The Friday Alaska Landmine column: Impact of LNG imports on the Cook Inlet gas market

Some claim using LNG imports to supplement traditional Cook Inlet supplies will dramatically spike Southcentral gas costs. It won’t; here’s why.

One issue some raise when discussing using LNG imports to supplement traditional Cook Inlet supplies is their potential impact on utility gas costs. Indeed, some have claimed that LNG imports could increase the cost of gas to Cook Inlet utilities by 50%.

But that hugely overstates the case. While gas production from the Cook Inlet is in decline, it will not disappear overnight. Indeed, according to the “Alaska Utilities Working Group Phase I Assessment: Cook Inlet Gas Supply Project” (July 2023) (the “study”), the most recent, detailed, publicly available study on the issue, production from the Cook Inlet is not projected to disappear over the next 16 years. Instead, it will decline gradually, the corollary of which is that the need for LNG imports will only increase gradually.

Here is the data from that study in chart form:

The light blue line across the top (65 Bcf) represents the overall size of the Cook Inlet utility gas market included in the study at normal demand (the “medium” case). The dark blue bars represent the amount of that market projected to be met from traditional Cook Inlet supply sources under current contracts. The green bars represent the additional amount of “lower-risk uncontracted demand, expected to be supplied [over the period] from Cook Inlet remaining reserves.” The red bars represent the remaining “unmet” portion of the demand under the study’s medium demand case, which presumably would be supplied by imported LNG. The number of LNG tankers required per year to deliver that amount of LNG (at a cargo size of 150,000 cubic meters) is in the yellow bars.

As is clear, while the portion of the Cook Inlet market potentially supplied by imported LNG would increase over time, it would not replace traditional supplies in their entirety even by 2040, the end of the time frame included in the detailed portion of the study. Even at that point, 13 Bcf, or a little over 20% of the 60 Bcf market, would still be supplied from traditional Cook Inlet supply sources.

So, what does that mean for the price? The study also enables some insight into that.

As we explained in last week’s column, the study includes price projections of various supply options to meet the unmet demand. Here is the chart we included then:

We can estimate LNG’s price impact by applying these prices to the supply/demand balance reflected in the chart at the top of this column. In the example below, we have maintained the cost of the supplies provided under the Cook Inlet supply contracts currently in existence at the $8.65/MCF “Supplier Gas Cost Charge” reflected in ENSTAR’s most recent tariff. We have priced the portion meeting the “lower-risk uncontracted demand, expected to be supplied from Cook Inlet remaining reserves” at the lower end of the range for the incremental supply of “Cook Inlet Gas” shown in the table above ($9.30/MCF). And we have similarly priced the LNG supplies required to meet the remaining “Unmet Demand” at the lower end of the range for Kenai LNG shown in the table above ($12.00/MCF).

The result shows the real (not inflated) “blended” cost of supply as the sources shift over time. To keep it simple, for the purposes of this analysis, we have not included any adjustment for inflation or the higher cost of new supplies from the Cook Inlet as the existing fields are depleted and newer, more expensive fields are developed to replace them.

The results show that while the “real” (unadjusted) blended price, in the blue bars, does increase over time as, first, the portion meeting the “lower-risk uncontracted demand, expected to be supplied from Cook Inlet remaining reserves,” and then, second, LNG imports are added to the mix, even by the end of the 16-year period, the price has only grown in real terms by 31%, or at a compound annual rate of only 1.7% per year.

Even viewed from the perspective of the change in price year-over-year, as the red line on the chart does, the largest change in any given year is 2028 when a combination of a jump in the portion meeting the “lower-risk uncontracted demand, expected to be supplied from Cook Inlet remaining reserves,” and the introduction of the first deliveries of imported LNG cause a temporary price jump of 5.1% over the previous year. In all of the other 15 years, the year-over-year increase stays at or below 3.5%, and in ten of the 16 years, below (and often well below) 1.5%. In none of the years, or even over all of the years in the aggregate, is there anything approaching the type of 50% price “spike” some have speculated will occur in attempting to justify a state subsidy of some Cook Inlet gas producers.

The price impact is even more muted in the study’s “low demand” case, where renewables are installed at a faster pace than anticipated in the “medium” (normal demand) case.

There, while the real price continues to grow by a compound rate of 1.7% over the 16-year period, because of the deferral in the need for additional supplies, the largest change in any given year is 4.2%.

Of course, in all of the cases, there is an issue late in this decade, before the lowest cost LNG option (described in the study as “Kenai LNG”) becomes available in the early 2030s. As the chart at the top of this column shows, in the medium (normal) case, projected Cook Inlet supplies are insufficient to meet full demand beginning in 2028. The issue is how to fill the resulting “Unmet Demand” until Kenai LNG, the lowest-cost LNG option, is in place.

But as the study shows, that problem is relatively small in scale. Under the medium case, the “Unmet Demand” during that period is only 8 Bcf in 2028, 14 Bcf in 2029, and 16 Bcf in 2030, or 38 Bcf in the aggregate. Using the “Barge/Small LNG carrier” option as a substitute for those volumes, overall gas costs still only rise significantly in two years of that period before falling back to previously projected levels once the larger Kenai LNG project is in place.

Overall, prices increase over the full 16 year period still only at an annual compound rate of 1.7%. Because a significant downswing follows the upswing in prices, a typical price-smoothing approach (using average prices) over the period from 2028 to 2032 should mitigate any concerns.

Of course, if additional traditional gas supplies from Cook Inlet sources can meet the aggregate unmet need of 38 Bcf over the 2028 -2030 period at a lower price than the “Barge/Small LNG carrier” option, the utilities should pursue that option instead. But any such interim measure should not delay the effort to put the lower-priced Kenai LNG option in place as soon as possible, or continue any subsidies beyond the end of that transition period.

As the study points out — and as we discussed in last week’s column — the projected cost of developing additional Cook Inlet gas supplies beyond the portion used to meet the “lower-risk uncontracted demand, expected to be supplied from Cook Inlet remaining reserves” is substantial, varying between $9.30/MCF and $25.50/MCF, with a midpoint in that range of $17.40/MCF. With a projected price range of between $12.00/MCF and $13.60/MCF, and a midpoint of $12.80/MCF, the Kenai LNG option is significantly cheaper.

Given those parameters, what puts Cook Inlet consumers at risk of future price spikes is the reverse of what some are claiming now. The risk comes from injecting any delay into the lower-priced Kenai LNG project, not pursuing the lower-priced project itself. The sooner the project is up and running, the more stable the price and lower the risk of supply shortages will be for Southcentral utilities and consumers.