Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2023

Supplemental Oil and Gas Disclosures (Unaudited)

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil and coal in exchange for royalty payments based on the lessees' sales of those minerals. As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. See Note 1, Note 2 and Note 15 for additional discussion of the Minerals Management segment.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and gas royalty and mineral interests with applicable accumulated depreciation, depletion and amortization at December 31 are as follows:


	2023		2022
Proved developed	$	16,179	$	7,302
Proved undeveloped	51,971		24,134
Proved reserves	68,150		31,436
Less: accumulated depreciation, depletion and amortization	3,309		1,936
Net royalty interests in oil and natural gas properties	$	64,841	$	29,500

Oil and Natural Gas Reserves

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to Company interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31 based on the reserve report prepared by Haas Engineering, the Company’s independent petroleum engineering firm. All of the Company’s reserves are located in the United States.


	Net reserves as of December 31, 2023
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
Proved developed	656,370	380,650	23,596,110
Proved undeveloped	9,020	3,720	26,420
Total	665,390	384,370	23,622,530


	Net reserves as of December 31, 2022
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
Proved developed	305,710	408,280	25,907,890
Proved undeveloped	32,570	11,030	1,784,670
Total	338,280	419,310	27,692,560

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

Estimated Proved Reserves

The following table summarizes changes in proved reserves during the year ended December 31, 2023:


	Estimated Proved Reserves
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
December 31, 2022	338,280	419,310	27,692,560
Purchases	259,178	43,934	609,184
Extensions and discoveries	170,330	77,527	2,340,715
Revisions of previous estimates (3)	37,483	(73,375)	1,027,779
Production	(98,553)	(56,768)	(7,601,521)
Other	(41,328)	(26,258)	(446,187)
December 31, 2023	665,390	384,370	23,622,530

Estimated Proved Undeveloped Reserves ("PUDs")

The following table summarizes changes in PUDs during the year ended December 31, 2023:


	Estimated Proved Undeveloped Reserves
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
December 31, 2022	32,570	11,030	1,784,670

Purchases	2,300	950	8,237
Extensions and discoveries	5,786	2,021	14,814
Conversions	(29,757)	(9,172)	(1,770,232)
Revisions of previous estimates (3)	(1,879)	(1,109)	(11,069)

December 31, 2023	9,020	3,720	26,420

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

As an owner of mineral and royalty interests, the Company generally does not have evidence of approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2023, PUD reserves consists of 45 wells in various stages of drilling or completions. As of December 31, 2023, less than 1% of the Company's total proved reserves were classified as PUDs.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. Future cash inflows are computed by applying applicable prices relating to proved reserves to the year-end quantities of those reserves. Future production and costs are derived based on current costs assuming continuation of existing economic conditions. Federal income tax expenses are deducted from future production revenues in the calculation of the standardized measure using the statutory tax rate. The Company is subject to certain state-based taxes; however, these amounts are not material. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2023:


	Gross Amounts		Statutory tax rate		Net Amounts
Future cash inflows(3)	$	122,286
Future production costs	27,487
Future net cash flows before income tax expense	94,799		21	%	74,891
10% discount to reflect timing of cash flows	(33,521)		21	%	(26,481)
Standardized measure of discounted cash flows	$	61,278	21	%	$	48,410

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2022:


	Gross Amounts		Statutory tax rate		Net Amounts
Future cash inflows(3)	$	218,982
Future production costs	39,841
Future net cash flows before income tax expense	179,141		21	%	141,521
10% discount to reflect timing of cash flows	(62,615)		21	%	(49,465)
Standardized measure of discounted cash flows	$	116,526	21	%	$	92,056

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows during 2023:


	Gross amounts
	2023		2022
January 1	$	116,526	$	36,839

Purchases	11,312		6,236
Extensions and discoveries	11,419		54,795
Revisions of previous estimates (3)(4)	(61,206)		18,695
Conversions	(16,773)		(39)
December 31	$	61,278	$	116,526

(3) Requirements for oil and gas reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The benchmark price for WTI crude oil sold at Cushing, OK during 2023 and 2022 was $78.22 and $93.67 per bbl, respectively. The benchmark price for natural gas delivered at Henry Hub during 2023 and 2022 was $2.64 and $6.36 per MMBTU, respectively. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

(4) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.