Why are the warnings about Cook Inlet gas getting more dire?

Imports will be delayed, supposedly available gas may not be there, and stopgap imports will come at triple current prices. But household energy costs won’t change as much as many fear.

It’s been two years since Hilcorp announced that it couldn't guarantee gas supply beyond its existing contracts. I feel like every time I’ve heard the gas crisis discussed I’ve heard a different date for when the supply gap will begin, when imports can begin, and how much the new gas will cost. Enstar has been stepping up its warnings with nearly every announcement. So I decided to try and compile a timeline of who said what when, and what it might mean, and then went off down some data rabbit holes, and well -- this is my best take on what’s going on with Cook Inlet gas.

Utilities think it’ll take longer to construct an import facility than they did originally. If Cook Inlet gas production declines as predicted, we’ll need to import stopgap gas in little tanks on container ships --  at more than triple current prices.

Enstar can’t get anyone to promise to sell them new gas that supposedly is available in Cook Inlet. Whether or not they have to draw down their stored gas substantially in the next year or two might be a useful signal of how bad this is going to be.

We haven’t actually done anything to address the crisis yet. Lots of folks have studied and planned things, but there haven’t been any final investment decisions on any major renewable projects, gas developments or gas import facilities. The longer this remains true, the bigger the supply gap could be.

Even with all of that, consumer impacts are probably not as scary as that seems. Current contracts act as a partial buffer through 2032, even if we have to mix in some triple price gas. Especially if we work to conserve gas, and actually invest in solutions. Business and industry will be proportionally more affected than households.

Gas crisis timeline - Who said what when

“Gap begins” when predicted Cook Inlet supply is less than demand -- if a range was given, I chose the middle. “Earliest Imports ready” is the fastest possible timeline for a large scale LNG import facility of any kind. “Import price” is the price of that gas (including import costs), and “Stopgap price” is the price of importing gas through small ISO tanks on container ships before the existence of a large scale import facility.

Reasons for Enstar to worry

Import facilities will take longer than anticipated to come online: Last summer, Enstar and the electric utilities published two separate reports that estimated gas imports could be ready as early as 2027, one year ahead of their projected supply gap. Since then, Enstar has told both the legislature and the media that their consultants now say it can’t happen before 2030, a timeline that will continue to slip until they make a final investment decision on an import facility.

Enstar needs more gas than it used to: Enstar has started supplying gas to electric utilities. At the end of 2022, Enstar contracted to provide 1 Bcf (billion cubic feet) per year of gas to GVEA for two years. When HEA’s Hilcorp contract expired this spring, Enstar committed to sell 3-4.5 Bcf to HEA for a year. This means that Enstar is projecting to need 37 Bcf of gas for the upcoming year, significantly above the recent average of 33 Bcf per year. 

Enstar’s contracts don’t cover all its needs: This isn’t actually new. Every year, Enstar files a “Gas Cost Adjustment” with the RCA, which both sets its customers’ gas price for the following year, and predicts where that gas will come from. Enstar generally predicts that around 10% of its needs will come from “undetermined supply” or from its gas storage reserves. In practice, both Hilcorp and smaller producers have supplied more gas than predicted each year, and Enstar hasn’t had to draw down those reserves (gas storage is used heavily for seasonal demand fluctuations, but hasn’t been a contributor to overall supply). Now, higher volumes make that gap larger -- around 14% of expected gas needs.

Based on gas cost adjustments and gas cost balance reports filed with the RCA. 

This is likely why Enstar is raising the alarm rather than the electric utilities. Chugach and MEA have all their gas covered under contract or self production until  2028, and GVEA doesn’t need gas to generate power (though they’d prefer to buy gas power). Electric utilities also have the ability to reduce gas use through adding renewable energy, while a gas utility cannot.

Suppliers may not fill those gaps as they have in the past: Relatively little gas is supplied by small (non-Hilcorp) producers, but what there is is poised to shrink. Last summer, Vision and Enstar renegotiated their contract for smaller volumes based on poor production. Enstar was waiting on drilling results from Furie/Hex at the end of 2023 to determine future gas amounts, but now says they anticipate no gas from Furie/Hex after March 2025. Furie will not drill new wells this season.

Hilcorp’s signals have been more mixed. They’ve clearly said that their entire well drilling program is intended to meet existing contracts (see graph below). They also agreed to sell Enstar 3.5 Bcf more for one year to cover most of HEA’s demand (Enstar agreed to cover the rest through their own existing contracts). That agreement only increased the price a little, but was full of provisions to mitigate supply risk -- requiring Enstar to use some of its stored gas before buying the extra ‘call’ gas it usually buys in winter, and exempting Hilcorp from penalties on some amount of delivery failure.

From Hilcorp’s presentation to the legislature February 2024

Normal variation could make things better or worse: Gas use varies quite a bit year to year, around 11%. In cold years, we use more gas for heat. On the electricity side, we use substantially more gas when GVEA is able to purchase power from southern utilities, and a little bit more in dry years when there’s less energy available from hydropower.   

2024-2026: Will producers sell gas beyond their firm contracts, or will we draw down gas storage?   

The state’s forecast modeled gas pool decline. The dropoff is steep, but not as steep as the dropoff in firm gas contracts. This means there’s a substantial amount of gas that is theoretically economic to produce in Cook Inlet, but no one has promised to do it -- represented by the green bars in the graph below.

From the June 2023 BRG report by Enstar and Electric utilities.

The space between the bottom of the green bar and the purple ‘medium demand’ line was pretty small in 2023 -- and was indeed supplied from Cook Inlet. But that uncontracted wedge gets bigger quickly. And while Cook Inlet producers may still be able to supply that gas, they certainly aren’t willing to promise it.

Producers might sell gas to Enstar on a non-firm basis: Gas producers are probably motivated to be conservative with their firm contract promises. If they do produce gas beyond contract minimums, they might sell it to Enstar for somewhere around current prices, as has occurred in the past.

Or we might use gas we’ve already stored: If producers can’t produce more, we’ll have to turn to storage. Since the CINGSA gas storage facility was created, 9.7 Bcf more has been put in than taken out, and it also contains extra gas that was discovered when it was built, for a total of 13.5 Bcf working gas there today. Additionally, Hilcorp has its own storage, which had around 26 Bcf stored as of February.

Neither of those outcomes is a crisis. But how much we need to draw down gas stores may be a sign of what comes next.

2027-2029: Renewables, new gas, or super-expensive stopgap imports?

This time frame seems like the biggest wild card. Ordinary variation in demand and drilling success might mean that we have a major supply gap in this time frame, or none at all. And while it’s too soon for large-scale imports, this is enough time to make significant changes to gas demand, storage, supply, or all three. 

Renewables could push demand down -- if we sign contracts soon: In my last post about Cook Inlet gas, Alan and I analyzed how proposed renewable energy projects and ambitious efficiency measures could delay the supply gap. 

The recently-passed HB 307 improved the prospects for all these renewable projects (assuming it gets signed by the Governor), by reforming the property tax structure for IPPs, and removing wheeling fees. But we’re midway through 2024, and no power purchase contracts have been signed yet. It seems likely that some timelines will shift later, and it remains possible that none of these projects will happen at all.

Utility demand of 65 BCF from the mid-case of the 2023 working group report (p 12-14), production data from DNR’s truncated 2022 forecast.

Gas storage might help a little: Chugach is planning to rely on new gas storage by 2027 or 2028, allowing it to save some of the near term production from its Beluga River gas field for later years. Chugach often sells gas energy to GVEA, so if they stored more gas it might push up GVEA electricity prices even as it delays their own shortfall. Cingsa also has expansion plans, and the legislature just passed a bill setting up a framework for regulation of third party gas storage. This is important for a future import scenario, and for reliability on super cold days, but doesn’t help overall supply issues much. Hilcorp has storage already, and small producers seem unlikely to end up with so much gas they can’t sell it.

New gas wells show diminishing returns, but without them, production would likely crater: Overall, the Cook Inlet data shows that well drilling hasn’t slowed down, but we get a lot less gas out of each well. This makes it hard to get more by drilling more. Nearly all of the recent wells have been drilled by Hilcorp, which has said they don’t expect to produce more than their current contracts require, and are drilling to offset the natural declines. So if Hilcorp backs off drilling, they would likely produce a lot less -- as they threatened to do when the legislature suggested making them subject to corporate income tax.

Cook Inlet well data from the state’s AOGCC data miner - gas development wells only

From the state’s AOGCC data miner

Small producers might produce more gas than expected -- if they get financing and/or royalty relief: In contrast to Hilcorp, two of the small gas producers do say they could potentially increase gas production between now and 2030.

Bluecrest has gas reserves that require a new offshore platform, and a $400 million dollar investment they haven’t been able to secure. This gas would cover around a quarter of current Railbelt demand for 13 years -- not enough to change the long term picture, but enough to buy time. However, they say the earliest it could happen is 30-40 months after financing -- 2027 if that happens today. AIDEA now has the authority to lend money for Cook Inlet gas development from a Cook Inlet Reserve based lending account (from HB 50). But making use of that would require a future legislature to fund the account with a rather large amount of money -- not guaranteed, and at least a year away. Bluecrest is currently in forbearance with its existing AIDEA loan.

Furie/Hex also says they could produce more gas from their Kitchen Lights Unit, possibly ramping up to 12 Bcf/yr (17% of current demand) by 2028. But they framed this to the legislature as contingent on using the Inlet’s single jack up rig, which isn’t certain or quick (they’re still working on permits, and Hilcorp already has plans to use the rig in 2024). They also framed it as contingent on financing, and contingent on royalty relief (which they haven’t gotten), and recently confirmed they will not drill this summer. I’m also not sure what portion of this gas is already included in the state’s Cook Inlet forecast, since it’s a currently producing pool. 

We could import super-expensive gas in little tanks on container ships -- and we probably will: One thing that’s gone little noticed in Enstar’s dire warnings is what happens if we have a shortfall and no import facility. In that case, Enstar has said we’d need to import gas in ISO tanks instead (shipping-container sized tanks, stacked up on container ships), and that it would cost $25 or $30 per Mcf -- over triple current prices. 

In the mid-range predictions -- this happens. They all show a supply gap at least a couple years before an import facility. And developers’ timelines for new renewable energy or new gas are more likely to be optimistic than pessimistic. This will cost the Railbelt $150 million to $600 million extra per year (beyond the current costs of gas) until large scale imports come online, with costs ramping up as the gap grows.

Triple prices sounds big and scary, but around half the Railbelt’s gas will still be under contract at prices close to today’s through 2032. And a good chunk more theoretically will come from Cook Inlet. For example, the utility mid-case forecast for 2029 shows around half the gas from existing contracts, and only around a quarter coming from outside Cook Inlet. Triple price stopgap gas could make up a huge portion of the total cost in this scenario, but existing contracts buffer their impact, leaving the overall price within the range predicted for large scale imports.

Current contracts include CEA’s owned gas from Beluga River. Prices modeled in today’s dollars at $8/Mcf for gas under contract, $10/Mcf for new Cook Inlet gas, and $27.50 for stopgap ISO tank gas (halfway between Enstar’s two quoted estimates).

I’ll cover the cost impacts of those large scale imports in the next section. If we don’t get imports online as predicted, and end up with an extended period where we’re burning triple-price stopgap gas to heat our homes, using diesel power, etc… Then the extra costs could add up to billions.

2030 and Beyond: LNG imports -- when will we get them, and what will we pay?

Why isn’t Enstar pulling the trigger on an import facility right now? There’s a lot of uncertainty in the forecasts, but once you start getting to this time frame, they all collapse into “not enough”. If you add Bluecrest and Furie’s optimistic forecasts to aggressive renewable development, we still run short of local gas in the early 2030s. This is basically inescapable because most gas is used for heat. We can, and should, electrify heat, but there isn’t a way to step up both renewable buildout and heat electrification quickly enough. 

Enstar recently filed an application to extend their service territory to encompass a potential import site. But while the urgency of their warnings has increased, they’ve moved more slowly on an investment decision -- originally planned for the end of last year. This is the piece of the Cook Inlet gas puzzle that confuses me the most. Stepping up warnings and delaying action looks like a move to try and get someone else to solve the problem -- but they haven’t clearly asked anyone else to solve it. Most of what they said to the legislature was along the lines of ‘do what the gas producers want’ -- but what the gas producers say they want might change the numbers a little, but won’t solve the long term decline. 

What will imported gas cost? The first utility reports on the gas crisis last summer put the costs of imported gas at around $13 per Mcf, compared to the current average of around $8. More recently, Enstar has used higher numbers -- $15 or $16 per Mcf. Pacific LNG prices haven’t changed substantially since last summer. Possibly the numbers are higher because the consultants who said import infrastructure couldn’t happen until 2030 also said that infrastructure would cost more. Possibly no one knows what prices will be and folks are just pulling numbers from a large hat of possibilities in every interview.

For households, electric rates probably won’t change much, but heating costs for Enstar customers will: I analyzed the impact of gas costs and renewables on both electric and heat rates as part of my post on natural gas vs. heat pump costs earlier this year. It matters less than most people suspect. Gas costs make up around 20% of total electric costs on the Railbelt, for around $170 million per year. Doubling that would matter -- but it wouldn’t come close to doubling electric bills. 

Gas efficiency and non-gas components of the rate (including other fuels) are held constant, and renewable energy is modeled at $0.08/Kwh.

On the other hand, 75% of a residential gas heat bill from Enstar is the gas cost. Doubling the gas cost increases the bill by 75%. Yet it still remains well below the cost of heating oil. Nearly 40% of Railbelt households don’t have gas heat, and outside the Railbelt, almost no one does (and their oil is usually a lot more expensive).

See detailed assumptions and versions that include heat pumps in this post

Gas costs are a bigger deal for commercial and industrial users: For both electricity and gas heat, fuel costs are a larger portion of your bill the more energy you use. Fuel costs are captured in a per Kwh “Cost of Power Adjustment”  (COPA) for electric customers, and a per ccf “Gas Cost Adjustment” for gas customers. Those costs are the same for every customer. Meanwhile, the rest of the per-unit charges are much smaller for large users. For example, the COPA is less than a third of an electric bill for an HEA residential customer, but 85% of an electric bill for the Marathon oil refinery. 

Chicken and Egg -- are all the options delaying all the other options?

In their presentations to the legislature, gas producers mentioned that possible competition with gas imports, a pipeline, or renewables makes their investment more uncertain. But that could go in all directions. Why invest in in imports if local gas might become available after all? Why invest in renewables if utilities might sign long term gas contracts that don’t leave room for them? The risk, of course, is that we don’t invest in anything at all, ride the downward slope of Cook inlet production, and find ourselves in a few years with nothing but $25-$30 per Mcf ISO tanks of gas, and all the solutions years farther off than they would be if we pursued them today. I’d like to think we’re not going to do that, but I’m not so sure.

In Conclusion

Someone should probably do something. Specifically, Enstar should make a final investment decision on an import facility, all the Railbelt utilities should sign contracts for large scale solar and wind facilities, and the rest of us should make our buildings more efficient. We said the exact same thing before, but I’ll repeat it until we do it. Doing it sooner minimizes the likelihood and quantity of triple price stopgap gas imports. And if we do end up with more Cook Inlet gas than expected, those actions will still set us up well for the future. It’s theoretically possible that an import facility could be rendered useless by a combination of amazing short term gas production and a fast buildout of the North Slope pipeline that nearly everyone’s given up on. It’s also possible that if you leap off a cliff, someone will toss you a parachute before you hit the ground.

In the meantime, I’ll be watching what happens with Enstar’s gas supply in the next couple years to see how hard that landing might be.