Vol. 28, No.6 Week of February 05, 2023
Providing coverage of Alaska and northern Canada's oil and gas industry

Upcoming gas shortage

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Assessment sees reduced volumes from proved resources of inlet gas after 2027

Kristen Nelson

Petroleum News

Hilcorp Alaska, Southcentral’s primary natural gas producer, began warning its utility customers last year that, while it could meet obligations under its existing contracts, it did not have firm natural gas supplies available beyond that.

A new study of Cook Inlet gas supplies by the Alaska Department of Natural Resources’ Division of Oil and Gas, updating studies done since 2009, has found that while significant volumes of natural gas are “potentially available through additional investment and development in currently producing fields,” there are only 820 billion cubic feet of proved gas reserves which are economic to develop. “The key uncertainties that drive the variability in these estimates are costs, production rates, and the rate of return companies require to invest in new projects,” the report said.

With a current demand level of some 70 bcf per year volumes identified in the study can only satisfy the current demand until around 2027, the division found.

The report is authored by the division’s John Burdick, a petroleum reservoir engineer, and Jhonny Meza, a commercial analyst.

The gas included in the study was limited to proved developed and undeveloped categories, the report says, which means “sanctioning of gas projects that are currently under evaluation for their commercial viability is an important contributor to meeting the demand of gas when the economic production in this study falls below 70 bcf per year.”

The report stresses that it is not intended as a prediction of Cook Inlet gas supply and demand, but “serves as a tool for understanding Cook Inlet’s capacity to meet natural gas demand under present conditions and assumptions.”

Fields and pools

The report looks at 38 currently or historically producing gas fields in Cook Inlet and uses data publicly available from the Alaska Oil and Gas Conservation Commission. Within those 38 fields, the report evaluated 90 pools, with historical production considered through the end of 2021.

The report assumes a steady drilling pace of 15 development wells per year for the remainder of the decade, based on 2009-2019 drilling, with years beyond 2019 not considered because the drilling pace then was impacted by the COVID-19 pandemic and the market crash which resulted.

60 years of production

Cook Inlet has been in production for more than 60 years, and in a Jan. 30 presentation to the Senate Resources Committee, Burdick and Meza presented a slide showing the share of production from wells by vintage which illustrates the importance of continuous development drilling.

In 2005, 69% of gas produced was from wells drilled prior to 2000, while by 2021, that percentage had dropped to 20%. Exploration has led to 13 new oil and gas units coming online and more than 450 wellbores drilled since 2000, as noted in a slide from that presentation.

DNR Commissioner-designee John Boyle said in introductory comments that natural gas is a finite resource. The questions, he said, are whether the natural gas supply will increase or demand decrease, and he noted the potential for additional gas along with other options such as liquefied natural gas imports.

Boyle also said, as does the report, that another factor to be considered is the health of the service and support industry in Cook Inlet, with reduced production providing fewer opportunities for the support industry.

The report said among the issues it does not address is the basin-wide effect that “some fields reaching the end of their economic lives could have on the service industry. A fewer number of surviving gas-producing fields could lead to the downsizing of the service industry in terms of providers or the availability of rigs.”


The 2022 forecast is a technical assessment using decline curve analysis to estimate volumes from currently producing fields. Discovered resources - requiring more favorable commercial conditions for approval - and undiscovered resources were not included in the forecast.

The technical forecast was subject to economic analysis including such factors as the unlikelihood that companies will operate fields as a sustained loss and that if marginal revenue does not cover marginal expenditures, the operator is likely to stop production and any remaining technically recoverable gas will not be available to the market.

The report also says that where fields share facilities, such as pipelines, one field closing down for economic reasons may have a ripple effect, increasing pipeline costs for the remaining field and causing that field to also become uneconomic to produce.


The study does not consider undiscovered gas and “does not encompass all the gas that remains in Cook Inlet. Additional supplies may come from sources not considered in this report: new development in some smaller existing fields, currently unidentified prospects, added compression that increases ultimate recovery, and unconventional resources.”

A slide in the presentation to legislators noted that both the U.S. Geological Survey and the federal Bureau of Ocean Energy Management have released estimates of undiscovered, technically recoverable gas in Cook Inlet - USGS in 2011 estimating a mean of 13.7 trillion cubic feet of conventional gas and BOEM also in 2011 assessing 1.2 trillion cubic feet in the southern Cook Inlet outer continental shelf area. Undiscovered resources are not considered in the division’s study.

In state waters, BlueCrest has discovered natural gas offshore at Cosmopolitan, but, Senate Resources Chair Cathy Geissel said in the hearing, developing that gas would require installation of a platform.

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