Senate Resources Committee adopts SB280 committee substitute; revenue modeling shows mixed fiscal effects and project sensitivity to a $12 price cap

Senate Resources Committee Chair Senator Diesel opened the session on May 18 and the committee agreed to use a new committee substitute (version S) for Senate Bill 280, the Gas Line for Alaskans Act, as the working document after Senator Dunbar moved its adoption and the chair withdrew an initial objection for discussion.

The committee then heard detailed modeling from Department of Revenue analysts about how SB280 and its committee substitute would affect state revenues and the economics of a proposed AK LNG/Phase 1 pipeline. Owen Stevens, commercial analyst, and Dan Stickel, the department's chief economist, told members they had modeled multiple scenarios including an increase in the North Slope oil minimum tax floor from 4% to 6%, alternate Phase 1 demand paths and a 10‑year sunset on an alternative volumetric tax included in current bill language. "This is a very complex tax system," Stevens said, and the slides reflect preliminary interpretations of how build provisions interact with the spring forecast.

The analysts reported that raising the minimum tax floor from 4% to 6% would, on average, increase production-tax revenue by about $132 million per year over FY2027–36, with year-to-year variation that includes a modeled peak near $199 million in 2033 and a negative delta around 2034 driven by interactions with carry‑forward lease expenditures and per‑barrel credits. Stickel summarized the mechanics: higher gross floors reduce companies' ability to apply carry‑forwards in early years, producing timing effects on deductions and resulting revenues.

Modeling of the AK LNG project and combined scenarios showed additional complexity. The department's AK Energy Project model assumed a 32‑year project window (first LNG sales in 2031), a 10% midstream IRR and construction-cost assumptions expressed in 2026 dollars. Analysts said combining project-driven production changes with tax changes can raise or lower net state revenues in different years; one combined scenario produced a higher peak (about $243 million in the early 2030s) and a modeled low of about negative $50 million in 2034.

Committee members pressed analysts on key assumptions. Senator Kawasaki asked about capital costs; Stickel confirmed a pipeline construction assumption of roughly $15.5 billion in real 2026 terms and said the department's full gas treatment plant assumption for the complete project was about $10.9 billion, while the cost profile for a smaller Phase 1 treatment facility is uncertain and was approximated at a similar per‑thousand‑cubic‑feet basis. On demand, Stickel explained the committee-requested alternative Phase 1 scenario that starts at 20 billion cubic feet per year and ramps up by 5 billion per year, versus the baseline scenario that begins at 65 billion per year and includes a large anchor customer.

Price and consumer‑cost implications were a central point. Stickel provided weighted average in‑state breakeven estimates: about $17.71 per thousand cubic feet under current law, roughly $12.45 under SB280 as introduced by the governor, and roughly $17.14 under the committee substitute before the committee. He warned that a $12 nominal price cap in the committee substitute (not indexed for inflation) could make Phase 1 economically unviable: "With that $12 price cap, we don't believe that the Phase 1 would proceed," he said. The department also cited an import‑price estimate for LNG into Southcentral in 2033 of about $16.93 per thousand cubic feet based on external BRG/Instar analysis.

Analysts also modeled a 10‑year sunset on the alternative volumetric tax (a provision in the current bill). Stickel said a limited‑duration tax reduction affects developer economics because project sponsors evaluate discounted lifetime revenues; modeling found a modest change to LNG breakeven prices when a 10‑year sunset was included, and he explained why a time‑limited tax relief can require a higher up‑front price to reach the developer's target return.

Several members sought clarifications about slide wording, whether the committee substitute's provisions were inflation‑adjusted, and how baseline vs. baseload assumptions change utility prices. Senator Wilikowski emphasized that consumer price outcomes depend on whether a baseload (anchor) customer receives a lower delivered price and how distribution and delivery costs are applied; Stevens and Herbert said deliver‑to‑utility and consumer prices require additional assumptions (they cited a notional $4.36 per thousand‑cubic‑feet for distribution costs used in their modeling).

The hearing paused because the room was needed elsewhere; Chair Diesel adjourned at 10:00 a.m. and said the committee will resume the SB280 briefing this afternoon at 3:30 p.m. The committee adopted version S as the working document and will continue review, questions and additional modeling later in the day.