Supplemental information on oil and gas activities

12 Months Ended

Dec. 31, 2017

Disclosure of Supplemental information on oil and gas activities [Abstract]

Disclosure Of Supplemental Information On Oil And Gas Activities [Text Block]

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 31 December 2008. This information includes the Group’s oil and gas production activities carried out in Chile, Colombia, Brazil, Argentina and Peru.

Table 1 - Costs incurred in exploration, property acquisitions and development ^(a)

The following table presents those costs capitalised as well as expensed that were incurred during each of the years ended as of 31 December 2017, 2016 and 2015. 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	Chile		Colombia		Argentina		Brazil		Peru		Total
Year ended 31 December 2017
Acquisition of properties
Proved		-		-		-		-		-		-
Unproved		-		-		-		-		-		-
Total property acquisition		-		-		-		-		-		-
Exploration		3,283		37,017		8,080		5,207		743		54,330
Development		10,231		49,268		167		1,210		14,074		74,950
Total costs incurred		13,514		86,285		8,247		6,417		14,817		129,280

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Peru		Total
Year ended 31 December 2016
Acquisition of properties
Proved		-		-		-		-		-		-
Unproved		-		-		-		-		-		-
Total property acquisition
Exploration		5,519		15,233		1,894		2,555		-		25,201
Development		4,566		12,500		-		191		-		17,257
Total costs incurred		10,085		27,733		1,894		2,746		-		42,458

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Peru		Total
Year ended 31 December 2015
Acquisition of properties
Proved		-		-		-		-		-		-
Unproved		-		-		-		-		-		-
Total property acquisition
Exploration		3,598		14,845		1,103		2,562		-		22,108
Development		13,315		14,752		56		3,780		-		31,903
Total costs incurred		16,913		29,597		1,159		6,342		-		54,011

^(a)Includes capitalised amounts related to asset retirement obligations.

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

The following table presents the capitalised costs as at 31 December 2017, 2016 and 2015, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
At 31 December 2017
Proved properties (a)
Equipment, camps and other facilities		80,611		69,906		843		6,036		157,396
Mineral interest and wells		397,031		291,050		11,159		77,264		776,504
Other uncompleted projects (b)		12,508		11,290		48		70		23,916
Unproved properties		49,702		4,106		2,975		7,585		64,368
Gross capitalised costs		539,852		376,352		15,025		90,955		1,022,184
Accumulated depreciation		(253,764)		(228,793)		(5,700)		(39,509)		(527,766)
Total net capitalised costs		286,088		147,559		9,325		51,446		494,418

^(a) Includes capitalised amounts related to asset retirement obligations.

^(b) Do not include Peru capitalised costs.

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
At 31 December 2016
Proved properties (a)
Equipment, camps and other facilities		80,611		46,785		843		4,174		132,413
Mineral interest and wells		380,037		230,100		4,849		77,255		692,241
Other uncompleted projects		18,274		12,534		36		2,082		32,926
Unproved properties		48,908		4,503		1,894		6,468		61,773
Gross capitalised costs		527,830		293,922		7,622		89,979		919,353
Accumulated depreciation		(230,917)		(190,025)		(5,692)		(29,803)		(456,437)
Total net capitalised costs		296,913		103,897		1,930		60,176		462,916

^(a) Includes capitalised amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$  5,664,000.

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
At 31 December 2015
Proved properties (a)
Equipment, camps and other facilities		79,040		42,852		843		2,097		124,832
Mineral interest and wells		367,722		213,480		4,849		62,941		648,992
Other uncompleted projects		21,830		7,703		290		-		29,823
Unproved properties		70,062		8,180		-		8,758		87,000
Gross capitalised costs		538,654		272,215		5,982		73,796		890,647
Accumulated depreciation		(201,138)		(160,759)		(5,654)		(14,236)		(381,787)
Total net capitalised costs		337,516		111,456		328		59,560		508,860

^(a) Includes capitalised amounts related to asset retirement obligations and impairment loss in Chile and Colombia for US$  104,515,000 and US$  45,059,000, respectively.

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 31 December 2017, 2016 and 2015. Income tax for the years presented was calculated utilizing the statutory tax rates.

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
Year ended 31 December 2017
Revenue		32,738		263,076		70		34,238		330,122
Production costs, excluding depreciation
Operating costs		(19,685)		(42,677)		(325)		(7,603)		(70,290)
Royalties		(1,314)		(24,236)		(13)		(3,134)		(28,697)
Total production costs		(20,999)		(66,913)		(338)		(10,737)		(98,987)
Exploration expenses (a)		(1,404)		(3,856)		(707)		(3,985)		(9,952)
Accretion expense (b)		(994)		(683)		-		(930)		(2,607)
Impairment loss reversal for non-financial assets		-		-		-		-		-
Depreciation, depletion and amortization		(22,705)		(38,721)		(8)		(10,659)		(72,093)
Results of operations before income tax		(13,364)		152,903		(983)		7,927		146,483
Income tax benefit (expense)		2,005		(61,161)		344		(2,695)		(61,507)
Results of oil and gas operations		(11,359)		91,742		(639)		5,232		84,976

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
Year ended 31 December 2016
Revenue		36,723		126,228		-		29,719		192,670
Production costs, excluding depreciation
Operating costs		(20,674)		(29,326)		-		(5,738)		(55,738)
Royalties		(1,495)		(7,281)		-		(2,721)		(11,497)
Total production costs		(22,169)		(36,607)		-		(8,459)		(67,235)
Exploration expenses (a)		(21,060)		(11,690)		-		(5,636)		(38,386)
Accretion expense (b)		(897)		(459)		-		(1,198)		(2,554)
Impairment loss reversal for non-financial assets		-		5,664		-		-		5,664
Depreciation, depletion and amortization		(29,890)		(29,439)		-		(12,785)		(72,114)
Results of operations before income tax		(37,293)		53,697		-		1,641		18,045
Income tax benefit (expense)		5,594		(21,479)		-		(558)		(16,443)
Results of oil and gas operations		(31,699)		32,218		-		1,083		1,602

Amounts in US$ '000	Chile		Colombia		Argentina		Brazil		Total
Year ended 31 December 2015
Revenue		44,808		131,897		597		32,388		209,690
Production costs, excluding depreciation
Operating costs		(26,731)		(40,384)		(1,414)		(5,058)		(73,587)
Royalties		(1,973)		(8,150)		(34)		(2,998)		(13,155)
Total production costs		(28,704)		(48,534)		(1,448)		(8,056)		(86,742)
Exploration expenses (a)		(30,499)		(7,132)		(1,159)		(1,103)		(39,893)
Accretion expense (b)		(789)		(890)		-		(896)		(2,575)
Impairment loss for non-financial assets		(104,515)		(45,059)		-		-		(149,574)
Depreciation, depletion and amortization		(37,664)		(50,675)		(91)		(13,401)		(101,831)
Results of operations before income tax		(157,363)		(20,393)		(2,101)		8,932		(170,925)
Income tax benefit (expense)		23,604		7,953		735		(3,037)		29,255
Results of oil and gas operations		(133,759)		(12,440)		(1,366)		5,895		(141,670)

^(a) Do not include Peru costs.

^(b) Represents accretion of ARO liability.

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 31 December 2017, 2016 and 2015 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 accurately measured, and the reserve estimation depends on the quality of available information and the interpretation and judgment 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 31 December 2017, 2016 and 2015 are summarised as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	As of 31 December 2017				As of 31 December 2016				As of 31 December 2015
	Oil and  condensate  (Mbbl)		Natural gas (MMcf)		Oil and  condensate  (Mbbl)		Natural gas  (MMcf)		Oil and  condensate  (Mbbl)		Natural gas  (MMcf)
Net proved developed
Chile (a)		720.0		8,688.0		547.0		6,610.0		498.0		4,922.0
Colombia (b)		21,101.0		-		9,502.0		-		8,177.8		-
Brazil (c)		76.0		23,821.0		72.0		29,525.0		120.0		36,158.0
Peru (d)		9,502.0		-		9,316.0		-		-		-
Total consolidated		31,399.0		32,509.0		19,437.0		36,135.0		8,795.8		41,080.0
Net proved undeveloped
Chile (e)		3,423.0		11,329.0		6,052.0		29,690.0		5,455.8		31,593.0
Colombia (f)		44,398.0		-		27,838.0		-		22,245.5		-
Brazil (c)		-		-		-		-		-		-
Peru (d)		9,215.0		-		9,305.0		-		-		-
Total consolidated		57,036.0		11,329.0		43,195.0		29,690.0		27,701.3		31,593.0
Total proved reserves		88,435.0		43,838.0		62,632.0		65,825.0		36,497.1		72,673.0

^(a) Fell Block accounts for 98% of the reserves (99% in 2016 and 91% in 2015) (LGI owns a 20% interest) and Flamenco Block accounts for 2% (1% in 2016 and 9% in 2015) (LGI owns 31.2% interest).

^(b) Llanos 34 Block, Cuerva Block and Yamu Block account for 98%, 1% and 1% (Llanos 34 Block and Llanos 32 Block account for 99% and 1% in 2016, and Llanos 34 Block and Cuerva Block account for 94% and 3% in 2015) of the proved developed reserves, respectively (LGI owns a 20% interest).

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

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

^(e) Fell Block accounts for 97% of the reserves (99% in 2016 and 100% in 2015) (LGI owns a 20% interest), Flamenco Block accounts for 3% in 2017 (1% in 2016 and nil in 2015) (LGI owns 31.2% interest).

^(f) Llanos 34, Cuerva Block and Yamu Block account for 97%, 2% and 1% (Llanos 34 Block accounts for 100% in 2016 and Llanos 34 Block and Cuerva Block account for 95% and 4% in 2015) of the proved undeveloped reserves, respectively (LGI owns a 20% interest).

The amounts of proved reserves disclosed herein as of 31 December 2017 include 13,934.1 thousand barrels of crude oil and condensate (8,796.2 in 2016 and 7,281.3 in 2015) and 4,101.5 million cubic feet of natural gas (7,356.0 in 2016 and 7,345.8 in 2015) corresponding to non-controlling interest held by LGI.

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

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

Thousands of barrels	Chile		Colombia		Brazil		Peru		Total
Reserves as of 31 December 2014		6,441.9		24,735.3		130.0		-		31,307.2
Increase (decrease) attributable to:
Revisions (a)		119.0		(225.0)		7.6		-		(98.4)
Extensions and discoveries (b)		100.0		10,489.0		-		-		10,589.0
Production		(707.1)		(4,576.0)		(17.6)		-		(5,300.7)
Reserves as of 31 December 2015		5,953.8		30,423.3		120.0		-		36,497.1
Increase (decrease) attributable to:
Revisions (c)		1,148.0		5,779.0		(34.0)		-		6,893.0
Extensions and discoveries (d)		-		6,311.0		-		-		6,311.0
Purchase of Minerals in place (e)		-		-		-		18,621.0		18,621.0
Production		(502.8)		(5,173.3)		(14.0)		-		(5,690.1)
Reserves as of 31 December 2016		6,599.0		37,340.0		72.0		18,621.0		62,632.0
Increase (decrease) attributable to:
Revisions (f)		(2,109.0)		6,315.0		19.0		96.0		4,321.0
Extensions and discoveries (g)		-		29,047.0		-		-		29,047.0
Production		(347.0)		(7,203.0)		(15.0)		-		(7,565.0)
Reserves as of 31 December 2017		4,143.0		65,499.0		76.0		18,717.0		88,435.0

^(a) For the year ended 31 December 2015, the Group’s oil and condensate proved reserves were revised downwards by 0.1 mmbbl. The primary factors leading to the above were:

-     The impact of lower average oil prices resulting in a 2 mmbbl decrease in reserves from the La Cuerva and Yamu blocks in Colombia, and a 1 mmbbl decrease in reserves related to a change in a previously adopted development plan in the Fell Block in Chile.

-      Such decrease was partially offset by better than expected performance from existing wells, of which 2 mmbbl was from the Llanos 34 Block in Colombia and 1 mmbbl from the Fell Block in Chile.

^(b) In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca field discoveries in the Llanos 34 Block.

^(c) For the year ended 31 December 2016, the Group’s oil and condensate proved reserves were revised upward by 7 mmbbl. The primary factors leading to the above were:

-     Better than expected performance from existing wells, resulting in an increase of 9 mmbbl, of which 8 mmbbl was from the Tigana, Jacana and other minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in Chile.

-     Such increase was partially offset by lower average oil prices impacting the La Cuerva and Yamu blocks in Colombia, resulting in a 2 mmbbl decrease.

^(d) In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells in the Llanos 34 Block.

^(e) In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement dated 1 October 2014 and its amendments were closed on 1 December 2016 following the issuance of Supreme Decree 031-2016-MEM.XXX.

^(f) For the year ended 31 December 2017, the Group’s oil and condensate proved reserves were revised upward by 4.3 mmbbl. The primary factors leading to the above were:

-     Better than expected performance from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl.

-     The impact of higher average oil prices resulting in a 2.5 mmbbl and 0.4 mmbbl increase in reserves from the blocks in Colombia and Chile, respectively.

-     Such increase was partially offset by a decrease in reserves mainly related to a change in a previously adopted development plan in the Fell Block in Chile, resulting in a 2.4 mmbbl decrease.

^(g) In Colombia, the extensions and discoveries are primary due to the Chiricoca, Jacamar, and Curucucu field discoveries in the Llanos 34 Block and the Tigana and Jacana field extentions in the Llanos 34 Block.

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

Millions of cubic feet	Chile		Brazil		Total
Reserves as of 31 December 2014		33,970.0		40,464.0		74,434.0
Increase (decrease) attributable to:
Revisions (a)		(2,807.6)		2,907.0		99.4
Extensions and discoveries (b)		9,378.0		-		9,378.0
Production		(4,025.4)		(7,213.0)		(11,238.4)
Reserves as of 31 December 2015		36,515.0		36,158.0		72,673.0
Increase (decrease) attributable to:
Revisions (c)		5,078.0		(319.0)		4,759.0
Production		(5,293.0)		(6,314.0)		(11,607.0)
Reserves as of 31 December 2016		36,300.0		29,525.0		65,825.0
Increase (decrease) attributable to:
Revisions (d)		(13,725.0)		59.0		(13,666.0)
Extensions and discoveries (e)		1,187.0		-		1,187.0
Production		(3,745.0)		(5,763.0)		(9,508.0)
Reserves as of 31 December 2017		20,017.0		23,821.0		43,838.0

^(a) For the year ended 31 December 2015, the Group’s proved natural gas reserves were revised by 0.1 billion cubic feet. This was the combined effect of:

-     Better than expected performance from existing wells that resulted in an increase of 13 billion cubic feet (3 billion cubic feet from the Manati field in Brazil and 10 billion cubic feet from the Fell Block in Chile).

-     The above was partially offset by a decrease of 13 billion cubic feet due to lower average gas prices in the Fell and Tierra del Fuego (TdF) blocks in Chile (totalling 3 billion cubic feet) and changes in previously adopted development plan in the Fell Block in Chile (totalling 10 billion cubic feet).

^(b) In Chile, the extensions and discoveries are primary due to the Ache Field discovery and from the extension well in the Fell Block.

^(c) For the year ended 31 December 2016, the Group’s proved natural gas reserves were revised upwards by 5 billion cubic feet. This increase was mainly driven by better than expected performance from existing wells, primarily the Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic feet. This increase was partially offset by a reduction of 4 billion cubic feet in the Pampa Larga field, also in the Fell Block.

^(d) For the year ended 31 December 2017, the Group’s proved natural gas reserves were revised downwards by 13.7 billion cubic feet. This was the combined effect of:

-     Removal of proved undeveloped reserves due to changes in previously adopted development plan in the Fell Block in Chile and unsuccessful proved undeveloped executions in the Fell Block in Chile (totalling 21.3 billion cubic feet).

-     The above was partially offset by an increase of 6.8 billion cubic feet due to a better performance in the proved developed producing reserves in the Fell Block in Chile and the impact of higher average prices that resulted in an increase of 0.8 billion cubic feet.

^(e) In Chile, the extensions and discoveries are primary due to the Uaken Field discovery in the Fell Block.

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 2017, 2016 and 2015 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	Chile		Colombia		Brazil		Peru		Total
At 31 December 2017
Future cash inflows		284,711		2,434,954		157,527		1,047,540		3,924,732
Future production costs		(131,788)		(531,751)		(56,311)		(466,110)		(1,185,960)
Future development costs		(57,690)		(187,414)		(7,524)		(235,920)		(488,548)
Future income taxes		(656)		(558,226)		(10,442)		(107,294)		(676,618)
Undiscounted future net cash flows		94,577		1,157,563		83,250		238,216		1,573,606
10% annual discount		(19,338)		(343,561)		(13,293)		(147,682)		(523,874)
Standardized measure of discounted future net cash flows		75,239		814,002		69,957		90,534		1,049,732
At 31 December 2016
Future cash inflows		394,993		873,771		200,713		941,463		2,410,940
Future production costs		(186,700)		(229,593)		(74,116)		(497,187)		(987,596)
Future development costs		(149,785)		(69,996)		(16,352)		(234,328)		(470,461)
Future income taxes		(8,344)		(191,096)		(21,041)		(69,698)		(290,179)
Undiscounted future net cash flows		50,164		383,086		89,204		140,250		662,704
10% annual discount		(14,709)		(113,584)		(15,688)		(109,321)		(253,302)
Standardized measure of discounted future net cash flows		35,455		269,502		73,516		30,929		409,402
At 31 December 2015
Future cash inflows		403,199		1,032,339		221,206		-		1,656,744
Future production costs		(186,933)		(309,394)		(99,832)		-		(596,159)
Future development costs		(112,312)		(99,305)		(16,360)		-		(227,977)
Future income taxes		(17,904)		(195,957)		(16,837)		-		(230,698)
Undiscounted future net cash flows		86,050		427,683		88,177		-		601,910
10% annual discount		(17,895)		(127,586)		(15,861)		-		(161,342)
Standardized measure of discounted future net cash flows		68,155		300,097		72,316		-		440,568

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

Amounts in US$ '000	Chile		Colombia		Brazil		Peru		Total
Present value at 31 December 2014		227,658		584,071		112,145		-		923,874
Sales of hydrocarbon , net of production costs		(20,948)		(97,152)		(37,428)		-		(155,528)
Net changes in sales price and production costs		(256,828)		(547,379)		(27,404)		-		(831,611)
Changes in estimated future development costs		28,227		(20,123)		542		-		8,646
Extensions and discoveries less related costs		23,595		174,951		-		-		198,546
Development costs incurred		15,093		29,965		4,872		-		49,930
Revisions of previous quantity estimates		(5,463)		(14,528)		4,845		-		(15,146)
Net changes in income taxes		28,611		101,576		1,573		-		131,760
Accretion of discount		28,210		88,716		13,171		-		130,097
Present value at 31 December 2015		68,155		300,097		72,316		-		440,568
Sales of hydrocarbon , net of production costs		(15,127)		(91,163)		(20,945)		-		(127,235)
Net changes in sales price and production costs		(16,854)		(171,131)		16,366		-		(171,619)
Changes in estimated future development costs		(49,763)		14,941		542		-		(34,280)
Extensions and discoveries less related costs		-		76,641		-		-		76,641
Development costs incurred		9,417		17,302		2,214		-		28,933
Revisions of previous quantity estimates		22,765		70,180		(1,872)		-		91,073
Purchase of Minerals in place		-		-		-		30,929		30,929
Net changes in income taxes		8,256		3,030		(4,020)		-		7,266
Accretion of discount		8,606		49,605		8,915		-		67,126
Present value at 31 December 2016		35,455		269,502		73,516		30,929		409,402
Sales of hydrocarbon , net of production costs		(14,251)		(198,631)		(26,979)		-		(239,861)
Net changes in sales price and production costs		26,928		289,199		(3,000)		69,962		383,089
Changes in estimated future development costs		79,078		(124,053)		8,385		(9,725)		(46,315)
Extensions and discoveries less related costs		-		49,574		-		-		49,574
Development costs incurred		7,146		67,571		-		-		74,717
Revisions of previous quantity estimates		(69,594)		673,622		603		1,133		605,764
Purchase of Minerals in place
Net changes in income taxes		6,097		(258,842)		7,976		(11,828)		(256,597)
Accretion of discount		4,380		46,060		9,456		10,063		69,959
Present value at 31 December 2017		75,239		814,002		69,957		90,534		1,049,732

The amounts of the standardized measure of discounted future net cash flows herein for the year ended 31 December 2017, 2016 and 2015 include $178.1 million, $61.4 million and $73.9 million that correspond to the non-controlling interest held by LGI.