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NOTE 18 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

Capitalized Costs

Net capitalized costs related to oil, NGLs and natural gas producing activities are as follows (in thousands):

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil, NGLs and natural gas property acquisition, exploration, and development activities (in thousands):

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Oil and Natural Gas Reserve Information

There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represents estimates only and are inherently imprecise. Reserve estimates were prepared based on the interpretation of various data by the Company’s independent reservoir engineers, including production data and geological and geophysical data of the Company’s existing wells.

All of the Company’s reserves are located in the United States with all located in state and federal waters in the Gulf of America. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC. The prices used do not purport, nor should it be interpreted, to present the current market prices related to estimated oil and natural gas reserves.

The following sets forth changes in estimated quantities of net proved oil, NGLs and natural gas reserves:

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During 2024, increases in revisions of previous estimates were primarily related to upward revisions to the Garden Banks 783 field offset by decreases due to SEC price revisions for all proved reserves. Proved reserves were also added through the acquisition of properties in January 2024.

During 2023, decreases in revisions of previous estimates were primarily due to SEC price revisions for all proved reserves. Proved reserves were also added through the acquisition of properties in September 2023.

During 2022, increases in revisions of previous estimates were primarily due to upward revisions to the Brazos A133 field combined with increases due to SEC price revisions for all proved reserves. Proved reserves were also added through the acquisitions of properties acquired from ANKOR and subsequent working interest acquisition in the same properties from a private seller.

As of December 31, 2024, we believe that we will be able to develop all but 5.9 MMBoe (approximately 27%) of the total 21.7 MMBoe classified as PUDs within five years from the date such PUDs were initially recorded. The primary exceptions are at the Mississippi Canyon 243 field (“Matterhorn”), Ship Shoal 349 field (“Mahogany”) and Viosca Knoll 823 field (“Virgo”) where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Three sidetrack PUD locations, one each at Matterhorn, Mahogany and Virgo, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2026 and 2036. The other exception is at the Garden Banks 783 field (“Magnolia”) where significant spending has already begun on rig and platform modifications for development drilling, but the timeline has been extended to 2026 before we will be able to mobilize the rig. 

Standardized Measure of Discounted Future Net Cash Flows

The following presents the standardized measure of discounted future net cash flows related to the Company’s proved oil, NGLs and natural gas reserves together with changes therein (in millions):

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Future cash inflows represent expected revenues from production of period-end quantities of proved reserve computed using SEC pricing for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the WTI oil spot price. Then, this ratio is applied to the oil price using SEC guidance. The average realized commodity prices used to determine the standardized measure are as follows:

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Future production, development and abandonment costs and production rates and timing were based on the best information available to the Company. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on the prescribed annual discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of the Company’s oil, NGLs and natural gas reserves. Actual prices realized, costs incurred, and production quantities and timing may vary significantly from those used.

The change in the standardized measure of discounted future net cash flows relating to the Company’s proved oil, NGLs and natural gas reserves is as follows (in millions):

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