Revenue office outlines how Alaska’s production tax, credits and a 4% floor determine FY26 receipts

Department of Revenue economists walked the Alaska Senate Finance Committee through the ‘‘order of operations’’ that turn North Slope crude into state production‑tax receipts, showing how royalties, transportation deductions, lease expenditures and per‑barrel tax credits interact with a 4% gross minimum tax floor to produce the FY26 forecast.

Dan Stickel, chief economist for the Department of Revenue, told the committee the presentation was intended to explain mechanics rather than policy: "the purpose of this presentation is to present a high‑level overview of Alaska's oil and gas production tax." He said the department’s FY26 example uses a $70‑per‑barrel average, production of about 469,500 barrels per day and an annual gross value near $12 billion, then walks that value through deductions and credits to arrive at the tax the state receives.

Why revenue fell: Stickel said recent declines in production‑tax receipts reflect lower oil prices and higher company investments that increase deductible lease expenditures. "We have a very progressive production tax system," he said, and when prices fall and investments rise, "there's a lot less profit in the system to tax." The department’s five‑year chart showed production‑tax value falling from roughly $7.5 billion in FY23 to about $2.2 billion by FY27 in the forecast and total tax paid declining accordingly.

How the calculation works: Stickel outlined the sequence used in the tax calculation: royalties (the landowner’s share) are subtracted first; property taxes are treated as lease expenditures or transportation costs; transportation and pipeline tariffs are deducted to reach a wellhead or gross value; allowable lease expenditures (capital and operating costs, overhead allowance) are then applied; and the production tax is calculated as a modified net‑profits tax with a parallel gross minimum tax floor of 4% of gross value (when annual oil price exceeds $25). The state receives the higher of the net‑tax calculation (statutory 35% rate applied to production tax value) or the gross minimum.

Credits and the "donut hole": Stickel described two key per‑barrel credits: a sliding‑scale credit (up to $8 per taxable barrel at low wellhead values) and a $5 per‑barrel credit for gross value reduction (GVR)‑eligible new fields. For FY26 the department estimates about $1.19 billion of such per‑barrel credits will be generated and roughly $572 million will be used against tax liabilities; unused sliding‑scale credits cannot be carried forward. Those rules, combined with the minimum‑floor mechanism, produce divergent outcomes across companies: low‑cost producers may earn full sliding‑scale credits and still pay above the floor; average‑cost firms may be limited by the floor and realize only a portion of credits; new entrants with high upfront spending can generate carryforward lease expenditures and pay little or no tax until production ramps up. Stickel summarized the net effect as a "donut hole" of benefits distributed unevenly across producers.

Company examples: Stickel presented stylized 50,000‑barrel‑per‑day examples showing different cost structures. In one, a low‑cost producer that invested an additional $100 million reduced its tax liability by $37 million (a ~36.6% tax benefit) and still paid above the minimum floor. An average‑cost producer making the same $100 million investment remained constrained by the minimum floor and saw no tax benefit from that incremental spending. A new entrant with no current production would pay no tax in the example and would accrue carryforwards that could offset future taxes.

Land‑type and new developments: Stickel noted state revenue varies with land type. Production on state land yields higher direct state receipts; NPRA (National Petroleum Reserve–Alaska) royalties are shared with restrictions and primarily pass through to impacted communities; production beyond six miles offshore yields no direct state revenue. He also referenced a department white paper on the Willow project as background for new‑development impacts.

Price sensitivity and budget implications: Near the department’s forecast, Stickel said a $1 change in the Alaska North Slope price alters FY26 unrestricted revenue by about $35 million. He explained that the figure is lower than historical heuristics (previously closer to $100 million per $1) because production is slightly lower, an increased share of production comes from nonstate land or companies not subject to state corporate income tax, and more companies now pay at the 4% minimum floor where the state only captures 4% of price changes rather than 35%.

Data and forecasting inputs: The department collects detailed monthly filings that support tax calculations, annual true‑ups, production and cost forecast filings ahead of the fall and spring revenue forecasts, and supplemental written outreach and meetings with companies and the Department of Natural Resources to refine projections.

What’s next: The presentation provided the committee with numerical illustrations staff said it will use as a template for future briefings and for informing budget decisions; no formal action or vote occurred at the meeting. The committee adjourned after questions and thanked Stickel for the presentation.