There is a critical need for additional gas this winter—

On August 20 at 2 p.m., the House and Senate Resources Committees will meet jointly at the Anchorage LIO to discuss Alaska’s winter energy supply. ENSTAR, the Alaska Energy Authority, the Regulatory Commission of Alaska and the Department of Natural Resources have been invited to answer questions about gas storage, Cook Inlet production, hydroelectric power and transmission.

Those are important questions. But here’s the problem: We already have many of the answers.

And before this hearing becomes an exercise for Senator Giessel, Senator  Wielechowski, Senator Dunbar and Senator Kawasaki to point fingers at the Governor, ENSTAR, regulators, producers or anyone else for a problem that has been building for years under their lack of leadership,  Alaskans deserve the facts and the context.

The Senate Resources Committee and the Senate Majority  had an opportunity to do their job and pursue these issues before we reached the point of an urgent winter gas shortage. Instead, we are now heading into a hearing where there is a risk that the discussion will focus on what someone else should do to solve a problem they ignored.

So, before the finger-pointing begins, we’re going to give you the answers (the questions were publicized in a recent campaign newsletter from Senator Giessel and in a statement from the Senate Majority).

1. Why was expanded gas storage denied?

What happened

On July 8, 2026, the Regulatory Commission of Alaska (RCA) denied ENSTAR’s request for an advance determination that its proposed Kenai Loop Pool gas-storage project was prudent.

Importantly, this was not a finding that gas storage is unnecessary or that the project could never proceed.

ENSTAR proposed developing the depleted Kenai Loop Pool, currently associated with AIX Energy, as a seasonal gas-storage facility. The project would provide approximately 25 Bcf of storage capacity at an estimated cost of $240 million. ENSTAR argued that the facility is critical to meeting winter gas demand.

The RCA’s concern was essentially that it did not have sufficient information to make the extraordinary advance prudency determination ENSTAR was requesting. The Commission specifically questioned:

• The timing and magnitude of the need for additional storage;
• The proposed facility’s injection and withdrawal capabilities;
• Whether the reservoir is technically capable of functioning as a storage facility; and
• The fact that DNR had not yet made a final determination regarding the reservoir’s technical suitability for storage.

Important current development

ENSTAR has already petitioned the RCA for reconsideration of the decision. The RCA has 30 days to act on that petition.

That means this issue is not over. The reconsideration process is already underway, and any new information regarding the need for storage, the reservoir’s capabilities or the competing applications could be relevant to the Commission’s review.

2. Can the Governor instruct the RCA to reverse itself?

No.

The Governor cannot simply instruct the RCA to reverse its decision. The RCA is established by statute as an independent agency. Its five commissioners are appointed by the Governor and confirmed by the Legislature, but the Governor cannot lawfully order the Commission to reach a particular regulatory decision.

That does not mean the Governor is powerless.

The Governor can:

• Direct his administration to make the gas-storage issue an urgent priority;
• Direct DNR to promptly resolve the technical and leasing questions surrounding the Kenai Loop Pool;
• Publicly urge the RCA to give ENSTAR’s reconsideration petition expedited consideration based on new or additional information; and
• Coordinate the state agencies involved to ensure that regulatory and technical questions are addressed as quickly as possible.

The distinction is important: the Governor can prioritize and facilitate action, but cannot dictate the RCA’s regulatory outcome.

3. Where is the gas going this summer?

With ENSTAR warning of a potential winter gas shortfall, one of the most immediate questions is:

What is being done right now to ensure that every available molecule of Cook Inlet gas that can be economically produced is available to Alaska consumers and, where possible, stored for winter?

This is not simply a question about future development.

ENSTAR is currently disputing with HEX over discretionary gas that ENSTAR says it needs to refill storage before winter. ENSTAR has initiated arbitration and sought emergency relief, arguing that gas that is not stored during the summer injection period cannot simply be recovered later when winter demand arrives.

That issue may be more immediate to the coming winter than the long-term storage question.

4. HEX Energy has doubled its gas production. How much more exploration and development is planned?

HEX has demonstrated that additional Cook Inlet gas can be brought online.

The important questions now are:

• How much additional exploration and development is planned for the Kitchen Lights Unit?
• What additional production is expected from that program?
• What regulatory, permitting or infrastructure obstacles could prevent that gas from reaching Alaska consumers?
• How quickly can additional production actually be brought online?

A better question for DNR and HEX may be:

What would it take to accelerate development of the remaining resource, and how long would it take to have additional gas available and under contract?

That gets beyond simply asking whether additional gas exists. The issue is how quickly it can become deliverable gas for Alaska consumers.

5. BlueCrest Energy has the Cosmopolitan Unit lease, with approximately 250 Bcf of gas reported in legislative hearings. Why hasn’t that gas been developed? What is the holdup? Why hasn’t DNR made them produce?

There is a much stronger and more complicated story here than simply asking, “Why hasn’t DNR made them produce?”

AIDEA documents show that BlueCrest Energy has been seeking investment to develop the offshore gas resource. Its 2023 board materials stated that the company was seeking financing for offshore gas development and that development was contingent on obtaining funding.

BlueCrest was denied nearly $100 million in cashable tax credits  for initial investments in Cosmopolitan and has struggled to secure financial backing for the drilling commitment contained in its 12th Plan of Operations filed with DNR.

But financing is not the only issue.

The limited and tenuous nature of the Southcentral Alaska natural gas market also makes significant investment in exploration and development more difficult. With the Railbelt consuming approximately 70 Bcf of gas per year, the market is operating on a relatively tight supply-and-demand balance. Plans to import LNG from Canada or potentially deliver North Slope natural gas to Southcentral Alaska create additional uncertainty for companies considering major investments in Cook Inlet exploration and development.

In other words, there is a resource, but developing it requires capital, infrastructure, a market and confidence that the investment can be recovered.

There are also significant regulatory issues.

In January 2026, DNR Commissioner-designee John Crowther told the House Resources Committee that BlueCrest was in default and that DNR was examining options to bring the resource into production. He also said the operator has an obligation to develop the leases and that DNR had been working to encourage BlueCrest to bring in investment to enable production.

In August 2025, DNR placed BlueCrest’ s 13th Plan of Development into abeyance because the company was in default under its 12th POD, while the Commissioner’s office reviewed BlueCrest’ s request for reconsideration.

So the picture is this:

DNR believes BlueCrest has a development obligation. BlueCrest has struggled to finance the development. The company is in regulatory default, and its development plan is in abeyance.

That leads to a much better question for DNR:

Is taking action to place the resource in the hands of an operator capable of developing it a viable option? If so, what would the timeline be for doing so, and when would DNR expect to see first production?

6. Can the Governor order DNR to enforce the lease?

Again, not simply by issuing an order to “enforce the duty to produce.”

The Governor has substantial authority over DNR and appoints the Commissioner. But the Governor cannot simply dictate a particular enforcement action or regulatory outcome.

The Governor can, however:

• Direct DNR to make development of stranded Cook Inlet gas a priority;
• Require the department to publicly report on the operator’s lease obligations and defaults;
• Require DNR to identify available enforcement options;
• Establish a clear timeline for decisions; and
• Require the department to report on what would be necessary to bring the resource into production.

The real question should therefore be:

What authority does DNR have today, what actions can it take, and what is the fastest realistic path to getting this resource into production?

7. How is Dixon Diversion progressing toward the 2030–2031 completion date?

Bradley Lake currently produces approximately 10% of Railbelt annual electricity. The Dixon Diversion project is expected to increase Bradley Lake’s energy production by as much as 50%.

AEA’s current materials estimate that the project could produce approximately 180,000 MWh annually, resulting in roughly 1.5 Bcf per year of natural gas displacement.

That is a positive step, but it is important to put the number in perspective.

The estimated natural gas displacement represents only about 2.14% of annual Railbelt gas demand. It is therefore helpful to the overall energy picture, but it is not large enough to solve the projected gas shortfall—and it will not be available for the 2026–27 winter.

AEA filed the Final License Amendment Application with FERC on June 30, 2026.

The project is targeting completion around 2031, with an estimated construction cost of approximately $342 million.

A better question for AEA and Bradley Lake is:

AEA has now filed the Final License Amendment Application for Dixon Diversion. What are the remaining FERC, financing, permitting and construction milestones, and is the project still on schedule for commercial operation in 2030–2031? What could cause that schedule to slip?

That is the information Alaskans need—not simply assurances that a project is underway.

The bigger issue: What can actually help this winter?

These questions matter because Alaska has both an immediate problem and a long-term energy problem.

Dixon Diversion will help—but not this winter.
New Cook Inlet exploration can help—but it takes time.
Cosmopolitan could potentially provide a significant resource—but it is not currently producing.
New gas storage could provide important winter reliability—but the regulatory process is still underway.
And the state needs to understand what gas is available right now and whether it is being properly positioned for the coming winter.

There is no single switch the Governor can flip to solve this.

But there are actions that can be taken now, and Alaskans deserve to know what they are, who has the authority to take them, and how quickly they can produce results.

That is the context that should frame the August 20 hearing.