NOTE 19 — 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

All of the Company’s proved reserves are located in state and federal waters in the U.S. Gulf of Mexico. 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 reserves are located in the United States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. 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 estimated quantities of net proved oil, NGLs and natural gas reserves:

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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.

During 2021, increases in revisions of previous estimates were primarily due to upward revisions to the Garden Banks 783 (Magnolia) field combined with increases due to SEC price revisions for all proved reserves.

During 2020, decreases in revisions of previous estimates were primarily due to additions made in the Mobile Bay properties due to the consolidation of the Yellowhammer and OTF gas plants which significantly reduced field lease operating expenses and additions made in the Garden Banks 783 (Magnolia) field. These additions were offset due to significant negative revisions due to SEC price revisions for all proved reserves. Proved reserves were also added as a result of working interest acquisitions in both the Mobile Bay Properties and Garden Banks 783 (Magnolia) field.

The Company believes that it will be able to develop all but 2.5 MMBoe (approximately 12%) of the total 20.5 MMBoe classified as PUDs at December 31, 2022, within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”) and Viosca Knoll 823 (“Virgo”) deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one each at Matterhorn and Virgo, will be delayed until an existing well is depleted and available to sidetrack. The Company also plans to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well. Based the latest reserve report, these PUD locations are expected to be developed in 2024.

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 thousands):

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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 crude oil realized price. Then, this ratio is applied to the crude oil price using SEC guidance. The average base 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 thousands):

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