As we have listened to the presentations and legislative hearings on the Alaska Liquefied Natural Gas project (the project) over the past few weeks, we have developed two observations. 

The first is that we don’t believe Phase 1 of the project should proceed until firm, irrevocable commitments from credible customers to purchase volumes sufficient to make Phase 2 economically viable are first in hand. 

The second, picking up on the analogies made by some between the Alaska LNG project and those in Texas and Louisiana, is that, to help offset any property and other tax concessions made to the developers as part of the project, and otherwise realize the constitutionally-required “maximum benefit” from the project for the state, contemporaneously with any concessions the state should adopt a broad-based tax along the lines similarly used in Louisiana and Texas, and generally similar to that in effect during the construction of the Trans-Alaska Pipeline System (TAPS) in the 1970s.

We explain the first one in this column. We will discuss the second in next week’s column.

Proceeding on Phase 1 should be contingent on first obtaining firm, irrevocable commitments to Phase 2

Over the past two weeks, we have learned much more about the impact of dividing the project into two phases than we understood before.

As explained during the special session hearings, the intent behind phasing is to allow the pipeline portion of the project to proceed while the developers continue to pursue sufficient firm commitments from foreign purchasers to underwrite the economics of the gas treatment, gasification and other export-related facilities. The first portion, the pipeline, is Phase 1. The additional facilities constitute Phase 2.

The Phase 1 facilities will serve both Alaskan and export customers. The Phase 2 facilities are required to deliver large volumes from the North Slope and, otherwise, mostly to serve the export customers.

The public reasons given for pushing Phase 1 ahead of receiving sufficient firm commitments to underwrite Phase 2 are that it will help limit the period during which Alaska’s utilities will be required to import allegedly higher-priced LNG to meet the needs of Alaska’s customers, as well as accelerate the point at which the state begins to reap some – although admittedly, a very limited amount in Phase 1 – of revenue from its own North Slope gas resources.

Because it is also intended to serve export customers, the pipeline is significantly oversized to meet the demand of Alaskan customers alone. The Alaskan customers will benefit from significantly lower-priced supplies once Phase 2 is complete and the pipeline is fully utilized. But the unit (per Mcf) costs of moving only the substantially smaller volumes required by Alaskans before that, during Phase 1, are significantly higher.

A slide from a presentation during the first week of the special session hearings by legislative consultants Gaffney Cline helps explain:

The lines on the left side of the slide represent the per-unit (Mcf) delivered price levels (on the vertical axis) required to achieve a 10% overall project return (the amount most say is required to attract investment) for Phase 1 at various levels of capital cost, wellhead price, and volume.  

So, for example, looking at the farthest left side of the lowest, solid line on the chart that starts just above the dashed red line, the required delivered price level to achieve a 10% overall project return is slightly over $12/Mcf at a capital cost of $10 billion for the pipeline, a wellhead price of $1, and a volume of 500 million cubic feet per day (MMcf/D).

At the other extreme reflected on the chart – the far right of the top line – at a capital cost of $14 billion for the pipeline, a wellhead price of $2.50, and a volume of 300 MMcf/D, the required delivered price level to achieve a 10% overall project return is approximately two-and-a-half times higher, or $30/Mcf. 

Absent other factors, the projected delivered price from the pipeline to Alaskan consumers during Phase 1 is much closer to the higher end of the continuum than to the lower end.

At current levels, Southcentral demand totals about 70 Bcf per year, or an average of about 190 MMcf/D. While including the anticipated additions to demand from Fairbanks and other areas along the Railbelt increases that number somewhat, it is a stretch to say demand will reach even 300 MMcf/D, even once Cook Inlet supplies are completely exhausted and the pipeline serves the entire Railbelt.

In addition, in its presentation to the Senate Finance Committee this week, Glenfarne, the project developer, projected the capital cost for Phase 1 as between $13.2 and $16.9 billion (with a midpoint of $15.05 billion), at the high end, if not beyond, of the estimates included in the earlier Gaffney Cline presentation.

According to the Gaffney Cline chart, at that capital cost and anticipated volume level, even if the wellhead price were only $1, the delivered price to Railbelt consumers required to produce a 10% return would still be approximately $29/Mcf. At a wellhead price of $2, the price would be approximately $30/Mcf.

In response to concerns about the potential for these substantially elevated price levels during Phase 1, Glenfarne, the project developer, committed in its presentation to the Senate Finance Committee to a “$16/MMBtu locked tariff — not re-opened for cost overruns.” But as the Gaffney Cline chart makes clear, while a factor, “cost overruns” are not the biggest driver of a higher rate. Volume underruns are.

Using the same chart from Gaffney Cline, here is the range within which Glenfarne’s proposed $16 would produce a 10% return.

The range is roughly where capital costs are around $12 billion, the wellhead price is around $1.75/Mcf, and volumes are at 500 MMcf/D. Using the same assumptions about capital and wellhead costs, at the more likely Phase 1 volume level of 300 MMcf/D or less, the “breakeven” price at a 10% return is in the range of $25-$27/Mcf.

With the new Glenfarne estimate of Phase 1 capital costs, the breakeven price at a 10% return is closer to $29/Mcf.

It should concern legislators that, while Glenfarne has proposed protecting Alaska consumers from cost overruns, they haven’t offered the same protection against the much more impactful potential of volume underruns. Even holding the capital cost constant, a volume underrun from the 500 MMcf/d level on which the $16 price is based could cause an additional $9-$11/Mcf tariff increase over the $16/Mcf level.

Moreover, we remain concerned about a “locked tariff” of $16/Mcf even if there is no risk of price increases due to volume shortfalls or other reasons.

While global LNG prices are currently elevated due to the effects of the Iran War, as with the oil futures market, the current LNG futures market anticipates significantly lower prices going forward. The reason for this is simple. As highly respected Bloomberg oil & gas columnist Javier Blas explained in a column earlier this week, “An LNG Glut is On Its Way.”

Here is Blas’ view:

Before the current war broke out, the market was contending with a third wave [of supply], which was set to last from 2026 to 2030, and a likely glut. This wave is not only still in the cards — though probably delayed about a year due to the closure of Hormuz — but it should be larger and likely longer lasting. Some will come from Asian buyers’ move to finance more and more projects in North America, Africa and Latin America. But Qatar will also want to increase production, using its low cost as incentive to find buyers. That expansion is delayed — maybe six months; maybe 12; maybe even 18 months. Whatever the length, it’s largely immaterial to what happens in 2030.

Last year, the LNG industry greenlit the construction of 100 billion cubic meters of new capacity, the most ever, according to new estimates from the International Energy Agency.

‘There remains a pipeline of over 700 billion cubic meters of projects globally seeking final investment decision, including around 110 billion in the US that have received regulatory approval,’ according to the IEA. Last year, global LNG production stood at nearly 600 billion cubic meters. If everything that could get built does get built, the global LNG supply will more than double.

Would there be enough demand? I doubt it; or at least, I doubt it at prewar price levels. LNG costs will need to decline further to incentivize more consumption. …

It’s a story as old as the commodity market: Today’s high oil prices will sow the seeds of tomorrow’s low ones. For a short period, LNG costs may remain somewhat high as importing countries, particularly in Europe, rebuild their inventories ahead of the 2026-2027 winter heating season and everyone purchases a little more than needed, just in case the fighting in the Gulf flares up again. But a buyer’s market is around the corner.

Reflecting those same market factors, as of the day we are writing this week’s column, here is what the current LNG futures market is projecting, using the same delivery months as reflected in ENSTAR’s presentation to the Senate Finance Committee earlier this week:

While the price levels for the coming heating year are elevated, as projected in Blas’ column, they quickly decline to much lower levels.

Of course, as ENSTAR explained in its presentation, those prices must be adjusted to reflect the additional costs of imported supplies delivered into its system. But even after accounting for those additional costs, the projected cost of LNG imports remains below $16 per Mcf.

In its presentation, ENSTAR added $1/Mcf to the JKM price for “shipping costs” plus an additional $3-$5/Mcf for “LNG Terminal Infrastructure.” To account for those additional costs, we add the midpoint of that combined $4-$6/Mcf range ($5) to the projected JKM futures prices in the following chart, and then compare the result to the $16 Mcf “locked tariff” price, adjusted for inflation:

The columns (in red) at the bottom reflect the difference between the $16 “locked tariff” price and the JKM futures price, adjusted for the additional costs described by ENSTAR. As is clear, the difference is increasingly negative over the period; even with the ENSTAR adjustments, imports cost less than $16.

The fact that the futures price falls below the $16 “locked tariff” price demonstrates two risks.

The first is the most obvious. By agreeing to a $16 “locked tariff,” ENSTAR may be exposing Alaska consumers to higher delivered prices than those available in the LNG import market even during the limited period contemplated by Phase 1.

The second is even more important. If, as both Blas and the futures market project, future LNG prices fall significantly and, as a result, Alaska LNG, as one of the higher-priced global alternatives, is not able ultimately to contract for sufficient volumes to make Phase 2 economic, Alaskans may become permanently stuck at the “locked” Phase 1 price level, even as overall LNG prices continue to fall.

These are not reasons to cancel the Alaska LNG project. As we said previously, the analysis shows that if the project achieves full Phase 2 volumes, the per-unit cost of delivered supplies to Alaska consumers will be lower than even the lowest projected cost of LNG imports.

These are reasons, however, to condition the construction of the Phase 1 line on the project first obtaining firm, irrevocable commitments from credible customers to purchase volumes sufficient to make Phase 2 economically viable. 

Once those are in hand and Phase 2 is underway, Alaskans can be reasonably confident that the long-term gas rates they pay will be lower than those available from alternative sources. As we explain above, however, before that point Alaskans will remain exposed to paying prices higher – and potentially significantly higher – than those contemporaneously available for supplies from alternative sources. And if Phase 2 is never constructed, that situation could become permanent and increasingly burdensome to Alaskans and the Alaska economy.