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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2025

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

NOTE 17—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

​

​	​	​	​	​	​	​
​	​	December 31,		​	December 31,
​	​	2025		​	2024
​	​	(In thousands)
Oil, natural gas and NGL interests	​	​	​	​	​	​
Proved properties	​	$	2,097,281	​	$	1,933,512
Unevaluated properties	​	​	174,189	​	​	115,200
Total oil, natural gas and NGL interests	​		2,271,470	​		2,048,712
Accumulated depreciation, depletion, accretion and impairment	​		(1,148,157)	​		(1,023,890)
Net oil, natural gas and NGL interests capitalized	​	$	1,123,313	​	$	1,024,822

​

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2025		​	2024		​	2023
​	​	(In thousands)
Acquisition costs	​	​	​	​	​	​	​	​	​
Proved properties	​	$	95,000	​	$	22	​	$	260,146
Unevaluated properties	​	​	127,759	​	​	—	​	​	322,559
Total costs incurred on oil, natural gas and NGL activities	​	$	222,759	​	$	22	​	$	582,705

​

Results of Operations from Oil, Natural Gas and NGL Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2025		​	2024		​	2023
​	​	(In thousands)
Oil, natural gas and NGL revenues	​	$	317,473	​	$	304,605	​	$	267,586
Lease bonus and other income	​	​	4,266	​	​	6,047	​	​	5,594
Production and ad valorem taxes	​		(20,440)	​		(20,407)	​		(20,326)
Depreciation and depletion expense	​		(124,554)	​		(135,123)	​		(96,477)
Impairment of oil and natural gas properties	​		—	​		(62,118)	​		(18,220)
Marketing and other deductions	​		(16,350)	​		(16,122)	​		(12,566)
Results of operations from oil, natural gas and NGLs	​	$	160,395	​	$	76,882	​	$	125,591

​

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves. The estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2025, 2024 and 2023. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

​

​	​	​	​	​	​	​	​	​
​	​	Crude Oil and	​	​	​	Natural Gas	​	​
​	​	Condensate	​	Natural Gas	​	Liquids	​	Total
​	​ ​ ​	(MBbls)	​ ​ ​	(MMcf)	​ ​ ​	(MBbls)	​ ​ ​	(MBoe) (4)
Net proved reserves at January 1, 2023	​	12,355	​	160,298	​	7,388	​	46,459
Revisions of previous estimates (1)	​	3,273	​	26,068	​	814	​	8,432
Purchase of minerals in place (2)	​	6,565	​	41,560	​	4,400	​	17,892
Production	​	(2,393)	​	(23,384)	​	(1,083)	​	(7,374)
Net proved reserves at December 31, 2023	​	19,800	​	204,542	​	11,519	​	65,409
Revisions of previous estimates (1)	​	3,038	​	27,297	​	3,646	​	11,234
Production	​	(2,837)	​	(27,586)	​	(1,667)	​	(9,102)
Net proved reserves at December 31, 2024	​	20,001	​	204,253	​	13,498	​	67,541
Revisions of previous estimates (1)	​	2,795	​	30,045	​	2,408	​	10,211
Purchase of minerals in place (3)	​	2,236	​	6,025	​	1,355	​	4,595
Production	​	(3,062)	​	(26,734)	​	(1,885)	​	(9,403)
Net proved reserves at December 31, 2025	​	21,970	​	213,589	​	15,376	​	72,944
​	​	​	​	​	​	​	​	​
Net proved developed reserves	​	​	​	​	​	​	​	​
December 31, 2023	​	19,800	​	204,542	​	11,519	​	65,409
December 31, 2024	​	20,001	​	204,253	​	13,498	​	67,541
December 31, 2025	​	21,970	​	213,589	​	15,376	​	72,944

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

(2) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent.

(3) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin.

(4) Includes total proved reserves of 9,798 MBoe, 10,273 MBoe and 14,399 MBoe as of December 31, 2025, 2024 and 2023, respectively, attributable to a non-controlling interest in the Partnership.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​ ​ ​	2025		​	2024		​	2023
​	​	(In thousands)
Future cash inflows	​	$	2,213,270	​	$	2,040,600	​	$	2,226,313
Future production costs	​	​	(162,622)	​	​	(152,322)	​	​	(164,848)
Future state margin taxes	​	​	(47,672)	​	​	(45,384)	​	​	(49,144)
Future net cash flows	​	​	2,002,976	​	​	1,842,894	​	​	2,012,321
Less 10% annual discount to reflect timing of cash flows	​	​	(1,033,046)	​	​	(955,134)	​	​	(1,037,192)
Standard measure of discounted future net cash flows	​	$	969,930	​	$	887,760	​	$	975,129

​

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2025, 2024 and 2023 were $65.34, $75.48 and $78.22 per barrel for crude oil and $3.39, $2.13 and $2.64 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2025		​	2024		​	2023
​	​	(In thousands)
Standardized measure - beginning of year	​	$	887,760	​	$	975,129	​	$	904,295
Sales, net of production costs	​	​	(278,867)	​	​	(266,202)	​	​	(236,953)
Net changes of prices and production costs related to future production	​	​	10,854	​	​	(107,311)	​	​	(302,599)
Revisions of previous quantity estimates, net of related costs	​	​	139,001	​	​	151,289	​	​	128,727
Net changes in state margin taxes	​	​	(1,223)	​	​	1,952	​	​	10,433
Accretion of discount	​	​	70,163	​	​	76,600	​	​	78,425
Purchases of reserves in place	​	​	98,210	​	​	-	​	​	435,230
Timing differences and other	​	​	44,032	​	​	56,303	​	​	(42,429)
Standardized measure - end of year	​	$	969,930	​	$	887,760	​	$	975,129

​

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- Definition

The entire disclosure for oil- and gas-producing activities considered to be supplementary information. Includes, but is not limited to, proved reserve quantity, cost incurred and capitalized, result of operation, standardized measure, and change in standardized measure of discounted future cash flow.

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-SubTopic 270
-Name Accounting Standards Codification
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