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Nicolai royalty reduction
Division publishes preliminary finding reducing small gas field royalty rate
Kristen Nelson Petroleum News
The Alaska Department of Natural Resources has released Commissioner John Boyle's preliminary findings and determination favoring a royalty reduction for Amaroq Resources' Nicolai Creek, a small west side Cook Inlet natural gas field.
The deadline for public comments on the Aug. 5 preliminary findings and determination is 4:30 p.m. Sept. 5. After close of the comment period DNR will issue a written decision approving or denying the application.
DNR said Amaroq began engaging with the department in October 2022 on requirements of an application, submitted a draft application in July 2024 and based on feedback from DNR, submitted its application Sept. 3, 2024.
Alaska statutes allow royalty modification under three scenarios: to allow production for an oil or gas field that has not previously produced oil or gas for sale; to prolong the economic life of oil or gas as the price decreases or costs increase "sufficient to make future production no longer economically feasible"; or to allow reestablishing shut-in production "from the zones previously produced by now non-producing wells."
DNR said Amaroq is seeking royalty modification based on increasing costs per unit produced making the field no longer economic and to reestablish production from zones previously produced in wells not currently producing.
Nicolai Creek There are 471 unitized acres in the Nicolai Creek unit, originally formed by Texaco in 1968, and operated by that company until 1977 when production was shut in. Union Oil Company of California and Marathon Oil Co. acquired the unit in 1988 but were unable to restore production. Aurora Gas took over the leases in 2000, restarting production in 2001 and producing gas from the field until that company's bankruptcy in 2018.
Amaroq acquired Nicolai Creek in 2018.
Current sustained production began in 2001, DNR said, peaking in 2012 at annual production of 1.2 billion cubic feet. From 2001 to 2024 production averaged 0.4 bcf annually.
There are three onshore pads and six active wells, one a disposal injection well, with only three of the five producers currently online, averaging 380 thousand cubic feet per day, as of May, for annual production of 0.1 bcf.
Application DNR said Amaroq's application is for royalty modifications on all five leases in the unit. The current state royalty rate is 12.5%, and the leases have overriding royalty interests ranging from 1.5% to 6.5%, with the average total royalty burden of 17.28% for the five leases.
Amaroq told DNR that since it acquired Nicolai Creek in 2018 it has operated at a negative cash flow as its attempts to revitalize the field have not been successful and said the field would continue to generate negative cash flows, even with an updated contract price of $10 per thousand cubic feet.
The company also said royalty reduction was justified to reestablish production from two currently shut-in wells, NCU 3 and NCU 10, work which would not be economically feasible without royalty modification.
DNR said Amaroq "clearly showed" in its application that future production would not be economically feasible without royalty modification, as operating expenditures do not change with lower production rates and minimum general and administrative costs do not change with lower volume.
Amaroq had a third-party review done by Petrotechnical Resources of Alaska of potential reserves under the two wells currently offline, a report which confirmed proven and probable reserves that could be economically recovered with more favorable economic conditions.
Extended life Amaroq told DNR that at a 3% royalty rate -- the lowest allowed by statute -- the economic life of the field would be extended by at least 12 months, and with additional work to bring the two offline wells back online, 10 additional years could be added.
"Granting royalty modification would provide Amaroq the ability to sustain operations while planning additional well work to maintain and restore any production from existing wells and implement additional development of the NCU acreage," DNR said.
Amaroq proposed a reduction to 3% until the field showed annual positive cash flows and profitability, but DNR said it found this was not optimal. The commissioner's preliminary determination calls for royalty modification based on cumulative gross revenues "driven by the price and volume of gas sold."
DNR's proposed terms are a royalty rate of 3% per month until gross revenue from the unit, beginning Sept. 1, 2024, reaches a cumulative amount of $25,300,000, after which the royalty rate would return to 12.5%.
Economic modelling by DNR shows an expected end of field life of September 2026 if there is no modification of the royalty.
At the 3% rate, but with no development drilling, field life would end in September 2027.
DNR's expected case for development drilling shows a field life end in 2030.
Benefits to the state include the expected field life extension, increased gas production and increase in direct revenues to the state.
Indirect benefits to the state include continued local gas production, which is less expensive than displacing local gas with imported liquefied natural gas.
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