DNR says Cook Inlet gas and storage capacity vital; 'net profit share' lease sales show limited outside interest

John Crother, deputy commissioner at the Alaska Department of Natural Resources, and Derek Nottingham, director of the division of oil and gas, briefed the House Energy Committee on Jan. 23 in Juneau about Cook Inlet natural gas supplies, recent department actions and storage options to buffer winter demand.

Crother told lawmakers the governor had directed the department to “do everything we can with our existing authorities to unlock our natural gas resources in the inlet.” He and Nottingham said Cook Inlet natural gas is the principal feedstock for utilities that provide heat and electricity to much of the state’s population centers, and that declines in production over the last three decades have tightened in‑state supply.

Nottingham summarized the basin’s history and recent production trends, noting that Cook Inlet is a mature oil and gas basin with dozens of producing fields and that production has declined from multi‑decade peaks. He said the region currently supports roughly 70 billion cubic feet (BCF) a year of contracted gas for utilities and that the gas under contract and storage in the inlet is critical to roughly half a million residents.

To encourage more activity, the department described its use of so‑called net profit share leases (authorized under AS 38.05.180(f)(3)) in 2023–2024. Under that approach the state accepts a net‑profit share bid rather than a traditional up‑front royalty; the state would not collect a return until a project has recovered qualified capital and operating costs, the presenters said. Nottingham and Crother told the committee that the net‑profit share leases were deliberately competitive but that industry response has so far been modest: 2023 saw several blocks awarded to existing Cook Inlet operators (HillCorp and HEX) at bids closer to the minimum net‑profit share; 2024 produced only three tracts and minimal bonus payments.

The department also described recent releases of seismic surveys previously restricted by expiration tax‑credit windows; staff said the agency expedited those releases so developers and explorers can access recent subsurface data. “We’ve released that data out to the public for sale,” Nottingham said during the hearing.

On storage, Nottingham explained to the committee how storage reservoirs operate and why storage is important to meet high winter demand. He said the Singsa facility is an existing multi‑billion‑cubic‑foot storage facility (operating working volume described in testimony as about 11 BCF, with additional capacity added by new wells) and that HillCorp’s Kenai Pool 6 is a large reservoir HillCorp has proposed to use commercially for third‑party storage; Nottingham noted reported working volumes of roughly 17.5 BCF for Kenai Pool 6 while adding the field may be capable of more.

Lawmakers raised policy tradeoffs. Representative Chris Holland asked how the department weighs consumer price impacts against state revenue collection when it offers royalty relief or net‑profit terms. Crother and Nottingham said the department analyzes whether changes will increase supply and overall state receipts over the life of a project, and that evaluation of consumer impacts is part of the policy discussion. Nottingham added technical context: “Gas storage is basically re‑injecting gas in a subsurface reservoir… it mitigates high winter demand by having kind of a reserve of gas available,” a process the department said is overseen with rate and safety oversight by the Regulatory Commission of Alaska and by the Alaska Oil and Gas Conservation Commission.

DNR officials told the committee they will return with further briefings on well counts, recent activity in the inlet, and modeling of production scenarios. Committee members thanked DNR and signaled interest in additional analysis of lease design, storage commercialization and the relationship between royalties and consumer prices.