DNR: Cook Inlet production has stabilized; decommissioning costs vary widely

The Division of Oil and Gas told the Senate Finance Committee that while Cook Inlet saw sharp declines earlier this decade, recent in‑field development and investment have largely stabilized output: "Now we're seeing decline rates closer to 1% per year," Director Haley Payne said during the presentation. Payne said producers added development wells (22 in 2025 and 14 drilled so far in 2026), and that multiple legacy fields still account for most output.

Payne walked senators through how the department manages production through lease contracts, unit agreements and annual plans of development. She described end‑of‑field sequencing—unit termination, lease expiration and use of easements for remaining surface infrastructure—and emphasized the department's suite of financial assurances: negotiated financial assurance agreements, statewide operator bonds, sinking funds, parent guarantees and insurance that can be seized if operators default on DR&R obligations. "One of our principal bonding or financial assurance instruments is a financial assurance agreement... the purpose of that is to guarantee that at the end of field life... the state has access to funds sufficient to offset the cost of that DR&R," Payne said.

Senators pressed for remediation cost estimates and operational detail. DNR said there is no single per‑well cost because expenses vary by whether a well is onshore or offshore, proximity to infrastructure and whether special access (for example an ice road or jackup rig) is needed. The department said it periodically reevaluates bonding levels—raising them if an operator appears financially distressed—and works closely with other agencies (AOGCC, DEC) to coordinate technical and plugging requirements.