Providing coverage of Alaska and northern Canada's oil and gas industry
January 2023

Vol. 28, No.5 Week of January 29, 2023

Slope volumes up

Crude expected to average 490,000 bpd in FY23, almost 550,000 by FY28

Kristen Nelson

Petroleum News

It’s a long way from the 1988 peak of more than 2 million barrels per day of North Slope production, but volumes are forecast to increase over the state’s current 10-year forecast window.

North Slope crude oil production, which averaged 476,490 barrels per day in fiscal year 2022, down 2%, 9,570 bpd from an average of 486,062 bpd in FY21, is forecast to increase to some 490,000 bpd in FY23, and then average around 500,000 bpd, hitting a peak of 549,000 bpd in FY28.

That forecast is from a presentation by the Department of Natural Resources’ Division of Oil and Gas to Senate and House Finance committees on Jan. 18 and Jan. 23 and from the Fall 2022 Revenue Sources Book.

Travis Peltier, a petroleum engineer with the division, told the committees that for fiscal year 2023 (July 1, 2022, through June 30, 2023), DNR is forecasting “annualized average statewide production” of 501,000 barrels per day, with North Slope production forecast at an average of 492,000 bpd, with a range of 448,000 bpd to 535,000 bpd.

“Outlook on production assumes that operators’ plans and other project drivers stay unchanged,” the division noted in its presentation to the Finance committees.

In both near and medium term, current production is the backbone of state production, declining to below 300,000 bpd by FY32. A small segment of production comes from resources under development - for the current forecast, production expected from wells drilled in FY23.

Over the next 5 to 10 years, production currently under evaluation begins to play a more significant role, accounting for some 250,000 bpd by FY32.

Key future projects

Peltier provided a status for five key future North Slope projects.

*Santos made a final investment decision for the first phase of Pikka in August, with first oil expected from the project in 2026 and a peak design capacity for the first phase of 80,000 bpd.

*Willow, in the National Petroleum Reserve-Alaska, is awaiting a record of decision by the federal Bureau of Land Management on the supplemental environmental impact statement, with operator ConocoPhillips unable to make a final investment decision until there is a ROD for the project. The division said first oil is expected 6 years after FID, and a peak rate of 180,000 bpd estimated.

*ConocoPhillips’ Narwhal CD8 project in the Colville River unit is a new pad development. Sustained production could begin as early as 2028, and DNR estimates a peak of 32,000 bpd.

*Hilcorp Alaska has applied for a new pad, Raven or R, in its Milne Point unit. DNR estimates peak production of 10,000 bpd for the new pad which it said is analogous to Hilcorp’s 2018 M pad development at Milne.

*The Nuna-Torok project at the ConocoPhillips Alaska-operated Kuparuk River unit saw appraisal activity in 2021, with additional drilling planned for 2022, and an ultimate peak rate of up to 25,000 bpd.

Cook Inlet

From FY21 to FY22, Cook Inlet production, which Peltier noted is critical for in-state refineries, declined, down 11%, some 1,200 bpd.

A separate forecast for Cook Inlet was not included in the presentation, but the difference between the ANS forecast and the statewide numbers would indicate a Cook Inlet forecast of some 9,000 bpd for FY23.

The Fall Revenue Sources Book shows a forecast of 9,400 bpd of Cook Inlet crude in FY23, dropping to 8,500 bpd in FY24 and 8,700 bpd in FY25, and then increasing to 9,800 bpd in FY26 and 9,900 bpd in FY27, before declining to average 6,200 bpd at the end of the forecast period in FY32.

A reason for the FY26-FY27 increase is not given in the Revenue Sources Book, but the Middle Ground Shoal field has been shut-in by a leak in a fuel gas line since April 2021. The division has approved applications by Hilcorp Alaska, the field’s owner, for suspension of production at the field through the end of June.

Before that field can come back online the fuel gas pipeline issue needs to be addressed, and the Cook Inlet production forecast, which shows a small increase in FY25 before increasing substantially in the subsequent two fiscal years, may reflect the division’s expectation of when that field would come back online.

Middle Ground Shoal was averaging just over 1,200 bpd in the two months prior to the shut-in.

Peltier cited Middle Ground Shoal as a reason for decreases in Cook Inlet production and said increases FY21 and FY22 were due to work by Hilcorp at Beaver Creek, and the return to production of the Glacier Oil and Gas fields Redoubt Shoal and West McArthur River, which had been offline since May 2020 and came back online in September and October of 2021.

North Slope highlights

In summarizing North Slope production for FY22 compared to FY21, Peltier said all production areas had year-on-year declines, with FY22 down some 2%, 9,570 bpd, for FY21.

At ConocoPhillips Alaska’s Alpine, there was a natural decline after flush production following an extended shut-in from 2020, and due to limited development drilling in FY22.

At Kuparuk and the Kuparuk satellites, managed and majority owned by ConocoPhillips, natural decline followed ending of natural gas liquids imports and associated enhanced oil recovery in early 2022. Offshore fields saw a natural reservoir decline.

FY21 to FY22 increases were in the National Petroleum Reserve-Alaska, where ConocoPhillips brought a second pad came online at Greater Mooses Tooth; at the Prudhoe Bay satellites (which, for production reporting purposes, include Hilcorp’s Milne Point), which had a 10% production growth from “consistent drilling efforts”; and at Hilcorp-operated Point Thomson, where an 8% growth was due to improved reliability of facilities.

The forecast

In forecasting, the division looked at publicly available well data and did “ground-up” decline curve forecasts for producing pools, based on Alaska Oil and Gas Conservation Commission data. There were some 37 producing pools in the state as of June 30.

The division also engaged with operators, and considered confidential data on 17 projects under development or under evaluation, with forecasts for those using confidential data from operators, with future volumes “adjusted and risked for scope of contribution, chance of occurrence and start date.”

Peltier said a reason the ANS production forecast shows gradual rather than jagged changes when plotted is because new projects are risked for volumes, start dates and likelihood.

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