Supplemental information on oil and gas activities

12 Months Ended

Dec. 31, 2023

Supplemental information on oil and gas activities

Supplemental information on oil and gas activities

Note 38     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, 2023, 2022 and 2021. 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	Ecuador	Brazil	Chile	Argentina	Total
Year ended December 31, 2023
Acquisition of properties
Proved	—	—	—	—	—	—
Unproved	—	—	—	—	—	—
Total property acquisition	—	—	—	—	—	—
Exploration	66,953	13,331	107	56	1,481	81,928
Development (a)	125,997	372	255	(564)	—	126,060
Total costs incurred	192,950	13,703	362	(508)	1,481	207,988

Amounts in US$‘000	Colombia	Ecuador	Brazil	Chile	Argentina	Total
Year ended December 31, 2022
Acquisition of properties
Proved	—	—	—	—	—	—
Unproved	—	—	—	—	—	—
Total property acquisition	—	—	—	—	—	—
Exploration	48,771	26,521	—	116	779	76,187
Development (a)	89,231	648	(212)	9,952	—	99,619
Total costs incurred	138,002	27,169	(212)	10,068	779	175,806

Amounts in US$‘000	Colombia	Brazil	Chile	Argentina	Total
Year ended December 31, 2021
Acquisition of properties
Proved	—	—	—	—	—
Unproved	—	—	—	—	—
Total property acquisition	—	—	—	—	—
Exploration	40,828	3	3,940	998	45,769
Development (a)	81,310	(2,212)	1,900	2	81,000
Total costs incurred	122,138	(2,209)	5,840	1,000	126,769

(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, 2023, 2022 and 2021, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

Amounts in US$‘000	Colombia	Ecuador	Brazil	Chile (b)	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	31,149	48,448	330,024	1,250,684
Other uncompleted projects	15,770	—	11	—	15,781
Unproved properties	69,823	10,426	330	—	80,579
Gross capitalized costs	1,092,322	41,575	52,910	404,515	1,591,322
Accumulated depreciation	(447,716)	(8,522)	(47,388)	(379,448)	(883,074)
Total net capitalized costs	644,606	33,053	5,522	25,067	708,248

(a) Includes capitalized amounts related to asset retirement obligations and impairment loss recognized in Chile for US$ 13,332,000.

(b) Classified as ‘Assets held for sale’ as of December 31, 2023, due to the divestment process closed in January 2024. See Note 36.1.

Amounts in US$‘000	Colombia	Ecuador	Brazil	Chile	Total
As of December 31, 2022
Proved properties (a)
Equipment, camps and other facilities	144,672	—	3,565	74,490	222,727
Mineral interest and wells	672,424	18,191	44,716	343,926	1,079,257
Other uncompleted projects	16,099	—	268	113	16,480
Unproved properties	102,760	9,991	290	—	113,041
Gross capitalized costs	935,955	28,182	48,839	418,529	1,431,505
Accumulated depreciation	(354,981)	(2,316)	(42,885)	(371,171)	(771,353)
Total net capitalized costs	580,974	25,866	5,954	47,358	660,152

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

Amounts in US$‘000	Colombia	Brazil	Chile	Argentina	Total
As of December 31, 2021
Proved properties (a)
Equipment, camps and other facilities	125,078	3,333	72,766	—	201,177
Mineral interest and wells	580,931	42,008	334,993	—	957,932
Other uncompleted projects	26,136	250	818	—	27,204
Unproved properties (b)	94,419	271	—	—	94,690
Gross capitalized costs	826,564	45,862	408,577	—	1,281,003
Accumulated depreciation	(282,616)	(38,741)	(358,417)	—	(679,774)
Total net capitalized costs	543,948	7,121	50,160	—	601,229

(b) Includes capitalized amounts related to asset retirement obligations, impairment loss recognized in Chile for US$ 17,641,000 and impairment loss reversed in Argentina for US$ 13,307,000.

(a) Do not include Ecuador capitalized costs.

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, 2023, 2022 and 2021. Income tax for the years presented was calculated utilizing the statutory tax rates.

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

Amounts in US$‘000	Colombia	Ecuador	Brazil	Chile	Argentina	Total
Year ended December 31, 2022
Revenue	978,423	10,671	19,873	29,196	1,962	1,040,125
Production costs, excluding depreciation
Operating costs	(78,323)	(3,220)	(3,753)	(12,961)	(1,306)	(99,563)
Royalties and economic rights in cash	(249,303)	—	(1,546)	(1,165)	(273)	(252,287)
Total production costs	(327,626)	(3,220)	(5,299)	(14,126)	(1,579)	(351,850)
Exploration expenses	(28,424)	(4,768)	—	(116)	(779)	(34,087)
Accretion expense (a)	(621)	—	(504)	(1,516)	—	(2,641)
Depreciation, depletion and amortization	(72,386)	(2,315)	(1,509)	(12,754)	—	(88,964)
Results of operations before income tax	549,366	368	12,561	684	(396)	562,583
Income tax expense	(192,278)	(92)	(4,271)	(103)	—	(196,744)
Results of oil and gas operations	357,088	276	8,290	581	(396)	365,839

Amounts in US$‘000	Colombia	Brazil	Chile	Argentina	Total
Year ended December 31, 2021
Revenue	618,268	20,109	21,471	28,695	688,543
Production costs, excluding depreciation
Operating costs	(72,043)	(2,954)	(10,280)	(14,490)	(99,767)
Royalties and economic rights in cash	(106,341)	(1,642)	(770)	(4,270)	(113,023)
Total production costs	(178,384)	(4,596)	(11,050)	(18,760)	(212,790)
Exploration expenses	(11,276)	—	(4,509)	(998)	(16,783)
Accretion expense (a)	(576)	(535)	(1,319)	(710)	(3,140)
Impairment loss for non-financial assets	—	—	(17,641)	13,307	(4,334)
Depreciation, depletion and amortization	(54,588)	(2,933)	(12,806)	(8,152)	(78,479)
Results of operations before income tax	373,444	12,045	(25,854)	13,382	373,017
Income tax (expense) benefit	(115,768)	(4,095)	3,878	(4,684)	(120,669)
Results of oil and gas operations	257,676	7,950	(21,976)	8,698	252,348

(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, 2023, 2022, 2021 and 2020 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, 2023, 2022, 2021 and 2020 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	As of December 31, 2023		As of December 31, 2022		As of December 31, 2021		As of December 31, 2020
	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)	43,120	1,075	46,623	1,065	47,766	1,207	43,817	1,695
Ecuador (b)	1,017	—	322	—	—	—	—	—
Brazil (c)	28	8,888	8	9,443	43	13,601	34	13,927
Chile (d)	619	9,956	1,115	14,103	755	15,196	798	19,054
Argentina (e)	—	—	—	—	1,186	3,379	1,685	5,599
Total consolidated	44,784	19,919	48,068	24,611	49,750	33,383	46,334	40,275
Net proved undeveloped
Colombia (f)	16,225	—	17,765	—	31,019	—	45,240	—
Ecuador (b)	1,278	—	—	—	—	—	—	—
Chile (d)	479	855	476	—	575	1,563	1,229	5,661
Argentina (g)	—	—	—	—	603	—	104	—
Total consolidated	17,982	855	18,241	—	32,197	1,563	46,573	5,661
Total proved reserves	62,766	20,774	66,309	24,611	81,947	34,946	92,907	45,936

(a) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 94% and 6% (96% and 4% in 2022, 98% and 2% in 2021, and 97% and 3% in 2020) of the proved developed reserves, respectively.

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

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

(d) Fell Block accounts for 100% of the reserves.

(e) Aguada Baguales, Puesto Touquet and El Porvenir Blocks accounted for 45%, 21% and 33% in 2021 (50%, 26% and 24% in 2020) of the proved developed reserves, respectively.

(f) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 97% and 3% (95% and 5% in 2022, 97% and 3% in 2021, and 96% and 4% in 2020) of the proved undeveloped reserves, respectively.

(g) Aguada Baguales Block accounted for 100% of the proved undeveloped reserves.

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	Ecuador	Brazil	Chile	Argentina	Total
Reserves as of December 31, 2020	89,057	—	34	2,027	1,789	92,907
Increase (decrease) attributable to:
Revisions (a)	(3,207)	—	18	(597)	(169)	(3,955)
Extensions and discoveries (b)	3,375	—	—	—	603	3,978
Production	(10,440)	—	(9)	(100)	(434)	(10,983)
Reserves as of December 31, 2021	78,785	—	43	1,330	1,789	81,947
Increase (decrease) attributable to:
Revisions (c)	(2,677)	—	(27)	422	—	(2,282)
Extensions and discoveries (d)	204	632	—	—	—	836
Disposal of Minerals in place (e)	—	—	—	—	(1,760)	(1,760)
Production	(11,924)	(310)	(8)	(161)	(29)	(12,432)
Reserves as of December 31, 2022	64,388	322	8	1,591	—	66,309
Increase (decrease) attributable to:
Revisions (f)	3,617	324	26	(412)	—	3,555
Extensions and discoveries (g)	2,549	1,937	—	—	—	4,486
Production	(11,209)	(288)	(6)	(81)	—	(11,584)
Reserves as of December 31, 2023	59,345	2,295	28	1,098	—	62,766

(a) For the year ended December 31, 2021, the Group’s oil and condensate proved reserves were revised downward by 4.0 mmbbl. The primary factors leading to the above were:

- Lower than expected performance from the existing wells that reduced the proved developed reserves in Colombia (8.9 mmbbl), in Argentina (0.3 mmbbl), and in Chile (0.3 mmbbl).

- A decrease of 0.6 mmbbl in Chile due to a change in a previously adopted development plan in the Fell Block.

- Such decrease was partially offset by a higher average oil prices resulted in a 5.7 mmbbl, 0.1 mmbbl and 0.3 mmbbl increase in reserves from the blocks in Colombia, Argentina and Chile, respectively.

(b) In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Argentina are due to the Aguada Baguales Field.

(c) For the year ended December 31, 2022, the Group’s oil and condensate proved reserves were revised downward by 2.3 mmbbl. The primary factors leading to the above were:

- A decrease of 3.6 mmbbl in Colombia due to a change in the royalties payment in certain fields from cash to kind.

- Such decrease was partially offset by a higher average oil prices resulted in a 0.6 mmbbl and 0.1 mmbbl increase in reserves from the blocks in Colombia and Chile, respectively.

- Higher than expected performance from the existing wells that increase the proved reserves in Colombia (0.3 mmbbl) and in Chile (0.3 mmbbl).

(d) In Colombia, the extensions and discoveries are primary due to the Cante Flamenco new field in CPO-5 Block and in Ecuador are due to the Jandaya, Yin and Tui new fields in the Perico Block and the Pashuri field in the Espejo Block.

(e) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3).

(f) 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.

(g) 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.

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

Millions of cubic feet	Colombia	Brazil	Chile	Argentina	Total
Reserves as of December 31, 2020	1,695	13,927	24,715	5,599	45,936
Increase (decrease) attributable to:
Revisions (a)	14	3,470	(3,553)	(636)	(705)
Production	(502)	(3,796)	(4,403)	(1,584)	(10,285)
Reserves as of December 31, 2021	1,207	13,601	16,759	3,379	34,946
Increase (decrease) attributable to:
Revisions (b)	141	(886)	1,501	—	756
Disposal of Minerals in place (c)	—	—	—	(3,227)	(3,227)
Production	(283)	(3,272)	(4,157)	(152)	(7,864)
Reserves as of December 31, 2022	1,065	9,443	14,103	—	24,611
Increase (decrease) attributable to:
Revisions (d)	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

(a) For the year ended December 31, 2021, the Group’s proved natural gas reserves were revised downward by 0.7 billion cubic feet. This was the combined effect of:

- A decrease of proved developed reserves due to lower performance of existing wells in Argentina (1.6 billion cubic feet) and in Chile (2.7 billion cubic feet) partially offset by better-than-expected performance in the Manati Field in Brazil (2.5 billion cubic feet).

- A decrease of 3.4 billion cubic feet in Chile due to the revision of the type well associated with the incremental activity that reduced the proved undeveloped reserves.

- A decrease of 1.5 billion cubic feet in Chile due to a change in a previously adopted development plan in the Fell Block.

-Such decrease was partially offset by higher average prices which resulted in an increase of 4.0 billion cubic feet, 1 billion cubic feet and 1 billion cubic feet in Chile, Brazil, and Argentina, respectively.

(b) For the year ended December 31, 2022, the Group’s proved natural gas reserves were revised upwards by 0.8 billion cubic feet. This was the combined effect of:

- An increase of proved reserves due to better performance of existing wells in Chile (0.8 billion cubic feet) and the Llanos 32 block in Colombia (0.1 billion cubic feet).

- Higher average prices resulted in an increase of 0.7 billion cubic feet and 0.8 billion cubic feet increase in gas reserves in Chile and Brazil, respectively.

- The above was partially offset by lower-than-expected performance of Manati Field in Brazil (1.6 billion cubic feet).

(c) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3).

(d) 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 Block in Brazil (1.7 billion cubic feet) and the Llanos 32 Block in Colombia (0.2 billion cubic feet).

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 2023, 2022 and 2021 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	Ecuador	Brazil	Chile	Argentina	Total
As of December 31, 2023
Future cash inflows	4,027,686	140,607	75,757	111,384	—	4,355,434
Future production costs	(1,633,889)	(45,052)	(22,815)	(50,343)	—	(1,752,099)
Future development costs	(147,045)	(13,768)	(1,204)	(41,359)	—	(203,376)
Future income taxes	(764,309)	(27,648)	(4,036)	—	—	(795,993)
Undiscounted future net cash flows	1,482,443	54,139	47,702	19,682	—	1,603,966
10% annual discount	(430,250)	(11,436)	(6,476)	5,205	—	(442,957)
Standardized measure of discounted future net cash flows	1,052,193	42,703	41,226	24,887	—	1,161,009
As of December 31, 2022
Future cash inflows	5,229,599	26,553	65,002	190,449	—	5,511,603
Future production costs	(1,633,818)	(8,094)	(29,519)	(72,411)	—	(1,743,842)
Future development costs	(182,701)	(297)	(1,955)	(40,659)	—	(225,612)
Future income taxes	(1,191,658)	—	(1,761)	—	—	(1,193,419)
Undiscounted future net cash flows	2,221,422	18,162	31,767	77,379	—	2,348,730
10% annual discount	(839,621)	(2,504)	(8,856)	(13,094)	—	(864,075)
Standardized measure of discounted future net cash flows	1,381,801	15,658	22,911	64,285	—	1,484,655
As of December 31, 2021
Future cash inflows	4,381,191	—	89,208	136,152	109,678	4,716,229
Future production costs	(1,715,554)	—	(34,930)	(69,067)	(61,660)	(1,881,211)
Future development costs	(197,461)	—	(1,955)	(40,339)	(49,200)	(288,955)
Future income taxes	(754,205)	—	(3,449)	—	(2,947)	(760,601)
Undiscounted future net cash flows	1,713,971	—	48,874	26,746	(4,129)	1,785,462
10% annual discount	(496,150)	—	(7,171)	6,121	4,471	(492,729)
Standardized measure of discounted future net cash flows	1,217,821	—	41,703	32,867	342	1,292,733

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

Amounts in US$‘000	Colombia	Ecuador	Brazil	Chile	Argentina	Total
Present value as of December 31, 2020	759,233	—	25,378	17,032	(19)	801,624
Sales of hydrocarbon, net of production costs	(516,844)	—	(15,677)	(11,520)	(16,855)	(560,896)
Net changes in sales price and production costs	924,875	—	19,393	64,048	(3,145)	1,005,171
Changes in estimated future development costs	96,364	—	861	(18,731)	20,674	99,168
Extensions and discoveries less related costs	80,933	—	—	—	(1,020)	79,913
Development costs incurred	87,877	—	—	4,111	—	91,988
Revisions of previous quantity estimates	(76,850)	—	11,957	(23,776)	465	(88,204)
Net changes in income taxes	(254,618)	—	(2,780)	—	244	(257,154)
Accretion of discount	116,851	—	2,571	1,703	(2)	121,123
Present value as of December 31, 2021	1,217,821	—	41,703	32,867	342	1,292,733
Sales of hydrocarbon, net of production costs	(891,534)	(2,732)	(14,697)	(15,317)	—	(924,280)
Net changes in sales price and production costs	956,926	—	(6,909)	39,457	—	989,474
Changes in estimated future development costs	93,657	(10,483)	(933)	(22,675)	—	59,566
Extensions and discoveries less related costs	6,754	28,873	—	—	—	35,627
Development costs incurred	94,195	—	—	11,153	—	105,348
Revisions of previous quantity estimates	(87,851)	—	(2,441)	15,513	—	(74,779)
Disposal of Minerals in place	—	—	—	—	(342)	(342)
Net changes in income taxes	(205,370)	—	1,673	—	—	(203,697)
Accretion of discount	197,203	—	4,515	3,287	—	205,005
Present value as of December 31, 2022	1,381,801	15,658	22,911	64,285	—	1,484,655
Sales of hydrocarbon, net of production costs	(491,525)	(6,673)	(8,143)	(6,362)	—	(512,703)
Net changes in sales price and production costs	(596,668)	(2,893)	21,490	(33,595)	—	(611,666)
Changes in estimated future development costs	9,461	(17,908)	(4,440)	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	10,642	9,159	(11,019)	—	113,038
Net changes in income taxes	198,769	(21,808)	(2,218)	—	—	174,743
Accretion of discount	257,346	1,566	2,467	6,429	—	267,808
Present value as of December 31, 2023	1,052,193	42,703	41,226	24,887	—	1,161,009