaska to monetize this resource. The operations infrastructure [except the LNG plant and transportation] already exists. Natural gas is plentiful and will be an energy source for many years to come, and if it doesn’t come from Alaska, it will come from somewhere else. Given the infrastructure we already have on the North Slope of Alaska and the wells we already have, from an environmental standpoint it makes sense to produce it in Alaska.”