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    Alaskan LNG: Two Routes to Market [NGW Magazine]


Alaska’s government has been banking on LNG as a means of monetising its stranded gas, but the market is now not attractive and a small rival project is nosing ahead. [NGW Magazine Volume 5, Issue 11]

by: Anna Kachkova

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Natural Gas & LNG News, Americas, Liquefied Natural Gas (LNG), Top Stories, Americas, Premium, NGW Magazine Articles, Volume 5, Issue 11, United States

Alaskan LNG: Two Routes to Market [NGW Magazine]

The proposed state-led Alaska LNG project has received federal authorisation, marking an important milestone. However, this step forward comes as conditions in the LNG market become unfavourable, throwing pending final investment decisions (FIDs) into doubt. Nonetheless, if Alaska wishes to find markets for its gas reserves, LNG exports appear to be its best bet, and this may compel the state and producers to work on finding a way forward. Indeed, Alaska LNG is not the only liquefaction project proposed for the state: the smaller competing Qilak LNG is at an earlier stage of development but eyeing first exports sometime early in 2025.

A step forward

The US Federal Energy Regulatory Commission (Ferc) authorisation was granted on May 21 to the Alaska Gasline Development Corp (AGDC), the state agency that backs Alaska LNG.

The authorisation covers construction and operation of a 20mn metric ton (mt)/year liquefaction terminal on the Kenai Peninsula – home to the first, if smallest, US LNG export terminal – as well as a roughly 807-mile pipeline to carry up to 3.9bn ft3/day of gas to the facility. The pipeline would however also be able to gasify inland Alaska which now relies on diesel and other refined oil products. The feedstock gas would come from Alaska’s North Slope, where a gas treatment plant would also be built as part of the project.

The federal approval has been welcomed by supporters of Alaska LNG – including Alaska Governor Mike Dunleavy – as a significant step forward for a project whose future has been in doubt in the past.

In 2016, AGDC’s three partners in Alaska LNG – ExxonMobil, BP and ConocoPhillips, with equity production – all pulled out of the project. Their exit came after the last industry downturn brought the venture’s economics into question. Initially Alaska LNG was estimated to cost up to$65bn, and consultancy Wood Mackenzie found in 2016 that the project could struggle to make “acceptable” returns at a Brent oil price below $70/barrel.


Efforts have been underway since then to bring down Alaska LNG’s cost, which was estimated to be $43bn in 2017. Engineering, procurement and construction contractor Fluor was subsequently brought in to work on a further updated cost estimate, which has been concluded but not yet publicly disclosed.

However, there are questions over whether the collapse in LNG spot prices threatens the future of more expensive projects, especially if the market remains oversupplied for some time. Even some cheaper projects with low feedstock prices, such as Driftwood LNG on the US Gulf Coast, have been postponed indefinitely.

“The capex would need to come down very sharply to make the project economic at current prices,” the Oxford Institute for Energy Studies’ (OIES) director of natural gas research, James Henderson, told NGW. “However, it should be remembered that project developers are not looking at the current market but the market in the mid-to-late 2020s, when the supply-demand balance should have tightened. Nevertheless, gas prices seem unlikely to return to a level that would justify such an expensive project and so one would anticipate a revision of costs if the development is to go ahead.”

There are also other complicating factors for Alaska LNG. ExxonMobil and BP – both major North Slope producers with large volumes of stranded gas – are once again involved in the project, having agreed in 2019 to invest a combined $20mn to help advance it. But BP is set to exit Alaska when the sale of its business there to Hilcorp Energy closes later this year.

BP was unable to comment on where this will leave its involvement in Alaska LNG. However, an AGDC spokesman told NGW that the company “has an ongoing relationship with BP and has had preliminary talks with Hilcorp.”

An AGDC board presentation from May provides further details, showing that the company is continuing to work with BP and ExxonMobil on enhancing the project’s competitiveness as well as “reviewing project cost reductions with potential project participants.” The presentation adds that discussions on the sharing of costs and the provision of subject matter experts to the project are “ongoing with strategic parties”.

AGDC ultimately wants another player to take over as lead sponsor of Alaska LNG but the market conditions could make finding one more difficult.


If Alaska wishes to develop its stranded gas, rather than leaving it in the ground, it will likely have no choice but to turn to LNG exports. “Liquefaction is really the only option as the US and Canadian gas markets do not require more pipeline gas, given the growth in shale gas,” said Henderson. “The key question is whether the gas should be liquefied in southern Alaska, having been brought there in a long and expensive pipeline, or whether it should be liquefied close to the production area but in a smaller plant.”

Indeed, this is the other option that Lloyd Energy is considering for Alaska. Its wholly-owned Qilak LNG project would be significantly smaller than Alaska LNG, with a proposed capacity of 4mn mt/year from its first phase. Under Qilak’s plans, LNG would be shipped directly from the North Slope, possibly using a floating liquefaction vessel. These plans are still at a preliminary stage, but they are moving forward.

“Qilak LNG has completed a pre-feasibility study on development concepts for the liquefaction facility and on shipping LNG through Arctic waters directly to Asian markets,” Qilak’s chairman and CEO, Mead Treadwell – a former Lieutenant Governor of Alaska – told NGW. “We are currently organising a more comprehensive feasibility study with contractors, acquiring the data necessary for permitting, having informal meetings with permitting agencies regarding our permitting which is expected to begin with formal filings early next year, and continuing conversations with offtake project developers in Asia,” he said.

The project’s breakeven cost will depend on revised construction and operational costs from an upcoming feasibility study, among other factors, including LNG market prices.

“Overall, however, we believe long-term LNG prices will prevail at levels sufficient to bring new supplies to market, and we believe that as the third closest (after Sakhalin and Indonesia) supplier to markets in northeast Asia and with access to stranded gas supplies, we will have a competitive project,” Treadwell said. “Despite current LNG prices and the current Covid-19 situation, we see demand continuing to grow in Asia sufficient to take LNG from our proposed 4-8mn mt/year project by 2027.”

The company is hoping to capitalise on the latest developments in Arctic LNG technology, possibly using a gravity-based system as is planned for Novatek’s Arctic LNG-2 as well as reproducing its winterised LNG tankers in order to gain a competitive edge, although it has not hit on a definite plan. “The Yamal Project and its Arctic LNG 2 expansion plans have shown that Arctic shipment is possible, and in the most extreme ice-coverage years, our project has just 600 miles to open water compared to 2,600 miles for Pacific-bound Yamal cargoes,” Treadwell said. And additionally it is worth pointing out the higher efficiencies of liquefaction at those latitudes: a nominal 8mn mt/yr plant could produce close to 9mn mt/yr, based on the experience at Yamal LNG.

And at a time of low LNG prices and a growing amount of choice for buyers, smaller ventures may find it easier to secure enough commercial support to proceed. “This project seems like a more sensible idea at present, avoiding the huge capex for a pipeline to take the gas south before being liquefied,” Henderson commented. “The smaller plant would also be more flexible and could always be expanded with extra trains at a later date if the market improves. The developers would also be putting a lot less capital at risk, which would clearly be a good thing in today's market when cash flow has been sharply reduced.”

However, the North Slope has around 35 trillion ft3 of proven gas reserves, a potential resource of another 200 trillion ft3 of conventional gas, plus around 590 trillion ft3 of unconventional gas that could be tapped with advances in drilling. The state will be working to establish the economic viability of Alaska LNG in order to tap far more of its gas than Qilak alone could liquefy.