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Property and Equipment | 6 Months Ended
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Dec. 31, 2023
Property and Equipment |
Property and Equipment | Note 3. Property and Equipment Property and equipment as of December 31, 2023 and June 30, 2023 consisted of the following (in thousands): ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | December 31, 2023 |  | June 30, 2023
Oil and natural gas properties | ​ | ​ |  | ​ | ​ |
Property costs subject to amortization | ​ | $ | 199,526 | ​ | $ | 197,049
Property costs not subject to amortization | ​ | ​ | 3,370 | ​ | ​ | —
Less: Accumulated depletion, depreciation, and impairment | ​ | ​ | (99,415) | ​ | ​ | (91,268)
Oil and natural gas properties, net | ​ | $ | 103,481 | ​ | $ | 105,781
​ As of December 31, 2023, $3.4 million of oil and natural gas property costs were not subject to amortization. On September 12, 2023, the Company entered into a Participation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo Field, located in Chaves and Roosevelt Counties, New Mexico. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells. Upon signing the Participation Agreement, the Company paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transactions costs, in exchange for a 50% working interest share in the existing leases associated with two initial development blocks, or nine drilling locations. Following completion of the initial nine development wells, the Company will have the right, but not the obligation, to elect to participate and acquire a 50% working interest share in the next development block, for up to a total of approximately 16,000 gross acres for the payment of $450 per acre. The Company allocated all of the acreage costs associated with the initial acreage purchase to unevaluated oil and natural gas properties. As of December 31, 2023, the Company has incurred approximately $3.0 million in capital expenditures related to the drilling and completion of an initial three wells. These capital expenditures are recorded as unevaluated property costs. The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties. Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. Depletion of oil and natural gas properties was $8.1 million and $6.5 million for the six months ended December 31, 2023 and 2022, respectively. During the six months ended December 31, 2023 and 2022, the Company incurred development capital expenditures of $2.4 million and $2.1 million, respectively. At December 31, 2023, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended December 31, 2023 of the West Texas Intermediate (“WTI”) crude oil spot price of $78.21 per barrel and Henry Hub natural gas spot price of $2.63 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $31.57, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2023 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary. At December 31, 2022, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended December 31, 2022 of the WTI crude oil spot price of $94.14 per barrel and Henry Hub natural gas spot price of $6.40 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $48.50, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2022 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary.

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