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.

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2021, 2020 and 2019. 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.

(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, 2021, 2020 and 2019, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.


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

(a)	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.

(b)	Do not include Ecuador capitalized costs.


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Total
As of December 31, 2020
Proved properties ^(a)
Equipment, camps and other facilities	115,577	74,363	3,580	4,309	197,829
Mineral interest and wells	511,040	348,366	47,729	61,482	968,617
Other uncompleted projects ^(b)	13,048	2,158	245	26	15,477
Unproved properties ^(c)	77,388	—	432	—	77,820
Gross capitalized costs	717,053	424,887	51,986	65,817	1,259,743
Accumulated depreciation	(228,929)	(345,611)	(38,273)	(45,619)	(658,432)
Total net capitalized costs	488,124	79,276	13,713	20,198	601,311

(a)	Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile, Argentina and Brazil for US$ 81,967,000, US$ 16,205,000 and US$ 1,717,000, respectively.

(b)	Do not include Peru capitalized costs.

(c)	Do not include Ecuador capitalized costs.


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Total
As of December 31, 2019
Proved properties ^(a)
Equipment, camps and other facilities	79,999	84,069	4,615	3,824	172,507
Mineral interest and wells	282,973	402,392	64,179	81,393	830,937
Other uncompleted projects (b)	19,754	11,984	209	765	32,712
Unproved properties	567	45,681	1,788	—	48,036
Gross capitalized costs	383,293	544,126	70,791	85,982	1,084,192
Accumulated depreciation	(172,207)	(313,379)	(46,370)	(30,897)	(562,853)
Total net capitalized costs	211,086	230,747	24,421	55,085	521,339

(a)	Includes capitalized amounts related to asset retirement obligations, impairment loss in Argentina for US$ 7,559,000.

(b)	Do not include Peru 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, 2021, 2020 and 2019. Income tax for the years presented was calculated utilizing the statutory tax rates.


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2021
Revenue	618,268	21,471	20,109	28,695	688,543
Production costs, excluding depreciation
Operating costs	(72,043)	(10,280)	(2,954)	(14,490)	(99,767)
Royalties	(106,341)	(770)	(1,642)	(4,270)	(113,023)
Total production costs	(178,384)	(11,050)	(4,596)	(18,760)	(212,790)
Exploration expenses ^(a)	(11,276)	(4,509)	—	(998)	(16,783)
Accretion expense ^(b)	(576)	(1,319)	(535)	(710)	(3,140)
Impairment loss for non-financial assets	—	(17,641)	—	13,307	(4,334)
Depreciation, depletion and amortization	(54,588)	(12,806)	(2,933)	(8,152)	(78,479)
Results of operations before income tax	373,444	(25,854)	12,045	13,382	373,017
Income tax (expense) benefit	(115,989)	3,878	(4,095)	(4,684)	(120,890)
Results of oil and gas operations	257,455	(21,976)	7,950	8,698	252,127


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2020
Revenue	334,606	21,704	12,783	24,599	393,692
Production costs, excluding depreciation
Operating costs	(61,866)	(9,491)	(2,827)	(15,013)	(89,197)
Royalties	(30,453)	(753)	(1,049)	(3,620)	(35,875)
Total production costs	(92,319)	(10,244)	(3,876)	(18,633)	(125,072)
Exploration expenses ^(a)	(12,493)	(50,301)	(1,000)	(694)	(64,488)
Accretion expense ^(b)	(670)	(1,358)	(867)	(1,381)	(4,276)
Impairment loss for non-financial assets	—	(81,967)	(1,717)	(16,205)	(99,889)
Depreciation, depletion and amortization	(56,720)	(32,233)	(2,488)	(14,723)	(106,164)
Results of operations before income tax	172,404	(154,399)	2,835	(27,037)	(6,197)
Income tax (expense) benefit	(55,169)	23,160	(964)	8,111	(24,862)
Results of oil and gas operations	117,235	(131,239)	1,871	(18,926)	(31,059)


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2019
Revenue	538,917	32,336	23,049	34,605	628,907
Production costs, excluding depreciation
Operating costs	(60,545)	(18,608)	(4,098)	(21,137)	(104,388)
Royalties	(56,399)	(1,181)	(1,855)	(5,141)	(64,576)
Total production costs	(116,944)	(19,789)	(5,953)	(26,278)	(168,964)
Exploration expenses ^(a)	(10,921)	(126)	(6,152)	(13,947)	(31,146)
Accretion expense ^(b)	(813)	(1,283)	(832)	(722)	(3,650)
Impairment loss for non-financial assets	—	—	—	(7,559)	(7,559)
Depreciation, depletion and amortization	(44,906)	(34,344)	(6,200)	(14,534)	(99,984)
Results of operations before income tax	365,333	(23,206)	3,912	(28,435)	317,604
Income tax (expense) benefit	(120,560)	3,481	(1,330)	8,531	(109,878)
Results of oil and gas operations	244,773	(19,725)	2,582	(19,904)	207,726

(a)	Do not include Peru and Ecuador costs.

(b)	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, 2021, 2020, 2019 and 2018 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton 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, 2021, 2020, 2019 and 2018 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):


	As of December 31, 2021		As of December 31, 2020		As of December 31, 2019		As of December 31, 2018
	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)	47,766	1,207	43,817	1,695	39,397	2,319	32,326	1,763
Chile ^(b)	755	15,196	798	19,054	898	14,406	696	11,944
Brazil ^(c)	43	13,601	34	13,927	48	14,872	55	17,339
Argentina ^(d)	1,186	3,379	1,685	5,599	1,658	5,785	2,058	6,207
Total consolidated	49,750	33,383	46,334	40,275	42,001	37,382	35,135	37,253

Net proved undeveloped
Colombia ^(e)	31,019	—	45,240	—	51,212	—	42,449	359
Chile ^(b)	575	1,563	1,229	5,661	2,809	6,413	2,622	8,823
Argentina ^(f)	603	—	104	—	1,370	450	1,440	3,174
Peru ^(g)	—	—	—	—	19,210	—	18,460	—
Total consolidated	32,197	1,563	46,573	5,661	74,601	6,863	64,971	12,356

Total proved reserves	81,947	34,946	92,907	45,936	116,602	44,245	100,106	49,609

(a)	Llanos 34 Block, CPO-5 Block, Llanos 32 Block and Platanillo Block account for 88%, 8%, 2% and 2% (Llanos 34 Block, CPO-5 Block, Llanos 32 Block and Platanillo Block account for 86%, 8%, 3% and 3% in 2020, Llanos 34

Block and Llanos 32 Block account for 97% and 3% in 2019, and Llanos 34 Block, La Cuerva Block, Yamu Block and Llanos 32 Block account for 96%, 1.5%, 1.5% and 1% in 2018) of the proved developed reserves, respectively.

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

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

(d)

Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 45%, 21% and 33% (Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 50%, 26% and 24% in 2020, 49%, 30% and 21% in 2019 and 48%, 33% and 19% in 2018) of the proved developed reserves, respectively.

(e)

Llanos 34 Block, Llanos 32 Block, CPO-5 Block and Platanillo Block account 88%, 5%, 5% and 3% (Llanos 34 Block, Llanos 32 Block and CPO-5 Block account 91%, 5% and 4% in 2020, Llanos 34 Block and Llanos 32 Block account 96% and 4% in 2019, and Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and 1% in 2018) of the proved undeveloped reserves, respectively.

(f)	Aguada Baguales Block accounts for 100% (Aguada Baguales Block accounts for 100% in 2020 and 2019, and Aguada Baguales Block and El Porvenir Block account for 75% and 25% in 2018) of the proved undeveloped reserves, respectively.

(g)	Morona Block accounted for 100% of the 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	Chile	Brazil	Argentina	Peru	Total
Reserves as of December 31, 2018	74,775	3,318	55	3,498	18,460	100,106
Increase (decrease) attributable to:
Revisions ^(a)	18,341	541	4	95	750	19,731
Extensions and discoveries ^(b)	8,071	36	—	—	—	8,107
Production	(10,578)	(188)	(11)	(565)	—	(11,342)
Reserves as of December 31, 2019	90,609	3,707	48	3,028	19,210	116,602
Increase (decrease) attributable to:
Revisions ^(c)	(1,964)	(1,825)	(7)	(734)	—	(4,530)
Extensions and discoveries ^(d)	4,545	279	—	—	—	4,824
Purchase or (Disposal) of Minerals in place ^(e)	6,853	—	—	—	(19,210)	(12,357)
Production	(10,986)	(134)	(7)	(505)	—	(11,632)
Reserves as of December 31, 2020	89,057	2,027	34	1,789	—	92,907
Increase (decrease) attributable to:
Revisions ^(f)	(3,207)	(597)	18	(169)	—	(3,955)
Extensions and discoveries ^(g)	3,375	—	—	603	—	3,978
Production	(10,440)	(100)	(9)	(434)	—	(10,983)
Reserves as of December 31, 2021	78,785	1,330	43	1,789	—	81,947

(a)	For the year ended December 31, 2019, the Group’s oil and condensate proved reserves were revised upward by 19.7 mmbbl. The primary factors leading to the above were:

- A technical revision of the expected results of future wells in the Jacana and Tigana Fields that led to an increase in reserves of 12.3 mmbbl.

- Better than expected performance from existing wells that increase the proved developed reserves, mostly originated in Colombia (6.3 mmbbl) from the Tigana and Jacana fields in the Llanos 34 Block. There were also minor increments in Argentina (0.4 mmbbl) originated in better performance of the Aguada Baguales Field wells; and in Chile (0.3 mmbbl) mostly in the Yagan Norte, Konawentru, Alakaluf and Yagan Fields.

- An updated geological model for the Situche Field in the Morona Block originated a new estimation of the proved original oil in place volumes that increased the proved undevelop reserves of the block by 0.7 mmbbl.

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

- There were also better well types considered for the Kiuaku, Loij and Konawentru Field that originated a minor increment of 0.2 mmbbl partially compensated by a reduction of 0.04 mmbbl in Argentina Challaco Field condensate due to an unsuccessful well.

^(b)	In Colombia, the extensions and discoveries are primary due to the Tigana and Jacana fields appraisal wells and the Guaco field discovery in the Llanos 34 Block and the Azogue field discovery in the Llanos 32 Block. In the Fell Block in Chile, the discovery of the Jauke field.

^{( c)}

For the year ended December 31, 2020, the Group’s oil and condensate proved reserves were revised downward by 4.5 mmbbl. The primary factors leading to the above were:

- Lower average oil prices resulted in a 4.2 mmbbl, 1.1 mmbbl and 0.3 mmbbl decrease in reserves from the blocks in Colombia, Argentina and Chile, respectively.

- A reduction of 1.6 mmbbl in Chile due to the revision of the type well in the Kiaku and Loij fields and a reduction in Argentina of 0.2 mmbbl, associated to the revision of the type of well in the Aguada Baguales fields.

- Lower than expected performance from the existing wells in Colombia that reduced the proved developed reserves from the Jacana, Tigana and Tigui fields (2.8 mmbbl).

- Such decrease was partially offset by a better performance of proved undeveloped reserves in Colombia (5.1 mmbbl) originated by a new estimation of original oil in place and better type wells considered in the Jacana and Tigana fields. In addition, the proved developed reserves increased in the Aguada Baguales Block in Argentina (0.5 mmbbl) and the Konawentru and Guanaco Fields in Chile of 0.1 mmbbl due to better performance of the existing wells.

(d) In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Chile are due to the Jauke Field discovery in the Fell Block.

(e) Purchase of Minerals in place refers to the CPO-5 and Platanillo Blocks acquisition during 2020 in Colombia. The reduction in Peru is due to the decision to retire from the Morona Block (see Note 36.4.1).

(f) 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.

(g) 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.

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


Millions of cubic feet	Colombia	Chile	Brazil	Argentina	Total
Reserves as of December 31, 2018	2,122	20,767	17,339	9,381	49,609
Increase (decrease) attributable to:
Revisions ^(a)	621	(167)	1,812	(1,791)	475
Extensions and discoveries ^(b)	295	5,386	—	—	5,681
Production	(719)	(5,167)	(4,279)	(1,355)	(11,520)
Reserves as of December 31, 2019	2,319	20,819	14,872	6,235	44,245
Increase (decrease) attributable to:
Revisions ^(c)	(211)	(385)	1,840	889	2,133
Extensions and discoveries ^(d)	—	10,456	—	—	10,456
Production	(413)	(6,175)	(2,785)	(1,525)	(10,898)
Reserves as of December 31, 2020	1,695	24,715	13,927	5,599	45,936
Increase (decrease) attributable to:
Revisions ^(e)	14	(3,553)	3,470	(636)	(705)
Production	(502)	(4,403)	(3,796)	(1,584)	(10,285)
Reserves as of December 31, 2021	1,207	16,759	13,601	3,379	34,946

(a)	For the year ended December 31, 2019, the Group’s proved natural gas reserves were revised upward by 0.5 billion cubic feet. This was the combined effect of:

- An increase of proved developed reserves due to better performance of existing wells in Chile (2.2 billion cubic feet) mostly associated to the Pampa Larga, Ache and Monte Aymond Fields; in Brazil (1.8 billion cubic feet) in the Manati Field; Colombia (0.6 billion cubic feet) due to a better performance of the Tigana and Jacana Fields; and Argentina (0.1 billion cubic feet) mostly associated to a better performance of wells in the Aguada Baguales Field.

- The above was partially offset by lower than expected performance for the proved undeveloped reserves in Chile (2.4 billion cubic feet) mostly associated to the increase of water production in Ache Field; and Argentina (1.3 billion cubic feet) associated to an unsuccessful well drilled in the Challaco Bajo Field.

- Lower average prices resulted in a decrease of 0.5 billion cubic feet reduction in gas proved developed reserves in Argentina.

(b)	The extensions and discoveries are primary due to the Jauke Field discovery in the Fell Block, in Chile, and the gas discovery of the Une Formation in the Azogue field in the Llanos 32 Block, in Colombia.

(c)	For the year ended December 31, 2020, the Group’s proved natural gas reserves were revised upwards by 2.1 billion cubic feet. This was the combined effect of:

- An increase of proved developed reserves due to better performance of existing wells in Chile (7.9 billion cubic feet) mostly associated to the Jauke and Ache Fields, in Brazil (3.0 billion cubic feet) associated to new gas sales plateau in 2021 and forward which leads to better than expected performance of the Manati Field and in Argentina (1.9 billion cubic feet) due to better performance of the Puesto Touquet and El Porvenir Blocks.

- The above was partially offset by lower than expected performance of proved undeveloped reserves in Chile (5.8 billion cubic feet) due to revisions of the type of well in the Pampa Larga Field.

- Lower average prices resulted in a decrease of 2.5 billion cubic feet, 1.2 billion cubic feet and 1.2 billion cubic feet reduction in gas reserves in Chile, Brazil and Argentina, respectively.

(d)	The extensions and discoveries are primary due to the Jauke Field discovery in the Fell Block, in Chile.

(e)	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.

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 2021, 2020 and 2019 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	Chile	Brazil	Argentina	Peru	Total
As of December 31, 2021
Future cash inflows	4,381,191	136,152	89,208	109,678	—	4,716,229
Future production costs	(1,715,554)	(69,067)	(34,930)	(61,660)	—	(1,881,211)
Future development costs	(197,461)	(40,339)	(1,955)	(49,200)	—	(288,955)
Future income taxes	(754,205)	—	(3,449)	(2,947)	—	(760,601)
Undiscounted future net cash flows	1,713,971	26,746	48,874	(4,129)	—	1,785,462
10% annual discount	(496,150)	6,121	(7,171)	4,471	—	(492,729)
Standardized measure of discounted future net cash flows	1,217,821	32,867	41,703	342	—	1,292,733
As of December 31, 2020
Future cash inflows	2,561,947	130,200	68,857	83,125	—	2,844,129
Future production costs	(850,029)	(82,290)	(36,254)	(65,536)	—	(1,034,109)
Future development costs	(197,859)	(28,620)	(2,355)	(24,640)	—	(253,474)
Future income taxes	(409,276)	—	(327)	—	—	(409,603)
Undiscounted future net cash flows	1,104,783	19,290	29,921	(7,051)	—	1,146,943
10% annual discount	(345,550)	(2,258)	(4,543)	7,032	—	(345,319)
Standardized measure of discounted future net cash flows	759,233	17,032	25,378	(19)	—	801,624
As of December 31, 2019
Future cash inflows	4,323,914	294,202	86,191	187,064	1,255,239	6,146,610
Future production costs	(1,159,621)	(104,688)	(32,608)	(118,797)	(512,607)	(1,928,321)
Future development costs	(276,804)	(35,420)	(2,166)	(49,595)	(278,388)	(642,373)
Future income taxes	(858,700)	(5,594)	(1,409)	(2,251)	(143,416)	(1,011,370)
Undiscounted future net cash flows	2,028,789	148,500	50,008	16,421	320,828	2,564,546
10% annual discount	(715,217)	(44,277)	(6,626)	(5,080)	(199,611)	(970,811)
Standardized measure of discounted future net cash flows	1,313,572	104,223	43,382	11,341	121,217	1,593,735

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


Amounts in US$‘000	Colombia	Chile	Brazil	Argentina	Peru	Total
Present value as of December 31, 2018	1,379,063	89,830	41,549	34,867	238,533	1,783,842
Sales of hydrocarbon, net of production costs	(411,528)	(14,284)	(17,289)	(13,280)	—	(456,381)
Net changes in sales price and production costs	(299,642)	12,799	6,923	(20,694)	(48,823)	(349,437)
Changes in estimated future development costs	(268,377)	(22,163)	1,165	573	(175,248)	(464,050)
Extensions and discoveries less related costs	182,857	17,300	—	—	—	200,157
Development costs incurred	69,694	4,023	445	4,325	—	78,487
Revisions of previous quantity estimates	415,349	9,508	5,482	(2,358)	11,992	439,973
Net changes in income taxes	23,398	(2,025)	729	3,760	51,917	77,779
Accretion of discount	222,758	9,235	4,378	4,148	42,846	283,365
Present value as of December 31, 2019	1,313,572	104,223	43,382	11,341	121,217	1,593,735
Sales of hydrocarbon, net of production costs	(221,620)	(12,803)	8,080	(10,454)	—	(236,797)
Net changes in sales price and production costs	(975,716)	(117,895)	(14,580)	(113)	—	(1,108,304)
Changes in estimated future development costs	514,317	20,870	(19,606)	(2,587)	—	512,994
Extensions and discoveries less related costs	59,898	13,914	—	—	—	73,812
Development costs incurred	69,694	10,743	394	445	—	81,276
Revisions of previous quantity estimates	(27,190)	(13,002)	3,519	(10)	—	(36,683)
Purchase or (Disposals) of Minerals in place	90,315	—	—	—	(121,217)	(30,902)
Net changes in income taxes	(281,264)	—	(290)	—	—	(281,554)
Accretion of discount	217,227	10,982	4,479	1,359	—	234,047
Present value as of December 31, 2020	759,233	17,032	25,378	(19)	—	801,624
Sales of hydrocarbon, net of production costs	(516,844)	(11,520)	(15,677)	(16,855)	—	(560,896)
Net changes in sales price and production costs	924,875	64,048	19,393	(3,145)	—	1,005,171
Changes in estimated future development costs	96,364	(18,731)	861	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)	(23,776)	11,957	465	—	(88,204)
Net changes in income taxes	(254,618)	—	(2,780)	244	—	(257,154)
Accretion of discount	116,851	1,703	2,571	(2)	—	121,123
Present value as of December 31, 2021	1,217,821	32,867	41,703	342	—	1,292,733