Supplemental information on oil and gas activities

12 Months Ended

Dec. 31, 2025

Supplemental information on oil and gas activities

Supplemental information on oil and gas activities

Note 37     Supplemental information on oil and gas activities (unaudited)

The following information is presented in accordance with ASC No. 932 “Extractive Activities- Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on December 31, 2008. This information includes the Group’s oil and gas production activities carried out in each country.

Table 1 - Costs incurred in exploration, property acquisitions and development

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2025, 2024 and 2023. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2025
Acquisition of properties
Proved	—	115,689	—	—	—	115,689
Unproved	—	—	—	—	—	—
Total property acquisition	—	115,689	—	—	—	115,689
Exploration	35,443	2,345	147	310	—	38,245
Development (a)	70,931	1,432	150	11	—	72,524
Total costs incurred	106,374	3,777	297	321	—	110,769

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2024
Acquisition of properties
Proved	—	—	—	—	—	—
Unproved	—	—	—	—	—	—
Total property acquisition	—	—	—	—	—	—
Exploration	46,330	2,839	86	24,223	—	73,478
Development (a)	127,403	—	933	729	—	129,065
Total costs incurred	173,733	2,839	1,019	24,952	—	202,543

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2023
Acquisition of properties
Proved	—	—	—	—	—	—
Unproved	—	—	—	—	—	—
Total property acquisition	—	—	—	—	—	—
Exploration	66,953	1,481	107	13,331	56	81,928
Development (a)	125,997	—	255	372	(564)	126,060
Total costs incurred	192,950	1,481	362	13,703	(508)	207,988

(a) Includes the effect of change in estimate of assets retirement obligations.

Table 2 - Capitalized costs related to oil and gas producing activities

The following table presents the capitalized costs as of December 31, 2025, 2024, and 2023, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

Amounts in US$‘000	Colombia	Argentina	Brazil (b)	Ecuador (b)	Chile (c)	Total
As of December 31, 2025
Proved properties (a)
Equipment, camps and other facilities	204,017	—	—	—	—	204,017
Mineral interest and wells	974,315	115,689	—	—	—	1,090,004
Other uncompleted projects	31,057	1,432	—	—	—	32,489
Unproved properties	95,786	—	223	—	—	96,009
Gross capitalized costs	1,305,175	117,121	223	—	—	1,422,519
Accumulated depreciation	(647,458)	(2,086)	—	—	—	(649,544)
Total net capitalized costs	657,717	115,035	223	—	—	772,975

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile (c)	Total
As of December 31, 2024
Proved properties (a)
Equipment, camps and other facilities	189,282	—	3,220	—	—	192,502
Mineral interest and wells	950,388	—	38,561	45,897	—	1,034,846
Other uncompleted projects	23,856	—	261	—	—	24,117
Unproved properties	88,105	—	101	12,749	—	100,955
Gross capitalized costs	1,251,631	—	42,143	58,646	—	1,352,420
Accumulated depreciation	(561,537)	—	(37,257)	(16,683)	—	(615,477)
Total net capitalized costs	690,094	—	4,886	41,963	—	736,943

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile (c)	Total
As of December 31, 2023
Proved properties (a)
Equipment, camps and other facilities	165,666	—	4,121	—	74,491	244,278
Mineral interest and wells	841,063	—	48,448	31,149	330,024	1,250,684
Other uncompleted projects	15,770	—	11	—	—	15,781
Unproved properties	69,823	—	330	10,426	—	80,579
Gross capitalized costs	1,092,322	—	52,910	41,575	404,515	1,591,322
Accumulated depreciation	(447,716)	—	(47,388)	(8,522)	(379,448)	(883,074)
Total net capitalized costs	644,606	—	5,522	33,053	25,067	708,248

(a) Includes capitalized amounts related to asset retirement obligations.

(b) The Manati gas field in Brazil (see Note 34.2) and the Perico and Espejo Blocks in Ecuador (see Note 34.3) were divested in December 2025.

(c) The entire Chilean business was divested in January 2024. See Note 34.7.

Table 3 - Results of operations for oil and gas producing activities

The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2025, 2024 and 2023. Income tax for the years presented was calculated utilizing the statutory tax rates.

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2025
Revenue	461,418	5,783	6,435	18,463	—	492,099
Production costs, excluding depreciation
Operating costs	(115,804)	(3,398)	(4,491)	(7,775)	—	(131,468)
Royalties and economic rights in cash	(8,210)	(699)	(365)	—	—	(9,274)
Total production costs	(124,014)	(4,097)	(4,856)	(7,775)	—	(140,742)
Exploration expenses	(20,126)	(2,345)	(41)	(149)	—	(22,661)
Accretion expense (a)	(1,319)	—	(576)	(62)	—	(1,957)
Impairment loss for non-financial assets	—	—	—	(30,989)	—	(30,989)
Depreciation, depletion and amortization	(105,783)	(2,086)	(1)	(4,079)	—	(111,949)
Results of operations before income tax	210,176	(2,745)	961	(24,591)	—	183,801
Income tax (expense) benefit	(73,562)	961	(327)	(1,600)	—	(74,528)
Results of oil and gas operations	136,614	(1,784)	634	(26,191)	—	109,273

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2024
Revenue	619,762	—	2,934	30,567	398	653,661
Production costs, excluding depreciation
Operating costs	(133,197)	—	(3,916)	(9,549)	(425)	(147,087)
Royalties and economic rights in cash	(10,437)	—	(224)	—	(12)	(10,673)
Total production costs	(143,634)	—	(4,140)	(9,549)	(437)	(157,760)
Exploration expenses	(13,984)	(2,839)	(242)	(7,880)	—	(24,945)
Accretion expense (a)	(987)	—	(636)	(128)	—	(1,751)
Impairment loss for non-financial assets	—	—	—	—	—	—
Depreciation, depletion and amortization	(113,820)	—	(227)	(8,162)	—	(122,209)
Results of operations before income tax	347,337	(2,839)	(2,311)	4,848	(39)	346,996
Income tax expense	(156,302)	—	786	(1,212)	—	(156,728)
Results of oil and gas operations	191,035	(2,839)	(1,525)	3,636	(39)	190,268

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Year ended December 31, 2023
Revenue	702,401	—	14,019	19,097	15,644	751,161
Production costs, excluding depreciation
Operating costs	(121,012)	—	(3,850)	(10,242)	(7,678)	(142,782)
Royalties and economic rights in cash	(83,233)	—	(1,096)	—	(548)	(84,877)
Total production costs	(204,245)	—	(4,946)	(10,242)	(8,226)	(227,659)
Exploration expenses	(36,395)	(1,481)	(90)	(309)	(56)	(38,331)
Accretion expense (a)	(669)	—	(560)	(87)	(1,478)	(2,794)
Impairment loss for non-financial assets	—	—	—	—	(13,332)	(13,332)
Depreciation, depletion and amortization	(92,735)	—	(1,047)	(6,205)	(8,278)	(108,265)
Results of operations before income tax	368,357	(1,481)	7,376	2,254	(15,726)	360,780
Income tax expense	(165,761)	—	(2,508)	(564)	—	(168,833)
Results of oil and gas operations	202,596	(1,481)	4,868	1,690	(15,726)	191,947

(a) Represents accretion of ARO and other environmental liabilities.

Table 4 - Reserve quantity information

Estimated oil and gas reserves

Proved reserves represent estimated quantities of oil (including crude oil and condensate) and natural gas, which available geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.

The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008.

The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, 2025, 2024, 2023 and 2022 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton Corp. prepared its proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities).

Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be exactly measured, and the reserve estimation depends on the quality of available information and the interpretation and judgement of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.

The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2025, 2024, 2023, and 2022 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	As of December 31, 2025		As of December 31, 2024		As of December 31, 2023		As of December 31, 2022
	Oil and		Oil and		Oil and		Oil and
	condensate	Natural gas	condensate	Natural gas	condensate	Natural gas	condensate	Natural gas
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)
Net proved developed
Colombia (a)	43,409	—	49,959	884	43,120	1,075	46,623	1,065
Argentina (b)	1,807	430	—	—	—	—	—	—
Brazil (c)	—	—	15	6,116	28	8,888	8	9,443
Ecuador (d)	—	—	515	—	1,017	—	322	—
Chile (e)	—	—	—	—	619	9,956	1,115	14,103
Total consolidated	45,216	430	50,489	7,000	44,784	19,919	48,068	24,611
Net proved undeveloped
Colombia (f)	4,082	—	6,396	—	16,225	—	17,765	—
Argentina (b)	8,885	2,114	—	—	—	—	—	—
Ecuador (d)	—	—	367	—	1,278	—	—	—
Chile (e)	—	—	—	—	479	855	476	—
Total consolidated	12,967	2,114	6,763	—	17,982	855	18,241	—
Total proved reserves	58,183	2,544	57,252	7,000	62,766	20,774	66,309	24,611

(a) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 96% and 4% (99% and 1% in 2024, 94% and 6% in 2023, and 96% and 4% in 2022) of the proved developed reserves, respectively.

(b) Loma Jarillosa Este Block in the Vaca Muerta formation in the Neuquen Basin account for 100% of the reserves.

(c) BCAM-40 Block accounted for 100% of the reserves.

(d) Perico Block accounted for 100% of the reserves in 2024 and 2023 (Perico and Espejo Blocks accounted for 85% and 15% of the reserves, respectively, in 2022).

(e) Fell Block accounted for 100% of the reserves.

(f) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 89% and 11% (100% and 0% in 2024, 97% and 3% in 2023, and  95% and 5% in 2022) of the proved undeveloped reserves, respectively.

Table 5 - Net proved reserves of oil, condensate and natural gas

Net proved reserves (developed and undeveloped) of oil and condensate:

Thousands of barrels	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Reserves as of December 31, 2022	64,388	—	8	322	1,591	66,309
Increase (decrease) attributable to:
Revisions (a)	3,617	—	26	324	(412)	3,555
Extensions and discoveries (b)	2,549	—	—	1,937	—	4,486
Production	(11,209)	—	(6)	(288)	(81)	(11,584)
Reserves as of December 31, 2023	59,345	—	28	2,295	1,098	62,766
Increase (decrease) attributable to:
Revisions (c)	7,495	—	(12)	(803)	—	6,680
Extensions and discoveries (d)	485	—	—	—	—	485
Disposal of Minerals in place (e)	—	—	—	—	(1,096)	(1,096)
Production	(10,970)	—	(1)	(610)	(2)	(11,583)
Reserves as of December 31, 2024	56,355	—	15	882	—	57,252
Increase (decrease) attributable to:
Revisions (f)	2,354	—	—	—	—	2,354
Extensions and discoveries (g)	23	—	—	—	—	23
Purchase or (Disposal) of Minerals in place (h)	(1,644)	10,788	(12)	(488)	—	8,644
Production	(9,597)	(96)	(3)	(394)	—	(10,090)
Reserves as of December 31, 2025	47,491	10,692	—	—	—	58,183

(a) For the year ended December 31, 2023, the Group’s oil and condensate proved reserves were revised upwards by 3.5 mmbbl. The primary factors leading to the above were:

- An increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan.

- An increase of 1.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells.

- An increase of 0.4 mmbbl in Colombia due to a change in the royalties’ payment in certain fields from kind to cash.

- An increase of 0.3 mmbbl in Ecuador due to higher average oil prices.

- Such increase was partially offset by lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl.

(b) The extensions and discoveries are primarily due to various fields in the Llanos Basin in Colombia and the Jandaya field extension in the Perico Block in Ecuador.

(c) For the year ended December 31, 2024, the Group’s oil and condensate proved reserves were revised upwards by 6.7 mmbbl. The primary factors leading to the above were:

- An increase of 5.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells.

- An increase of 3.2 mmbbl in Colombia due to a change in a previously adopted development plan.

- Such increase was partially offset by lower average oil prices by 1.2 mmbbl in Colombia.

- A decrease of 0.6 mmbbl in Ecuador due to unsuccessful activities.

- A decrease of 0.2 mmbbl in Ecuador due to lower-than-expected performance from the existing wells

(d) The extensions and discoveries are primarily due to the Perico new field in the CPO-5 Block and the Toritos Sur new field in the Llanos 123 Block, both in Colombia.

(e) The disposal of minerals in Chile is due to the divestment of the Chilean business, which closed in January 2024 (see Note 35.7).

(f) For the year ended December 31, 2025, the Group’s oil and condensate proved reserves were revised upwards by 2.4 mmbbl. The primary factors leading to the above were:

- An increase of 2.7 mmbbl in Colombia due to higher-than-expected performance from the existing wells.

- An increase of 1.0 mmbbl in Colombia due to a change in a previously adopted development plan.

- Such increase was partially offset by lower average oil prices by 1.3 mmbbl in Colombia.

(g) The extensions and discoveries are primarily due to the Currucutu new field in the Llanos 123 Block.

(h) Purchase of Minerals in place refers to the Loma Jarillosa Este Block in the Argentina’s Vaca Muerta formation acquired in 2025 (see Note 34.1). The disposals refer to the Manati gas field in Brazil (see Note 34.2), the Perico Block in Ecuador (see Note 34.3) and the Llanos 32 Block in Colombia (see Note 34.4) that were divested in 2025.

Net proved reserves (developed and undeveloped) of natural gas:

Millions of cubic feet	Colombia	Argentina	Brazil	Chile	Total
Reserves as of December 31, 2022	1,065	—	9,443	14,103	24,611
Increase (decrease) attributable to:
Revisions (a)	219	—	1,659	(9)	1,869
Production	(209)	—	(2,214)	(3,283)	(5,706)
Reserves as of December 31, 2023	1,075	—	8,888	10,811	20,774
Increase (decrease) attributable to:
Revisions (b)	59	—	(2,291)	—	(2,232)
Disposal of Minerals in place (c)	—	—	—	(10,678)	(10,678)
Production	(250)	—	(481)	(133)	(864)
Reserves as of December 31, 2024	884	—	6,116	—	7,000
Increase (decrease) attributable to:
Purchase or (Disposal) of Minerals in place (d)	(828)	2,597	(4,992)	—	(3,223)
Production	(56)	(53)	(1,124)	—	(1,233)
Reserves as of December 31, 2025	—	2,544	—	—	2,544

(a) For the year ended December 31, 2023, the Group’s proved natural gas reserves were revised upwards by 1.9 billion cubic feet. This was the effect of higher-than-expected performance from the existing wells in the Manati field in Brazil (1.7 billion cubic feet) and the Llanos 32 Block in Colombia (0.2 billion cubic feet).

(b) For the year ended December 31, 2024, the Group’s proved natural gas reserves were revised downwards by 2.2 billion cubic feet. This was the effect of lower-than-expected performance from the existing wells in the Manati field in Brazil (2.3 billion cubic feet), partially offset by higher-than-expected performance from the existing wells in the Llanos 32 Block in Colombia (0.1 billion cubic feet).

(c) The disposal of minerals in Chile is due to the divestment of Chilean business, which closed in January 2024 (see Note 35.3).

(d) Purchase of Minerals in place refers to the Loma Jarillosa Este Block in the Argentina’s Vaca Muerta formation acquired in 2025 (see Note 34.1). The disposals refer to the Manati gas field in Brazil (see Note 34.2) and the Llanos 32 Block in Colombia (see Note 34.4) that were divested in 2025.

Revisions refer to changes in interpretation of discovered accumulations and some technical and logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases.

Table 6 - Standardized measure of discounted future net cash flows related to proved oil and gas reserves

The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future net cash flows were estimated using the average first day-of-the-month price during the 12-month period for 2025, 2024 and 2023 and using a 10% annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the

Group. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have interests, as of the date this supplementary information was filed.

This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons.

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
As of December 31, 2025
Future cash inflows	2,644,803	638,021	—	—	—	3,282,824
Future production costs	(1,371,337)	(249,495)	—	—	—	(1,620,832)
Future development costs	(173,253)	(147,674)	—	—	—	(320,927)
Future income taxes	(318,394)	(48,333)	—	—	—	(366,727)
Undiscounted future net cash flows	781,819	192,519	—	—	—	974,338
10% annual discount	(204,268)	(107,211)	—	—	—	(311,479)
Standardized measure of discounted future net cash flows	577,551	85,308	—	—	—	662,859
As of December 31, 2024
Future cash inflows	3,636,275	—	50,881	60,366	—	3,747,522
Future production costs	(1,658,050)	—	(32,028)	(30,319)	—	(1,720,397)
Future development costs	(145,645)	—	(15,228)	(8,775)	—	(169,648)
Future income taxes	(525,755)	—	(1,437)	—	—	(527,192)
Undiscounted future net cash flows	1,306,825	—	2,188	21,272	—	1,330,285
10% annual discount	(414,437)	—	3,462	(2,575)	—	(413,550)
Standardized measure of discounted future net cash flows	892,388	—	5,650	18,697	—	916,735
As of December 31, 2023
Future cash inflows	4,027,686	—	75,757	140,607	111,384	4,355,434
Future production costs	(1,633,889)	—	(22,815)	(45,052)	(50,343)	(1,752,099)
Future development costs	(147,045)	—	(1,204)	(13,768)	(41,359)	(203,376)
Future income taxes	(764,309)	—	(4,036)	(27,648)	—	(795,993)
Undiscounted future net cash flows	1,482,443	—	47,702	54,139	19,682	1,603,966
10% annual discount	(430,250)	—	(6,476)	(11,436)	5,205	(442,957)
Standardized measure of discounted future net cash flows	1,052,193	—	41,226	42,703	24,887	1,161,009

Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves

Amounts in US$‘000	Colombia	Argentina	Brazil	Ecuador	Chile	Total
Present value as of December 31, 2022	1,381,801	—	22,911	15,658	64,285	1,484,655
Sales of hydrocarbon, net of production costs	(491,525)	—	(8,143)	(6,673)	(6,362)	(512,703)
Net changes in sales price and production costs	(596,668)	—	21,490	(2,893)	(33,595)	(611,666)
Changes in estimated future development costs	9,461	—	(4,440)	(17,908)	5,142	(7,745)
Extensions and discoveries less related costs	72,757	—	—	63,619	—	136,376
Development costs incurred	115,996	—	—	500	7	116,503
Revisions of previous quantity estimates	104,256	—	9,159	10,642	(11,019)	113,038
Net changes in income taxes	198,769	—	(2,218)	(21,808)	—	174,743
Accretion of discount	257,346	—	2,467	1,566	6,429	267,808
Present value as of December 31, 2023	1,052,193	—	41,226	42,703	24,887	1,161,009
Sales of hydrocarbon, net of production costs	(469,989)	—	2,103	(18,561)	39	(486,408)
Net changes in sales price and production costs	(210,958)	—	(65,632)	(15,290)	—	(291,880)
Changes in estimated future development costs	(167,126)	—	41,782	(5,267)	—	(130,611)
Extensions and discoveries less related costs	11,586	—	—	—	—	11,586
Development costs incurred	132,094	—	401	10,293	—	142,788
Revisions of previous quantity estimates	179,475	—	(18,533)	(24,024)	—	136,918
Disposal of Minerals in place	—	—	—	—	(24,926)	(24,926)
Net changes in income taxes	183,463	—	(223)	21,808	—	205,048
Accretion of discount	181,650	—	4,526	7,035	—	193,211
Present value as of December 31, 2024	892,388	—	5,650	18,697	—	916,735
Sales of hydrocarbon, net of production costs	(319,063)	(806)	—	—	—	(319,869)
Net changes in sales price and production costs	(342,480)	—	—	—	—	(342,480)
Changes in estimated future development costs	24,700	—	—	—	—	24,700
Extensions and discoveries less related costs	456	—	—	—	—	456
Development costs incurred	44,596	1,432	—	—	—	46,028
Revisions of previous quantity estimates	46,621	—	—	—	—	46,621
Purchase or (Disposal) of Minerals in place	(35,296)	84,682	(5,650)	(18,697)	—	25,039
Net changes in income taxes	123,815	—	—	—	—	123,815
Accretion of discount	141,814	—	—	—	—	141,814
Present value as of December 31, 2025	577,551	85,308	—	—	—	662,859