DNR projects statewide oil production to rise over decade as Willow and Pikka add capacity

Cochair Joseph (House Finance Committee) presiding — The Alaska Department of Natural Resources on Wednesday presented a 10‑year oil production forecast that projects short‑term statewide average daily production near 474,000 barrels per day and rising later in the decade if several large projects proceed.

The department’s forecast, included in the Revenue Sources Book, shows an official near‑term number of roughly 474,000 barrels per day with a stated uncertainty range from about 424,000 to 510,000 barrels per day. Fiscal‑year 2024 statewide production averaged 461,000 barrels per day, about 2% below the department’s FY24 mean forecast, the presenters said.

Why it matters: the forecast underpins budget planning and revenue estimates for the state. Large new projects — when and if they reach first oil — can materially change the state’s revenue trajectory, the department told lawmakers.

Department officers said the forecast combines decline‑curve analyses for 40 producing pools, confidential operator business‑plan interviews and a risked portfolio of 16 large projects under evaluation. “We do this effort twice a year,” petroleum reservoir engineer Travis Peltier told the committee, and the forecast is a “static snapshot in time” based on data cutoffs for each cycle.

Key numbers and near‑term accuracy - Fiscal year 2024 actual statewide production: 461,000 barrels per day. - Department official short‑term forecast (annual average): about 474,000 barrels per day; the North Slope component ~466,000 bpd. - Department range of uncertainty on the short term: roughly 424,000–510,000 bpd.

On the FY24 variance, Peltier said the mean forecast was about 2% higher than actuals; roughly 1 percentage point of that was due to a calculation bias the division has corrected going forward. He also cited field‑specific operational issues that were not forecastable, for example a sales line freeze at Point Thompson and lower‑than‑expected well counts in some fields.

New and continuing sources of supply The department highlighted a mix of legacy field work and new developments as drivers of future production: Milne Point has seen significant renewed investment and rising output, while a series of projects on the North Slope and Cook Inlet are either producing, under construction or under evaluation.

- Milne Point: Hillcorp’s program has brought output sharply higher since taking operatorship. The division’s presentation showed Milne Point averaged about 47,465 barrels per day in November 2024, up from a low of roughly 19,000 bpd under the prior operator; the field previously reached nearly 59,000 bpd under BP. The division said it expects Hillcorp’s work to push production above 50,000 bpd.

- Noona‑Torok (Kuparuk River unit): ConocoPhillips accelerated development and achieved first oil late in 2024. The division estimates a peak contribution from this project around 20,000 bpd.

- Mustang (small unit west of Kuparuk): Operator Finnex restarted activity and drilled two development wells in 2024; department staff estimate roughly 4,000 bpd capacity.

- Pikka (Santos/partners): Pikka Phase 1 is under construction with the operator targeting initial production around early 2026; the department’s internal peak estimate for Phase 1 is about 80,000 bpd. Pikka Phase 2 is in the department’s evaluation portfolio, with a targeted move into FEED in 2025 and a possible final investment decision in 2027. The department said it does not treat Phase 2 as a foregone conclusion and assigns a risked probability to its eventual start‑up.

- Willow (ConocoPhillips): The Bureau of Land Management issued a 2023 Record of Decision on the supplemental environmental impact statement permitting construction; ConocoPhillips announced an FID and the department said first oil is anticipated in 2029 with an estimated peak around 180,000 bpd.

Methodology and risk treatment Peltier described the forecast methodology: decline curves for currently producing pools (40 pools included must have been producing by the cut‑off date), confidential operator interviews to inform business plans, and a separate treatment of infill drilling (under development) versus large projects (under evaluation). He said the division convenes external technical experts to help quantify the risk for major projects.

Director Derek Nottingham and Deputy Commissioner John Crother emphasized that natural decline is typical for mature fields (Prudhoe Bay is “already on that hyperbolic decline,” Nottingham said, noting typical base declines of roughly 3–4% per year) and that substantial capital and drilling are required to sustain slower declines.

Cook Inlet and other basins were included in the statewide modeling; Cook Inlet is mature and smaller in scale but remains important for in‑state refinery feedstock and aviation fuels.

What lawmakers asked and what happens next Lawmakers pressed for additional detail about field ownership, acreage (state vs. federal), operator identities and well‑level data. The division said it can provide a field‑by‑field ownership and operator table after the hearing and pointed members to newly published AOGCC field/pad/well production charts available online.

The House Finance Committee will hear the Department of Revenue’s fall revenue forecast at the next meeting; committee leadership said the revenue hearing will translate the production forecast into budgetary implications.

Ending note: the presenters repeatedly cautioned that the forecast is sensitive to operator business plans and that it will be updated in the spring cycle; the department said its short‑term forecast already incorporates corrected calculation methodology and operator information collected last fall.