Note 4. Property and Equipment

Property and equipment consisted of the following for the periods presented (in thousands):

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As of December 31, 2025, $4.6 million of oil and natural gas property costs were not subject to amortization. These costs related to mineral and royalty interests acquired as part of the Company’s Minerals Acquisition described in Note 3, “Acquisitions” above. The mineral and royalty interests include approximately 3,600 net royalty acres for unproved locations. Property costs identified at the Minerals Acquisition associated with proved reserves were recorded to evaluated oil and natural gas properties and subject to amortization.

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 unproved 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 on oil and natural gas properties was $11.1 million and $10.3 million for the six months ended December 31, 2025 and 2024, respectively. During the six months ended December 31, 2025 and 2024, the Company incurred development capital expenditures of $2.5 million and $2.2 million, respectively.

At December 31, 2025, 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, 2025 of the West Texas Intermediate (“WTI”) crude oil spot price of $66.01 per barrel and Henry Hub natural gas spot price of $3.40 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $23.22, 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, 2025 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.

At December 31, 2024, 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, 2024 of the WTI crude oil spot price of $76.32 per barrel and Henry Hub natural gas spot price of $2.13 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $22.60, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.