Railbelt Cooperatives Facing Critical Decisions On Natural Gas Supplies and Renewable Power

Although AETP is editorially independent, it receives its funding from the Alaska Public Interest Research Group (AKPIRG). AKPIRG is an institutional member of the Renewable Energy Alaska Project (REAP) and currently holds the Small Consumer seat on the Railbelt Reliability Council’s (RRC) Board–both REAP and the RRC are mentioned in this article.

A full list of acronyms, organizations, and technical terms used in this article can be found at its end.

By Brian Kassof

In early 2024 the four Railbelt electric cooperatives will face a decision on how to deal with forecast shortages of Cook Inlet natural gas. One option is to join with Enstar, a utility that provides natural gas for heating in Southcentral Alaska, to pursue a strategy designed to bring in new supplies of natural gas that will allow them to maintain their current reliance on it for power generation. Another is to adopt a more flexible approach that will allow them to reduce their dependence on natural gas between now and 2040 as they integrate more renewable sources of power.

The Railbelt is the area served by the Alaska Railroad, running north from the Kenai Peninsula through Fairbanks. The four Railbelt electric cooperatives are Homer Electric Association (HEA), Chugach Electric Association (CEA), Matanuska Electric Association (MEA), and Golden Valley Electric Association (GVEA).

Enstar and the Railbelt cooperatives have different interests and incentives. Enstar will almost certainly press for a project that allows for current levels of use–its business is selling natural gas and it has no choice but to pursue a self-preserving project capable of bringing in large quantities for the foreseeable future. Having partners will help spread costs and make it easier to negotiate contracts to purchase gas. A joint project with the non-profit electric cooperatives might also make it easier for Enstar, a privately owned, for-profit business, to pursue state subsidies to build the infrastructure needed to bring in new gas supplies.

The mechanism for pursuing a joint project would be the Alaska Utility Working Group (AUWG), a coalition of Railbelt utilities that Enstar helped form in May 2022. Enstar has hired a consulting firm (the Berkeley Research Group, or BRG) to conduct a study on how to replace Cook Inlet natural gas. BRG is expected to issue the final part of this study sometime in December or January.

Unlike Enstar, however, the electric cooperatives have the option to reduce their dependence on natural gas by integrating more large-scale renewable energy projects into their generation portfolios. Two other on-going studies suggest that the cooperatives and their members might be better served by taking the second, more flexible approach. One is a report commissioned by CEA, that shows how renewable integration could significantly reduce the amount of natural gas it will require in the future. Another forthcoming study by the National Renewable Energy Laboratories (NREL) indicates that a system relying mostly on renewable power would actually save Railbelt consumers money compared to one that relies on gas-powered generation.

Chris Rose, Executive Director of the Renewable Energy Alaska Project (REAP), stresses that the electric utilities’ decisions about future gas supplies are also decisions about the future of renewable power in the Railbelt. He and other renewable energy advocates warn that a commitment to bringing in gas at current levels, in the form of expensive infrastructure and long-term contracts, will prevent the development of large-scale renewable projects, even though they believe these will be more cost effective. If the utilities plan for a future where they rely on natural gas generation, they will ensure that is exactly what will happen.

Concerns about the Gas Supply

Recent alarm about the Cook Inlet gas supply dates to April 2022, when Hilcorp, which is responsible for 85 percent of production, announced that it would not be able to renew its contracts to supply natural gas to the utilities when they expire (HEA’s current contract ends in 2024, MEA and CEA’s in 2028, and Enstar’s in 2033). Cook Inlet is currently the only source of natural gas in the Railbelt. Supplies are expected not to be able to meet current levels of demand by 2027.

While some efforts are being made to spur production in Cook Inlet, officials from the Railbelt electric utilities see no choice but to find a new source or sources of natural gas. At a November 29 legislative forum, the chief executives of the four Railbelt electric cooperatives all seemed resigned to begin importing liquified natural gas (LNG) at some point in the next few years. The Railbelt electric utilities currently rely on natural gas for about 75 percent of their power generation (the figure is over 80 percent for HEA, CEA, and MEA–GVEA still relies on coal-fueled generation for some of its power, but its strategic generation plan calls for it to increase its use of gas-powered generation in the next few years).

Importing LNG will be expensive. Cook Inlet gas currently costs about $8 per thousand cubic feet (mcf); BRG estimates that imported LNG will cost at least $12 per mcf, an increase of about 50 percent. Fuel accounts for about 30 percent of the cost of delivered electricity on the Railbelt. So if the cooperatives become reliant on imported LNG to fuel most of their generation, Railbelt consumers should expect to see about a 15 percent increase in their monthly bills by the early 2030s just to cover higher fuel costs. The only other option for new gas supplies would be a pipeline from the North Slope, which would require more time and cost billions of dollars to build.

Even if they committed tomorrow to moving to renewable power as quickly as possible, the Railbelt utilities would need to find a new source of gas–even a system relying on 80 percent renewable generation would still need some gas to help balance the system and meet peak loads. But near-term decisions about the future of power generation in the Railbelt will inform the type of infrastructure they build and contracts they sign to bring in that gas.

Future Gas Needs—3 Outlooks

The decisions about infrastructure and contracts will be closely tied to how much gas the utilities believe they will need over the next 15 to 20 years. The three on-going studies–the one commissioned by the AUWG, the one commissioned by CEA, and the NREL study–provide a fairly wide range of answers to this question. The variability of these answers reflects both the underlying assumptions of the different studies and the impact that the electric cooperatives’ upcoming choices about power generation will have.

Final versions of all three studies are expected in late December or January. The AUWG study, while acknowledging that renewable energy might play a role in the Railbelt’s future, works from an assumption that demand for natural gas will remain relatively stable over the next fifteen years. The CEA and NREL studies look more closely at scenarios where renewable energy could displace more substantial amounts of the natural gas used by the electric cooperatives. The NREL study also suggests that the displacement of natural gas by renewable generation might keep energy prices lower.

The AUWG and CEA studies will recommend specific strategies to bring in new supplies of natural gas. Because of the long lead time for these projects–it is expected to take at least three years to get an LNG import facility up and running–there will be considerable pressure on the utilities to decide on a strategy within several months of the studies’ completion. The electric cooperatives will have to decide whether or not to collaborate with Enstar. If they do collaborate, they will need to decide what level of commitment they are willing to make to build import infrastructure and sign joint contracts. If not, they will need to plan their own LNG import project.

AETP will be posting a more in-depth discussion of the gas needs outlined in these three studies on its Resources Page soon.

The AUWG Study:

The formation of the AUWG was announced on May 9 2022 shortly after Hilcorp informed the utilities that it would not renew existing contracts. Its members consist of six utilities–-Enstar, HEA, CEA, MEA, GVEA, and the Interior Gas Utility (IGU, which provides natural gas for heating in Fairbanks–the IGU has since announced plans to truck LNG from the North Slope to replace the gas it gets from Cook Inlet). The Alaska Energy Authority (AEA, a state agency dedicated to “reducing the cost of energy in Alaska”) and the state Department of Natural Resources (DNR) have also consulted with the group.

Although the AUWG has no formal leadership, Enstar appears to be playing a leading role in its work. Enstar officials have represented it before regulatory bodies, including the Regulatory Commission of Alaska (RCA, which oversees utilities). Enstar hired BRG to carry out the group’s study and applied to the RCA to create a regulatory asset to amortize its costs. The AUWG study and accompanying documents are housed on Enstar’s website.

The AUWG’s study is being released in two phases. The first phase, which was made public in a report in June 2023, estimates how much natural gas the Railbelt utilities would need between now and 2040. It also examines different sources of natural gas to replace Cook Inlet production and identifies the most promising options (information on the specific projects is in the “What Types of Projects Are Being Considered” section below). The second phase of the study, expected in December or January, will recommend one or two specific projects for sourcing new gas supplies.

The AUWG study takes as a given that all the Railbelt utilities should pursue a joint project (or projects) to bring in new supplies of natural gas. The press release announcing the founding of the group said it was created to “collectively explore long term gas supply solutions to meet utility and customer demand.”

The study acknowledges that the electric utilities’ future gas needs may vary considerably based on factors such as load, weather, and the addition of renewable generation. It predicts that by 2040 their collective needs could range anywhere from 11 billion cubic feet (bcf) a year up to 34 bcf/year. Although the report mentions plans to integrate several new, large-scale renewable projects, the number it settles on for electric utility gas needs is fairly close to current usage. In 2021 the Railbelt electric cooperatives used about 24 bcf of natural gas. The AUWG study’s “normal” demand assumption for electric utilities (the number it uses to evaluate different strategies) drops slightly between now and 2032, down to 21 bcf, then remains flat through 2040. For reference, Enstar uses about 34 bcf/year–this is why AUWG projects are designed to supply at least 55 bcf/year.

As a result, the AUWG study operates as if utility demand for natural gas will remain fairly stable until 2040, with only a slight drop due to new renewables. This means that any project or projects recommended in the Phase Two study will have been designed to allow Railbelt gas usage to continue at roughly current levels.

The CEA Study:

The CEA study paints a more complex and dynamic picture of the electric cooperatives’ future gas needs. It is limited to CEA’s future gas needs and provides four substantially different potential scenarios. Black and Veatch (BV), the consulting and engineering firm hired by CEA to conduct this study, has indicated that it expects to complete its work by the end of December.

In the fall of 2022 CEA commissioned BV to evaluate its future gas needs and how they could be met. CEA currently accounts for about half the natural gas use by the electric cooperatives (about 13 bcf/year). The fact that CEA chose to pay for a study parallel to the AUWG’s shows an awareness that their best interests may diverge from Enstar’s. It is not known how much CEA has spent on their study–as of June 2023, the AUWG study had cost $466,000. BV and BRG have been sharing some information between them.

The completed CEA report is not expected until late December or early January. BV has presented multiple updates to the CEA Board and its Operations Committee throughout 2023. The most complete summary of its first phase, which calculated CEA’s potential demand for gas, was submitted to the RCA in August.

The CEA study presents four detailed scenarios using renewable integration and consumer demand for power as key variables. The results show the high degree of uncertainty in CEA’s future gas needs, as well as the likelihood that these needs will change over time. According to BV’s report, CEA’s cumulative need for natural gas from outside Cook Inlet between now and 2040 could be as low as 32 bcf or as high as 144 bcf. CEA’s peak annual need could range from 5.3 to 15.3 bcf. Some of the CEA scenarios also show considerable changes in how much gas the utility could need from year to year, in contrast to the AUWG report’s flat demand.

These scenarios not only show a great deal of variation in potential gas needs, but that the date when CEA would need to start importing LNG depends on multiple factors. This could happen as soon as 2029 or as late as 2034. This date would also be affected by CEA’s ability to store natural gas pumped from its own Beluga River gas field.

These scenarios suggest that the solutions for CEA’s future gas needs may diverge from Enstar’s. This point was made explicitly in a September update by BV presented to CEA’s Operations Committee, which included a slide listing five points of divergence between the type of natural gas strategy that would work best for an electric utility or for Enstar.  Basically it explained that Enstar needs a “permanent long-term solution”--a strategy capable of bringing in large quantities of gas indefinitely–while CEA only needs a “transient solution” that would see its need taper off over time.


The NREL Study:

The second study raising questions about the AUWG’s assumptions is the NREL Wind Integration Study. Although it does not directly address the gas supply, this report shows that the most cost-effective path forward for the Railbelt is moving to a generation system that relies on renewable power for over 75 percent of its energy (currently the Railbelt gets about 15 percent of its power from renewable sources). Such a system would need considerably less natural gas to operate.

This is a follow-up to a 2022 NREL report looking at the feasibility of implementing a Renewable Portfolio Standard (RPS) for the Railbelt. (An RPS requires utilities to achieve specific targets for renewable power generation). An RPS bill requiring the Railbelt utilities to achieve 80 percent renewable power generation by 2040 was introduced by Governor Dunleavy in 2022. It did not pass, but a similar bill was introduced in 2023 and will be taken up in the next legislative session set to begin January 16. The first report demonstrated the feasibility of reaching the 80 percent goal; this follow-up is designed to look at the economic impact of increasing renewable generation. The final version is expected in early January.

Preliminary results of the NREL economic study were presented by Marty Schwarz, an NREL engineer, to the CEA board’s Operation Committee on September 6 and the Alaska Wind Workshop on September 8 (audio of his presentation to CEA can be found here). According to Schwarz’s presentation the most cost-effective Railbelt grid by 2040 would be one that relied on renewable power sources (wind, solar, hydro) for 78 percent of its generation. He estimated that by 2033 these types of renewable generation would cost less per kilowatt hour than the lowest-cost gas generation. This mix could save Railbelt consumers about $50 million per year by 2035. 

While Schwarz’s presentation did not directly address natural gas needs, a system relying on renewables for three-quarters of its generation would use far less gas than anticipated in the AUWG report. There were some important caveats to Schwarz’s presentation. He stated that he was in Alaska to get feedback from the utilities on NREL’s preliminary results, and that the final numbers would likely be somewhat different. But he also said that he believed that the differences would not be “of an order of magnitude.”

The NREL study does assume that the Railbelt transmission system will be upgraded and that utilities will use a system of “economic dispatch” (where a utility uses the least expensive available power to meet demand, regardless of who generates it). The heads of the four Railbelt cooperatives are actively pursuing state funding to match a $206 million federal grant to upgrade the transmission system and have spoken of economic dispatch as a future goal.

The Potential Costs of Committing to Natural Gas

According to Chris Rose, the Railbelt electric utilities will not just be deciding what to do about natural gas in the coming months; they will also be deciding what to do about renewable power. He believes a decision to commit to an extensive infrastructure and/or long-term LNG contracts that lock utilities into minimum annual purchases will forestall a transition to renewables like the one described in the NREL report. The Railbelt energy system would be frozen in place, he said, leaving Alaska stuck with an undiversified grid and high energy costs, and dependent on a volatile world-LNG market.

The kind of contracts the utilities sign to purchase LNG will have a significant impact on whether or not the Railbelt system can integrate large-scale renewable projects. Contract duration is one important factor. Short-term contracts could leave utilities exposed to potential fluctuations in LNG prices, but long-term contracts would lock them into gas generation for years, preventing them from buying power from independent producers even if that power would be less expensive.

Erin McKittrick, one of the authors of the Alaska Energy Blog and a founder of Ground Truth Alaska, pointed to LNG contracts with minimum purchase requirements as another potential impediment to the development of renewables. McKittrick, who is a member of the HEA board, spoke to AETP in her capacity as an independent researcher and author. Natural gas contracts frequently contain clauses requiring customers to purchase a guaranteed minimum amount of gas during a set time period (or sometimes pay a fine if they do not make the minimum purchase). If these minimums are set near the utility’s current level of gas usage, as is the practice of some Railbelt utilities, they have a disincentive to buy power from independent renewable energy projects, since they are committed to buying the gas. Even if a utility using such contracts wanted to buy power from an independent renewable producer, they would have to time any deals to coincide with the end of an LNG contract.

According to McKittrick, current gas contracts are an important reason why there has been so little development of large-scale renewable projects in the Railbelt over the past decade (the only large (over 1 megawatt) renewable projects to go into operation on the Railbelt since 2013 were the 2020 Battle Creek Extension at the Bradley Lake hydroelectric project and the 6-megawatt solar farm that opened in Houston in August 2023). When considering utility contracts with independent power producers, the RCA looks at whether the cost of that power would be lower than the gas-generated power it would displace (this is known as the “avoided cost”).

Since 2012 no one has submitted a power purchase agreement to the RCA that factors a rise in natural gas prices into its avoided-cost calculations. McKittrick believes this is because the last time this was done–in a 2012 contract between CEA and the Fire Island wind farm (operated by Cook Inlet Region, Inc.)--gas prices did not rise as anticipated. This has created an expectation that the RCA would not approve a similar contract. (The failure of Cook Inlet natural gas prices to rise after 2012 as anticipated was likely due, at least in part, to the over $2 billion in subsidies the state provided between 2006 and 2016 in the form of credits and tax caps).

This helps explain why the Railbelt utilities have done little to diversify their generation portfolios over the past decade, even though, as Rose points out, the DNR has been predicting declines in inexpensive Cook Inlet gas for over a decade. McKittrick believes, given expectations of LNG imports, that the utilities and RCA now need to start considering future gas prices when evaluating power purchase agreements with independent power producers. “They should be measuring a renewable contract against the expensive gas they will have to buy later, not against the limited pool of cheap gas they have left.”

One argument in favor of the utilities working together to import LNG is that they will have greater bargaining power than they would apart. But Rose is skeptical of this argument for two reasons. First, even at current levels, the total gas requirement of the Railbelt is very small in the context of international markets–the AUWG’s annual expectation of 55 bcf is equivalent to a half day’s worth of current US production (about 108 bcf/day). Second, he points out that the utilities will not all need gas at once–their need for imported LNG will be largely determined by the expiration of their contracts with Hilcorp, which range from 2024 to 2033, and the actual rate of Cook Inlet decline.

Decisions about what type of infrastructure to build to bring in new gas supplies and who will pay for it will also have long-term ramifications for the Railbelt. The most likely project would be an LNG import facility. The electric cooperatives will need to decide if they will join with Enstar in developing a facility or if they will look at building their own. Rose believes that Enstar will try convincing the electric utilities to join it in developing a large import facility with a long operational life–Enstar has no choice but to pursue such a project, and involving the electric utilities will help defray its costs.

The difference in projected costs between a smaller, seasonal facility that could accommodate 15.3 bcf/year (CEA’s high estimate for its potential annual demand), and a larger, year-round facility that could meet the AUWG’s projections (55 bcf/year) is considerable. BV puts the price of a smaller facility in the $150-280 million range. The AUWG estimates are far higher–$698-876 million. A project collectively serving the electric cooperatives would fall somewhere in between these figures.

If the electric utilities decide to share a facility with Enstar, an important question will be how construction and operations costs are divided. Electric utilities with expiring Hilcorp contracts may rely more heavily on LNG imports in the first years of operation, but their reliance on imports would decline over time if they integrate more renewables. Enstar’s need for such a facility would become pronounced after its Hilcorp contract expires in 2033 and would continue indefinitely.

A crucial wrinkle to this issue is the question of state subsidies. Enstar CEO John Sims has stated on several occasions that he believes the state should subsidize the construction of new infrastructure to bring in natural gas, either an import facility or a pipeline from the North Slope. In a presentation he gave in August 2023 to the Railbelt Reliability Council (RRC, an organization created in 2022 to help coordinate the Railbelt electric utilities), Sims stated that: “Subsidization is important. We live in a very challenging market..so I personally am strongly encouraging the state to looking into owning infrastructure….I think that’s critical and really one of the only ways we can move forward long-term….One of the common things you see across the world are governments investing in energy infrastructure because of how critical the lower cost of energy is for a community and economic growth.” The AUWG Phase One Study helpfully includes a table labeled “State Participation Options” with estimates for the price of natural gas if the state funded either 80 or 100 percent of the cost of an LNG import facility or pipeline from the North Slope.

The pursuit of subsidies is another reason for Enstar to try to get the electric cooperatives to join it in building an import facility. On its own, Enstar is a private, for-profit company asking the state to help pay for a facility it needs to operate. It would be easier to argue that a facility serving not only Enstar, but also the non-profit electric cooperatives, would benefit the entire Railbelt. Rose pointed out, however, that with a joint facility, Enstar will reap the greatest benefit of any subsidies in the long-term.

Both McKittrick and Rose pointed to another potential impact of state subsidies for any import facility–that by artificially reducing the cost of natural gas, they would make it much more difficult for renewable power projects to sell their power to the utilities, even though the renewables would be less expensive without the subsidies. Rose suggested that, if the state wants to subsidize power generation, it would be more cost effective to support renewable energy projects. But, he added, renewable energy projects will not require subsidies to be less expensive than unsubsidized gas-powered generation that relies on LNG.

As first reported by Nat Herz, Enstar has also recently requested to take over a project that would build a natural gas pipeline for in-state use from the North Slope. This project, whose cost recent estimates put at over $8 billion, could not be built without state aid. Most observers believe the project is a non-starter; however, the Governor’s Energy Security Task Force, of which Sims was a member, recently recommended the state support feasibility studies for this pipeline along with the larger, export-oriented AKLNG project.

For Rose, the cooperatives’ decision should be a simple one. Renewable energy projects create local jobs and provide energy at stable, predictable prices. It makes no sense, he said, to “double-down on a resource that is very expensive, very price volatile, and has to be imported from another country.” He continued that, even if the Railbelt achieves 80 percent renewable power generation, it will still need some natural gas–but the goal should be to use a lot less of it. McKittrick agreed that the long-term economics favor renewable power generation, calling it a “no-brainer.” But she also cautioned that discussions of these topics are not conducted on purely economic grounds–that people’s political beliefs and attachments can also influence them.

The AUWG’s Closed Process

One criticism of the AUWG’s work has been its lack of transparency. The group was formed by the utilities in May 2022 and has conducted its work in private. According to one document filed with the RCA, its first milestone was the formulation of a confidentiality agreement. The group has consulted with state agencies, such as AEA and the DNR, but has not invited any other group to participate.

In testimony to the RCA in October 2022 Sims said that the group had deliberately been restricted to the utilities so it could focus on their needs. Yet in June 2023 Sims told the RCA that the search for a solution to gas shortages was “fundamentally a public policy issue.”

The best public description of the group’s work was included in Enstar’s November 2022 petition to the RCA to allow it to amortize the cost of the BRG report. The heads of the Railbelt utilities met about every two weeks from May to November 2022, with separate meetings occurring among technical staff. No information has been shared on the frequency of meetings or attendees since then. Any updates or presentations by BRG were given in private; the only other public information on the study was the release of the Phase One report in June 2023.

The AUWG has denied requests from other Railbelt stakeholders, such as the RRC, to attend its meetings. It has provided occasional updates to the RCA, and Sims and a BRG representative met with the RRC’s Board in August 2023. During this meeting the question of how the AUWG’s work might impact the Integrated Resource Plan (IRP) the RRC is responsible for developing. The IRP is meant to coordinate the development of new generation projects (or major upgrades to existing ones) in the Railbelt to maximize their benefits and keep costs down. Because its recommendations could have a direct impact on the generation mix in the Railbelt through 2040, the AUWG’s work could seriously limit the options open to the IRP’s planners. Sims would only say that the AUWG was committed to presenting the Phase Two results to the RCA and RRC.

Rose said he thinks that, by cutting out other stakeholders, the AUWG is missing perspectives and information that could aid its work: “Having more people with more information and more perspectives at the table gets us to a better decision for the whole region.” (Rose is a member of the RRC’s Board, but was not speaking on its behalf). He recognized that parts of the AUWG’s work, concerning things like pricing and bargaining strategies, need to be conducted confidentially, but did not see why much of the basic discussions about the utilities’ need for natural gas and general strategies had to be conducted in private.

The BV study for CEA has been carried out with greater transparency–BV has provided multiple updates on the progress of its study to the CEA Board and its Operations Committee in open public session, where they have been discussed by board members. Material regarding confidential information was given in executive session, but substantial parts of the presentations were made available to CEA members and the public. CEA also submitted its completed Phase One report to the RCA in August.

What Types of Projects Are Being Considered

The first phases of both the AUWG and CEA studies both evaluated fuel sources that could be used to run natural gas generation plants. Most were new sources of natural gas, although some experimental fuels (green hydrogen) were also considered. Working from parameters provided by the utilities, BRG and BV identified several projects to be explored in more depth in their Phase Two studies.

Both studies recommended further consideration of an LNG import facility on the Kenai Peninsula, with several different configurations being examined. The AUWG study also recommended further study of the construction of a 24 inch natural gas pipeline from the North Slope. The CEA study discounted the pipeline idea for several reasons, including the fact that it only would be economically viable if it received billions of dollars in state subsidies.

AUWG members identified three top criteria to evaluate potential fuel sources: schedule risk (could a project deliver the needed amount of gas by specific dates), reliability (would that supply be dependable), and cost (how much would gas be per mcf). CEA’s consultant, BV, used similar criteria (cost, risk, schedule) in its evaluation. A number of possibilities were rejected, either as experimental (green hydrogen), useful, but unable to provide the needed amount of gas (“renewable” natural gas from landfills), or too expensive (trucking LNG from the North Slope).

Both reports identified an LNG import facility on the Kenai Peninsula as the option that could be up and running by the time Cook Inlet production is no longer capable of meeting local demand in 2027-28. Several different designs were considered, with the main two being a facility where LNG tankers would offload their cargo to an onshore processing facility for regasification and storage, or a floating facility where LNG would be offloaded, temporarily stored, and regasified before transportation to land-based storage. Regasification is the process by which LNG is converted back to a gaseous state for transportation through pipelines and consumer use.

Beyond the question of whether to use an onshore or floating facility, each project has to account for several design elements. These include the capacity for on-site storage for both LNG and regasified gas, whether the facility would operate seasonally or year-round, and the maximum rate of regasification. If a floating LNG storage/regasification facility was used, it could either be permanently docked or transient.

If a land-based facility for storage/regasification is selected, there are two options. One is to retrofit the old LNG export facility near Nikiski (exports ceased in 2007). Using this facility would require considerable upgrades and retrofitting, but would be less expensive than building a new import complex. Using this facility would also require negotiations with its current owner, Marathon Petroleum, which has considered converting the plant for LNG imports in the past (Marathon requires natural gas for its nearby oil refinery). The other option is the construction of a new complex (which the studies refer to as a “greenfield” development) in the same general area–any new site would require access to the existing natural gas pipeline system.

The other main possibility is a floating storage and regasification unit (FSRU). These are LNG tankers fitted with regasification units. In one configuration, an FRSU unit would be purchased or leased and permanently docked at a pier. LNG tankers would come, offload their cargo onto the FSRU, which could take on the whole cargo and then regasify it over a number of days or weeks. One site being considered for an FSRU unit is the old Agrium fertilizer plant in Nikiski. Otherwise, a new pier and pipeline connector would need to be constructed.

There are a few differences between the AUWG and CEA studies. Because CEA’s study is only considering projects designed to meet its individual needs, it is considering one option that the AUWG is not–the use of transient FSRU ships. These ships would transport LNG to Alaska, dock, and then regasify and discharge their cargo over a number of days, with the gas being sent to storage for later use.

CEA is also looking at projects that would only operate seasonally–LNG tankers or barges would come up in the summer and discharge their cargo, which would be put in a storage facility for use throughout the year. For this system to work, CEA would have to create a new underground storage facility (the existing Cook Inlet Natural Gas Storage Alaska, or CINGSA, facility shared by the utilities would not be large enough). At its September 6 Operations Committee meeting CEA staff discussed using exhausted gas wells in its Beluga River Unit as potential storage sites. Seasonal options are not being considered by the AUWG because they could not meet Enstar’s long-term needs.

The AUWG Phase Two study will also look at one option not considered by CEA: the construction of a natural gas pipeline from the North Slope. Sims has spoken in favor of the construction of the AKLNG project (also known as the Gasline), an export-oriented pipeline from the North Slope. If it were constructed, then the Railbelt utilities would be able to purchase gas from it–the Alaska Gasline Development Corporation (AGDC) has said it would make providing low-price LNG to Alaskan utilities a condition for investment in the project, but there is no guarantee this would actually happen. The AUWG study acknowledges that this project, which would cost over $40 billion to construct, is dependent on foreign investment that the Railbelt utilities cannot control, and so they cannot plan on it to provide natural gas.

But the AUWG is considering a smaller pipeline from the North Slope which would be built to serve the needs of the local market. This project, under consideration for years, has gone by several names, including the Bullet Line or the ASAP (Alaska Stand Alone Pipeline). As mentioned above, Enstar has asked AGDC to give it control over the ASAP project (AGDC has been overseeing both the AKLNG and ASAP projects, but had been prioritizing the former–as of December 13 2023 the AGDC website still lists the ASAP as one of its projects). Governor Dunleavy’s Energy Security Task Force, of which Sims was a member, recommended that the state pay for feasibility and permitting studies for both pipeline projects.

The AUWG report makes it clear that the ASAP project, which is estimated to cost about $8.79 billion to construct, would only be economically feasible if it were mostly or completely paid for by the state. The fact that either the Legislature or another state body, such as the Permanent Fund, would have to agree to invest such a huge sum in this pipeline makes the project unlikely (this is why CEA excluded it from the options it is considering).

Acronyms and Glossary:

AEA–Alaska Energy Authority. State agency dedicated to “reducing the cost of energy in Alaska.”

AGDC–Alaska Gasline Development Corporation. State-owned corporation charged with developing a natural gas pipeline from the North Slope.

AKLNG–Also known as the Gasline. Proposed export-oriented natural gas pipeline from the North Slope to Nikiski.

ASAP–Alaska Stand Alone Pipeline–a natural gas pipeline from the North Slope designed to supply in-state needs only (as opposed to export-oriented AKLNG project).

AUWG–Alaska Utility Working Group–consortium of six Railbelt utilities examining potential sources of gas to replace Cook Inlet production. (Sometimes referred to as the Railbelt Working Group or Cook Inlet Gas Working Group).

bcf–Billion cubic feet. Common unit of measurement for natural gas.

BRG–Berkeley Research Group. Consulting firm hired by Enstar to do the AUWG’s gas study.

BV–Black and Veatch. Engineering and consulting firm hired by CEA to conduct their gas study.

CEA–Chugach Electric Association. Cooperative serving the Anchorage area.

DNR–Alaska state Department of Natural Resources. Its Division of Gas and Oil provides forecasts of expected Cook Inlet gas production.

Enstar–Privately-owned natural gas utility serving Southcentral Alaska.

FSRU–Floating Storage and Regasification Unit. Ship capable of storing and/or transporting LNG and regasifying it for injection into a pipeline. Can be mobile or moored.

HEA–Homer Electric Association. Cooperative serving the western Kenai Peninsula.

GVEA–Golden Valley Electric Association. Cooperative serving Fairbanks and surrounding interior communities.

IGU–Interior Gas Utility. Borough utility providing natural gas for home heating in Fairbanks area.

IRP–Integrated Resource Plan. A plan to coordinates the development of new generation projects along the Railbelt in order to maximize benefit and minimize cost. This is one of the responsibilities of the RRC.

LNG–Liquified natural gas.

mcf–Thousand cubic feet. Unit of measurement used for pricing natural gas.

MEA–Matanuska Electric Association. Cooperative serving the Matanuska-Susitna Valley region.

Natural gas–the common name for a mixture of methane, ethane, butane, and propane.

NREL–National Renewable Energy Laboratories. Research organization under the United States Department of Energy.

RCA–Regulatory Commission of Alaska. State agency tasked with regulating most Alaskan utilities, including electric rates and utility fuel/generation contracts.

REAP–Renewable Energy Alaska Project. Non-profit organization dedicated to increasing the development of renewable energy and energy efficiency in Alaska.

RRC–Railbelt Reliability Council. Organization selected in 2022 to serve as the Railbelt’s Electric Reliability Organization (ERO)–the creation of a Railbelt ERO was mandated by the legislature in 2020.