GeoPark Limited (GPRK) 20-F 12 Apr 18 2017 FY Annual report (foreign) Financial data

Document And Entity Information

Document And Entity Information	12 Months Ended
	Dec. 31, 2017shares
Document Information [Line Items]
Document Type	20-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	GeoPark Ltd
Entity Central Index Key	1,464,591
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Trading Symbol	GPRK
Entity Common Stock, Shares Outstanding	60,596,219

CONSOLIDATED STATEMENT OF INCOM

CONSOLIDATED STATEMENT OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
REVENUE	$ 330,122	$ 192,670	$ 209,690
Commodity risk management contracts	(15,448)	(2,554)	0
Production and operating costs	(98,987)	(67,235)	(86,742)
Geological and geophysical expenses	(7,694)	(10,282)	(13,831)
Administrative expenses	(42,054)	(34,170)	(37,471)
Selling expenses	(1,136)	(4,222)	(5,211)
Depreciation	(74,885)	(75,774)	(105,557)
Write-off of unsuccessful exploration efforts	(5,834)	(31,366)	(30,084)
Impairment loss reversed (recognised) for non-financial assets	0	5,664	(149,574)
Other expenses	(5,088)	(1,344)	(13,711)
OPERATING PROFIT (LOSS)	78,996	(28,613)	(232,491)
Financial expenses	(53,511)	(36,229)	(36,924)
Financial income	2,016	2,128	1,269
Foreign exchange (loss) gain	(2,193)	13,872	(33,474)
PROFIT (LOSS) BEFORE INCOME TAX	25,308	(48,842)	(301,620)
Income tax (expense) benefit	(43,145)	(11,804)	17,054
LOSS FOR THE YEAR	(17,837)	(60,646)	(284,566)
Attributable to:
Owners of the Company	(24,228)	(49,092)	(234,031)
Non-controlling interest	$ 6,391	$ (11,554)	$ (50,535)
Losses per share (in US$) for loss attributable to owners of the Company. Basic	$ (0.40)	$ (0.82)	$ (4.05)
Losses per share (in US$) for loss attributable to owners of the Company. Diluted	$ (0.40)	$ (0.82)	$ (4.05)

CONSOLIDATED STATEMENT OF COMPR

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of comprehensive income [abstract]
Loss for the year	$ (17,837)	$ (60,646)	$ (284,566)
Items that may be subsequently reclassified to profit or loss
Currency translation differences	(512)	7,102	(1,001)
Total comprehensive loss for the year	(18,349)	(53,544)	(285,567)
Attributable to:
Owners of the Company	(24,740)	(41,990)	(235,032)
Non-controlling interest	$ 6,391	$ (11,554)	$ (50,535)

CONSOLIDATED STATEMENT OF FINAN

CONSOLIDATED STATEMENT OF FINANCIAL POSITION - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
NON CURRENT ASSETS
Property, plant and equipment	$ 517,403	$ 473,646
Prepaid taxes	3,823	2,852
Other financial assets	22,110	19,547
Deferred income tax asset	27,636	23,053
Prepayments and other receivables	235	241
TOTAL NON CURRENT ASSETS	571,207	519,339
CURRENT ASSETS
Inventories	5,738	3,515
Trade receivables	19,519	18,426
Prepayments and other receivables	7,518	7,402
Prepaid taxes	26,048	15,815
Other financial assets	21,378	2,480
Cash and cash equivalents	134,755	73,563
TOTAL CURRENT ASSETS	214,956	121,201
TOTAL ASSETS	786,163	640,540
Equity attributable to owners of the Company
Share capital	61	60
Share premium	239,191	236,046
Reserves	129,606	130,118
Accumulated losses	(283,933)	(260,459)
Attributable to owners of the Company	84,925	105,765
Non-controlling interest	41,915	35,828
TOTAL EQUITY	126,840	141,593
NON CURRENT LIABILITIES
Borrowings	418,540	319,389
Provisions and other long-term liabilities	46,284	42,509
Deferred income tax liability	2,286	2,770
Trade and other payables	25,921	34,766
TOTAL NON CURRENT LIABILITIES	493,031	399,434
CURRENT LIABILITIES
Borrowings	7,664	39,283
Derivative financial instrument liabilities	19,289	3,067
Current income tax liabilities	42,942	5,155
Trade and other payables	96,397	52,008
TOTAL CURRENT LIABILITIES	166,292	99,513
TOTAL LIABILITIES	659,323	498,947
TOTAL EQUITY AND LIABILITIES	$ 786,163	$ 640,540

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Total	Share Capital [member]	Share premium [member]	Translation Reserve [member]	(Accumulated Losses) Retained Earnings [Member]	Non-controlling interests [member]	Other reserves [member]
Beginning Balance at Dec. 31, 2014	$ 479,126	$ 58	$ 210,886	$ (3,510)	$ 40,596	$ 103,569	$ 127,527
Comprehensive income:
Loss for the year	(284,566)	0	0	0	(234,031)	(50,535)	0
Currency translation differences	(1,001)	0	0	(1,001)	0	0	0
Total Comprehensive loss for the year	(285,567)	0	0	(1,001)	(234,031)	(50,535)	0
Transactions with owners:
Share-based payment (Note 30)	8,223	1	22,734	0	(14,993)	481	0
Repurchase of shares (Note 26)	(1,615)	0	(1,615)	0	0	0	0
Total	6,608	1	21,119	0	(14,993)	481	0
Ending Balance at Dec. 31, 2015	200,167	59	232,005	(4,511)	(208,428)	53,515	127,527
Comprehensive income:
Loss for the year	(60,646)	0	0	0	(49,092)	(11,554)	0
Currency translation differences	7,102	0	0	7,102	0	0	0
Total Comprehensive loss for the year	(53,544)	0	0	7,102	(49,092)	(11,554)	0
Transactions with owners:
Share-based payment (Note 30)	3,367	1	6,032	0	(2,939)	273	0
Repurchase of shares (Note 26)	(1,991)		(1,991)	0	0	0	0
Dividends distribution to non-controlling interest	(6,406)	0	0	0	0	(6,406)	0
Total	(5,030)	1	4,041	0	(2,939)	(6,133)	0
Ending Balance at Dec. 31, 2016	141,593	60	236,046	2,591	(260,459)	35,828	127,527
Comprehensive income:
Loss for the year	(17,837)	0	0	0	(24,228)	6,391	0
Currency translation differences	(512)	0	0	(512)	0	0	0
Total Comprehensive loss for the year	(18,349)	0	0	(512)	(24,228)	6,391	0
Transactions with owners:
Share-based payment (Note 30)	4,075	1	3,145	0	754	175	0
Dividends distribution to non-controlling interest	(479)	0	0	0	0	(479)	0
Total	3,596	1	3,145	0	754	(304)	0
Ending Balance at Dec. 31, 2017	$ 126,840	$ 61	$ 239,191	$ 2,079	$ (283,933)	$ 41,915	$ 127,527

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOW - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Loss for the year	$ (17,837)	$ (60,646)	$ (284,566)
Adjustments for:
Income tax expense (benefit)	43,145	11,804	(17,054)
Depreciation	74,885	75,774	105,557
Loss on disposal of property, plant and equipment	190	14	2,000
Impairment loss (reversed) recognised for non-financial assets	0	(5,664)	149,574
Write-off of unsuccessful exploration efforts	5,834	31,366	30,084
Accrual of borrowing’s interests	28,879	27,940	28,460
Borrowings cancellation costs	17,575	0	0
Amortisation of other long-term liabilities	(657)	(2,924)	(703)
Unwinding of long-term liabilities	2,779	2,693	2,575
Accrual of share-based payment	4,075	3,367	8,223
Foreign exchange loss (gain)	2,193	(13,872)	33,474
Unrealized loss on commodity risk management contracts	13,300	3,068	0
Income tax paid	(6,925)	(1,956)	(7,625)
Changes in working capital	(25,278)	11,920	(24,104)
Cash flows from operating activities - net	142,158	82,884	25,895
Cash flows from investing activities
Purchase of property, plant and equipment	(105,604)	(39,306)	(48,842)
Cash flows used in investing activities - net	(105,604)	(39,306)	(48,842)
Cash flows from financing activities
Proceeds from borrowings	425,000	186	7,036
Debt issuance costs paid	(6,683)	0	0
Proceeds from cash calls from related parties	1,155	5,210	2,400
Repurchase of shares	0	(1,991)	(1,615)
Principal paid	(355,022)	(22,645)	(89)
Interest paid	(27,688)	(25,490)	(25,754)
Borrowings cancellation costs paid	(12,315)	0	0
Dividends distribution to non-controlling interest	(479)	(6,406)	0
Cash flows from (used in) financing activities - net	23,968	(51,136)	(18,022)
Net increase (decrease) in cash and cash equivalents	60,522	(7,558)	(40,969)
Cash and cash equivalents at 1 January	73,563	82,730	127,672
Currency translation differences	670	(1,609)	(3,973)
Cash and cash equivalents at the end of the year	134,755	73,563	82,730
Cash in bank and bank deposits	134,734	73,551	82,720
Cash in hand	21	12	10
Cash and cash equivalents	$ 134,755	$ 73,563	$ 82,730

General Information

General Information	12 Months Ended
	Dec. 31, 2017
Disclosure Of General Information [Abstract]
Disclosure Of General Information About Company And Subsidiaries [Text Block]	Note 1 General Information GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM11, Bermuda. The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas reserves in Chile, Colombia, Brazil, Peru and Argentina. These Consolidated Financial Statements were authorised for issue by the Board of Directors on 7 March 2018.

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2017
Disclosure Of Summary of significant accounting policies [Abstract]
Disclosure of significant accounting policies [text block]	Note 2 Summary of significant accounting policies The principal accounting policies applied in the preparation of these Consolidated Financial Statements are set out below. These policies have been consistently applied to the years presented, unless otherwise stated. The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost convention. The Consolidated Financial Statements are presented in thousands of United States Dollars (US$'000) and all values are rounded to the nearest thousand (US$'000), except in the footnotes and where otherwise indicated. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”. All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise indicated. New and amended standards adopted by the Group ⋅ Recognition of Deferred Tax Assets for Unrealised Losses – Amendments to IAS 12 ⋅ Disclosure initiative – Amendments to IAS 7 The adoption of these amendments did not have any impact on the current period or any prior period and is not likely to affect future periods. New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2017 and not early adopted. ⋅ IFRS 2 Share based payments: amended in June 2016 to clarify the measurement basis for cash-settled share-based payments and the accounting for modifications that change an award from cash-settled to equity-settled. It also introduces an exception to IFRS 2 principles by requiring an award to be treated as if it was wholly equity-settled, where an employer is obliged to withhold an amount for the employee’s tax obligation associated with a share-based payment and pay that amount to the tax authority. It is effective for annual periods beginning on or after January 1, 2018. The Group estimates that these amendments will not have a material impact on the Group’s operating results or financial position. ⋅ IFRS 9 Financial Instruments and associated amendments to various other standards: IFRS 9 replaces the multiple classification and measurement models in IAS 39. Classification of debt assets will be driven by the entity’s business model for managing the financial assets and the contractual cash flow characteristics of the financial assets. A debt instrument is measured at amortised cost if: a) the objective of the business model is to hold the financial asset for the collection of the contractual cash flows, and b) the contractual cash flows under the instrument solely represent payments of principal and interest. All other debt and equity instruments, including investments in complex debt instruments and equity investments, must be recognised at fair value. All fair value movements on financial assets are taken through the statement of profit or loss, except for equity investments that are not held for trading, which may be recorded in the statement of profit or loss or in reserves (without subsequent recycling to profit or loss). For financial liabilities that are measured under the fair value option entities will need to recognise the part of the fair value change that is due to changes in their own credit risk in other comprehensive income rather than profit or loss. The new hedge accounting rules (released in December 2013) align hedge accounting more closely with common risk management practices. As a general rule, it will be easier to apply hedge accounting going forward. The new impairment model under IFRS 9 requires the recognition of impairment provisions based on expected credit losses rather than only incurred credit losses as is the case under IAS 39. It applies to financial assets classified at amortised cost, debt instruments measured at fair value through other comprehensive income, contract assets under IFRS 15, lease receivables, loan commitments and certain financial guarantee contracts. The new standard also introduces expanded disclosure requirements and changes in presentation. Management has assessed the effects of applying the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected. ⋅ IFRS 15 Revenue from contracts with customers and associated amendments to various other standards: The IASB has issued a new standard for the recognition of revenue. This will replace IAS 18 which covers contracts for goods and services and IAS 11 which covers construction contracts. The new standard is based on the principle that revenue is recognised when control of a good or service transfers to a customer so the notion of control replaces the existing notion of risks and rewards. These accounting changes may have flow-on effects on the entity’s business practices regarding systems, processes and controls, compensation and bonus plans, contracts, tax planning and investor communications. Entities will have a choice of full retrospective application, or prospective application with additional disclosures. It is mandatory for financial years commencing on or after 1 January 2018. The Group intends to adopt the standard using the modified retrospective approach which means that the cumulative impact of the adoption will be recognised in retained earnings as of 1 January 2018 and that comparatives will not be restated. Management has assessed the effects of applying the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected. ⋅ IFRS 16 Leases: will affect primarily the accounting by lessees and will result in the recognition of almost all leases on balance sheet. The standard removes the current distinction between operating and financing leases and requires recognition of an asset (the right to use the leased item) and a financial liability to pay rentals for virtually all lease contracts. An optional exemption exists for short-term and low-value leases. The accounting by lessors will not significantly change. Some differences may arise as a result of the new guidance on the definition of a lease. The Group has not yet determined to what extent its commitments will result in the recognition of an asset and a liability for future payments and how this will affect the Group’s profit and classification of cash flows. Some of the commitments may be covered by the exception for short-term and low-value leases and some commitments may relate to arrangements that will not qualify as leases under IFRS 16. At this stage, the Group does not intend to adopt the standard before its effective date. The Group intends to apply the simplified transition approach and will not restate comparative amounts for the year prior to first adoption. ⋅ IFRIC 22 Foreign Currency Transactions and Advance Consideration: issued in December 2016. The interpreta-tion addresses how to determine the date of the transaction for the purpose of determining the exchange rate to use on initial recognition of the related asset, expense or income related to an entity that has received or paid an advance consideration in a foreign currency. The date of the transaction is the date on which an entity initially rec-ognises the non-monetary asset or non-monetary liability arising from the payment or receipt of advance consid-eration. It is effective for annual periods beginning on January 1, 2018. The Group estimates that these interpreta-tions will not have a material impact on the Group’s operating results or financial position. ⋅ Sale or contribution of assets between an investor and its associate or joint venture – Amendments to IFRS 10 and IAS 28: The amendments clarify the accounting treatment for sales or contribution of assets between an investor and its associates or joint ventures. ⋅ Improvements to IFRSs – 2014-2016 Cycle: amendments issued in December 2016 that are effective for periods beginning on or after January 1, 2018. The Group estimates that these amendments will not have an impact on the Group’s operating results or financial position. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. The Directors regularly monitor the Group's cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecast operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches. Considering macroeconomic environment conditions, the performance of the operations, the US$ 425,000,000 99 Subsidiaries are all entities (including structured entities) over which the group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred by the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred. The excess of the consideration transferred, the amount of any non-controlling interest in the acquired entity, and the acquisition-date fair value of any previous equity interest in the acquired entity over the fair value of the identifiable net assets acquired is recorded as goodwill. If the total of consideration transferred, non-controlling interest recognised and previously held interest measured is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognised directly in the income statement. Intercompany transactions, balances and unrealised gains on transactions between the Group and its subsidiaries are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group. Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and People departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. a) Functional and presentation currency The Consolidated Financial Statements are presented in US Dollars, which is the Group’s presentation currency. Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Chile, Colombia, Peru and Argentina is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the Brazilian Real. b) Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Consolidated Statement of Income. Under IFRS 11 investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined them to be joint operations. The Group combines its share in the joint operations individual assets, liabilities, results and cash flows on a line-by-line basis with similar items in its financial statements. Revenue from the sale of crude oil and gas is recognised in the Consolidated Statement of Income when risk is transferred to the purchaser, and if the revenue can be measured reliably and is expected to be received. Revenue is shown net of VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. See Note 32 (a). Production costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, leasing and royalties are also included within this account. Financial results include interest expenses, interest income, bank charges, the amortisation of financial assets and liabilities, and foreign exchanges gain and losses. The Group has capitalised borrowing cost for wells and facilities that were initiated after 1 January 2009. The capitalisation rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s general borrowings during the year, which was 6.90 7.98 amounted to 610,841 254,950 637,390 Property, plant and equipment are stated at historical cost less depreciation and impairment charge, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation. Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalising exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income. Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of exploratory wells. No depreciation and/or amortisation are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which the determination is made depending whether they have found reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. A charge of US$ 5,834 31,366 30,084 All field development costs are considered construction in progress until they are finished and capitalised within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties. Workovers of wells made to develop reserves and/or increase production are capitalised as development costs. Maintenance costs are charged to the Consolidated Statement of Income when incurred. Capitalised costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs and is based on current year end unescalated price levels. Changes in reserves and cost estimates are recognised prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. Depreciation of the remaining property, plant and equipment assets (i.e. furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between 3 years 10 years Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow up the performance of the business. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.12). Provisions for asset retirement obligations, deferred income, restructuring obligations and legal claims are recognised when the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to the passage of time is recognised as financial expense. The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded, the Group capitalises the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalised cost is depreciated over the estimated useful life of the related asset. According to interpretations and application of current legislation and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are included in the financial statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset. Relates to contributions received in cash from the Group’s clients to improve the project economics of gas wells. The amounts collected are reflected as a deferred income in the balance sheet and recognised in the Consolidated Statement of Income over the productive life of the associated wells. The depreciation of the gas wells that generated the deferred income is charged to the Consolidated Statement of Income simultaneously with the amortisation of the deferred income. The addition in 2016 and the amounts used in 2017 correspond to the deferred income related to the take or pay provision associated to gas sales in Brazil. Assets that are not subject to depreciation and/or amortisation (i.e.: exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation and/or amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date. No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable. During 2017, no impairment loss was recognised (impairment loss reversed for US$ 5,664,000 149,574,000 All current lease contracts are considered to be operating leases on the basis that the lessor retains substantially all the risks and rewards related to the ownership of the leased asset. Payments related to operating leases and other rental agreements are recognised in the Consolidated Income Statement on a straight line basis over the term of the contract. The Group's total commitment relating to operating leases and rental agreements is disclosed in Note 32. Leases in which substantially all of the risks and rewards of ownership are transferred to the lessee are classified as finance leases. Under a finance lease, the Group as lessor has to recognise an amount receivable equal to the aggregate of the minimum lease payments plus any unguaranteed residual value accruing to the lessor, discounted at the interest rate implicit in the lease. Inventories comprise crude oil and materials. Crude oil is measured at the lower of cost and net realisable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method. The tax expense for the year comprises current and deferred tax. Tax is recognised in the Consolidated Statement of Income. The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the balance sheet date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted as of the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. In addition, the Group has tax-loss carry-forwards in certain taxing jurisdictions that are available to be offset against future taxable profit. However, deferred tax assets are recognised only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. Deferred income tax liabilities are provided on taxable temporary differences arising from investments in subsidiaries and joint arrangements, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred tax is recognised in respect of the retained earnings of overseas subsidiaries only if at the date of the statements of financial position, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future. In the event that these differences revert in total (e.g. dividends are declared and paid), the deferred tax liability which the Group would have to recognise amounts to approximately US$ 12,300 Deferred tax balances are provided in full, with no discounting. Financial assets are divided into the following categories: loans and receivables; financial assets at fair value through profit or loss; available-for-sale financial assets; and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial recognition, depending on the purpose for which the investments were acquired. The designation of financial assets is re-evaluated at every reporting date at which a choice of classification or accounting treatment is available. All financial assets are recognised when the Group becomes a party to the contractual provisions of the instrument. All financial assets are initially recognised at fair value, plus transaction costs. Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date. Interest and other cash flows resulting from holding financial assets are recognised in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured. Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. The Group’s loans and receivables comprise trade receivables, prepayments and other receivables and cash and cash equivalents in the balance sheet. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. Loans and receivables are subsequently measured at amortised cost using the effective interest method, less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Statement of Income. All of the Group’s financial assets are classified as loan and receivables. Non current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes. Current other financial assets include the security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original maturities up to twelve months and over three months. Provision against trade receivables is made when objective evidence is received that the Group will not be able to collect all amounts due to it in accordance with the original terms of those receivables. The amount of the write-down is determined as the difference between the asset's carrying amount and the present value of estimated future cash flows. Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position. Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Derivative financial instruments are recognised in the statement of financial position as assets or liabilities and initially and subsequently measured at fair value through profit and loss. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period. The market-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. Gains and losses arising from changes in fair value are recognised in the Consolidated Statement of Income within Commodity risk management contracts. For more information about derivatives please refer to Note 8. Borrowings are obligations to pay cash and are recognised when the Group becomes a party to the contractual provisions of the instrument. Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the Consolidated Statement of Income over the period of the borrowings using the effective interest method. Direct issue costs are charged to the Consolidated Statement of Income on an accruals basis using the effective interest method. Equity comprises the following: ⋅ "Share capital" representing the nominal value of equity shares. ⋅ "Share premium" representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issuance. ⋅ "Other reserve" representing: - the equity element attributable to shares granted according to IFRS 2 but not issued at year end or, - the difference between the proceeds from the transaction with non-controlling interests received against the book value of the shares acquired in the Chilean and Colombian subsidiaries. ⋅ "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries. ⋅ "(Accumulated losses) Retained earnings" representing accumulated earnings and losses. The Group operates a number of equity-settled and cash-settled share-based compensation plans comprising share awards payments to certain employees and other third party contractors. Share-based payment transactions are measured in accordance with IFRS 2. Fair value of the stock option plan for employee or contractors services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted calculated using the Geometric Brownian Motion method. Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At each balance sheet date, the entity revises its estimates of the number of options that are expected to vest. It recognises

Financial Instruments-risk mana

Financial Instruments-risk management	12 Months Ended
	Dec. 31, 2017
Disclosure Of Financial Instruments-risk management [Abstract]
Disclosure of financial risk management [text block]	Note 3 Financial Instruments-risk management The Group is exposed through its operations to the following financial risks: · Currency risk · Price risk · Credit risk – concentration · Funding and liquidity risk · Interest rate risk · Capital risk management The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is described in more detail below. Currency risk In Argentina, Colombia, Chile and Peru the functional currency is the US Dollar. The fluctuation of the local currencies of these countries against the US Dollar does not impact the loans, costs and revenue held in US Dollars; but it does impact the balances denominated in local currencies. Such is the case of the prepaid taxes. In Chile, Colombia and Argentina subsidiaries most of the balances are denominated in US Dollars, and since it is the functional currency of the subsidiaries, there is no exposure to currency fluctuation except from receivables or payables originated in local currency mainly corresponding to VAT. The Group minimises the local currency positions in Argentina, Colombia and Chile by seeking to equilibrate local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore the Group maintains a net exposure to them. Most of the Group's assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally settled in US Dollar equivalents. During 2017, the Argentine Peso devaluated by 17 22 52 8 6 16 1 5 32 If the Argentine Peso, the Chilean Peso and the Colombian Peso had each devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 1,538,000 (US$ 2,683,400 in 2016 and US$ 1,003,300 in 2015). In Brazil, the functional currency is the local currency, which is the Brazilian Real. The fluctuation of the US Dollars against the Brazilian Real does not impact the loans, costs and revenues held in Brazilian Real; but it does impact the balances denominated in US Dollars. Such is the case of the Itaú, which was fully repaid in September 2017, and intercompany loans. Most of the balances are denominated in Brazilian Real, and since it is the functional currency of the Brazilian subsidiary, there is no exposure to currency fluctuation except from the intercompany loan and the Itaú loan described in Note 27. The exchange loss generated by the Brazilian subsidiary during 2017 amounted to US$ 1,274,000 14,542,000 35,605,000 During 2017, the Brazilian Real devaluated by 2 17 47 If the Brazilian Real had devaluated 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 3,100,000 (US$ 5,300,000 in 2016 and US$ 7,400,000 in 2015). As of 31 December 2017, the balances denominated in the Peruvian local currency (Peruvian Soles) are not material. As currency rate changes between the US Dollar and the local currencies, the Group recognises gains and losses in the Consolidated Statement of Income. Price risk The price realised for the oil produced by the Group is linked to US dollar denominated crude oil international benchmarks. The market price of these commodities is subject to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, geopolitical landscape, economic conditions and a variety of additional factors. In Colombia, the realised oil price is linked to the Vasconia crude reference price, a marker broadly used in the Llanos basin, adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur content, water content, delivery point and transport costs. In Chile, the oil price is based on Dated Brent minus certain marketing and quality discounts such as, API, sulphur content and others. GeoPark has signed a long-term Gas Supply Contract with Methanex in Chile. The price of the gas sold under this contract is determined by a formula that considers a basket of international methanol prices, including US Gulf methanol spot barge prices, methanol spot Rotterdam prices and spot prices in Asia. In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral de Preços do Mercado), or IGPM. If oil and methanol prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax loss for the year would have been higher by US$ 10,423,000 (US$ 23,655,000 in 2016 and US$ 23,940,000 in 2015). As of October 2016, GeoPark considered it was appropriate to manage part of the exposure to crude oil price volatility using derivatives. The Group considers these derivative contracts to be an effective manner of properly managing commodity price risk. The price risk management activities mainly employ combinations of options and key parameters are based on forecasted production and budget price levels. GeoPark has also obtained credit lines from industry leading counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8). Credit risk – concentration The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognised values. There is not considered to be any significant risk in respect of the Group’s major customers and hedging counterparties. In Colombia, during 2017, the Colombian subsidiary made 99 79 All the oil produced in Chile as well as the gas produced by TdF Blocks ( 5 10 15 5 9 7 In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the State owned company, which is the operator of the Manati Field ( 10 15 The forementioned companies all have good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk. In 2016 and 2017, the Group executed oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions and trading companies, therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes 8 and 25. Funding and Liquidity risk In the past, the Group was able to raise capital through different sources of funding including equity, strategic partnerships and financial debt. During 2017, the Group placed US$ 425,000 The Group is positioned at the end of 2017 with a cash balance of US$ 134,755,000 99 31,000 The indenture governing the Company Notes 2024 includes incurrence test covenants related to the compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur additional indebtedness, as specified in the indenture governing the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indenture’s provisions and covenants. The most significant funding transactions executed in 2017, 2016 and 2015 include: On September 2017, the Group successfully placed US$ 425,000,000 6.50 21 September 2024 7.50 2020 On December 2015, the Group announced the execution of an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provided GeoPark with access to up to US$ 100,000,000 10,000,000 Interest rate risk The Group’s interest rate risk arises from long-term borrowings issued at variable rates, which expose the Group to cash flow to interest rate risk. The Group does not face interest rate risk on its US$ 425,000,000 6.50 The Group analyses its interest rate exposure on a dynamic basis. Various scenarios are simulated taking into consideration refinancing, renewal of existing positions, alternative financing and hedging. Based on these scenarios, the Group calculates the impact on profit and loss of a defined interest rate shift. For each simulation, the same interest rate shift is used for all currencies. The scenarios are run only for liabilities that represent the major interest-bearing positions. At 31 December 2017, the Group has no exposure to fluctuations in the interest rate, since its long-term borrowings were issued at fixed rate. At 31 December 2016 and 2015, if 1% had been added to interest rates on currency-denominated borrowings with all other variables held constant, post tax loss for the year would have been US$ 467,000 and US$ 507,000 higher, respectively. Capital risk management The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. Consistent with others in the industry, the Group monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net debt is calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the consolidated balance sheet) less cash and cash equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plus net debt. The Group’s strategy is to keep the gearing ratio within a 30 45 Amounts in US$ '000 2017 2016 Net Debt 291,449 285,109 Total Equity 126,840 141,593 Total Capital 418,289 426,702 Gearing Ratio 70 % 67 %

Accounting estimates and assump

Accounting estimates and assumptions	12 Months Ended
	Dec. 31, 2017
Disclosure Of Accounting estimates and assumptions [Abstract]
Disclosure of accounting judgements and estimates [text block]	Note 4 Accounting estimates and assumptions Estimates and assumptions are used in preparing the financial statements. Although these estimates are based on management's best knowledge of current events and actions, actual results may differ from them. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The key estimates and assumptions used in these Consolidated Financial Statements are noted below: ⋅ Cash flow estimates for impairment assessments of non-financial assets require assumptions about two primary elements - future prices and reserves. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group's forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and own assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs. Given the significant assumptions required and the possibility that actual conditions will differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 36). The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of 31 December 2017 prepared by DeGolyer and MacNaughton, an international consultancy to the oil and gas industry based in Dallas. It incorporates many factors and assumptions including: o expected reservoir characteristics based on geological, geophysical and engineering assessments; o future production rates based on historical performance and expected future operating and investment activities; o future oil and gas prices and quality differentials; o assumed effects of regulation by governmental agencies; and o future development and operating costs. Management believes these factors and assumptions are reasonable based on the information available to them at the time of preparing the estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. ⋅ The Group adopts the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding whether an exploration asset should continue to be carried forward as an exploration and evaluation asset not yet determined or when insufficient information exists for this type of cost to remain as an asset. In making this assessment Management takes professional advice from qualified experts. ⋅ Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. ⋅ Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant obligations. Estimating the future abandonment costs is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future. Technologies and costs are constantly changing as well as political, environmental, safety and public relations considerations. The Group has adopted the following criterion for recognising well plugging and abandonment related costs: The present value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated future expenditure. The liabilities recognised are based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. ⋅ From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental, safety and health matters. For example, from time to time, the Group receives notice of environmental, health and safety violations. Based on what the Management of the Group currently knows, it is not expected any material impact on the financial statements.

Note - Consolidated Statement o

Note - Consolidated Statement of Cash Flow	12 Months Ended
	Dec. 31, 2017
Disclosure Of Consolidated Statement Of Cash Flow [Abstract]
Disclosure of cash flow statement [text block]	Note 5 Consolidated Statement of Cash Flow The Consolidated Statement of Cash Flow shows the Group's cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents during the year. Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital, and corporate tax. Income tax paid is presented as a separate item under operating activities. Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any. Cash flows from financing activities include changes in equity, and proceeds from borrowings and repayment of loans. Cash and cash equivalents include bank overdraft and liquid funds with a term of less than three months. Amounts in US$ '000 2017 2016 2015 Increase in asset retirement obligation 5,943 1,195 985 Increase in provisions for other long-term liabilities 2,053 3,468 - Purchase of property, plant and equipment 11,759 (4,657) 830 Amounts in US$ '000 2017 2016 2015 Increase in Prepaid taxes (14,802) (2,351) (16,611) (Increase) Decrease in Inventories (2,031) 466 2,752 (Increase) Decrease in Trade receivables (1,344) (4,811) 22,470 (Increase) Decrease in Prepayments and other receivables and Other assets (8,623) (1,758) 405 Customer advance (repayments) payments (10,000) 20,000 - Security deposit granted (Note 35) (15,600) - - Increase (Decrease) in Trade and other payables 27,122 374 (33,120) (25,278) 11,920 (24,104)

Segment information

Segment information	12 Months Ended
	Dec. 31, 2017
Disclosure Of Segment information [Abstract]
Disclosure of entity's operating segments [text block]	Note 6 Segment information Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and People departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective. The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit for the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payment, unrealized result on commodity risk management contracts and other non recurring events. Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses. Other information provided, except as noted below, to the Executive Committee is measured in a manner consistent with that in the financial statements. Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2017 Revenue 32,738 34,238 263,076 - 70 - 330,122 Sale of crude oil 15,873 910 262,309 - 70 - 279,162 Sale of gas 16,865 33,328 767 - - - 50,960 Realized loss on commodity risk management contracts - - (2,148) - - - (2,148) Production and operating costs (20,999) (10,737) (66,913) - (338) - (98,987) Royalties (1,314) (3,134) (24,236) - (13) - (28,697) Transportation costs (1,211) - (1,678) - (80) - (2,969) Share-based payment (170) (39) (248) - - - (457) Other costs (18,304) (7,564) (40,751) - (245) - (66,864) Operating (loss) profit (19,675) 4,434 116,290 (3,850) (3,430) (14,773) 78,996 Operating netback 11,222 23,540 194,013 - (467) - 228,308 Adjusted EBITDA 4,070 20,166 168,303 (3,505) (2,183) (11,075) 175,776 Depreciation (23,730) (10,809) (40,010) (139) (159) (38) (74,885) Write-off (546) (2,978) (1,625) - (685) - (5,834) Total assets 301,931 91,604 288,429 22,099 30,924 51,176 786,163 Employees (average) 102 12 164 13 88 - 379 Employees at year end 102 12 180 19 92 - 405 Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2016 Revenue 36,723 29,719 126,228 - - - 192,670 Sale of crude oil 18,774 688 125,731 - - - 145,193 Sale of gas 17,949 29,031 497 - - - 47,477 Realized gain on commodity risk management contracts - - 514 - - - 514 Production and operating costs (22,169) (8,459) (36,607) - - - (67,235) Royalties (1,495) (2,721) (7,281) - - - (11,497) Transportation costs (1,170) - (1,111) - - - (2,281) Share-based payment (138) (71) (413) - - - (622) Other costs (19,366) (5,667) (27,802) - - - (52,835) Operating (loss) profit (44,969) (645) 31,463 (3,147) 370 (11,685) (28,613) Operating netback 13,696 21,356 87,523 41 (378) (91) 122,147 Adjusted EBITDA 5,159 17,487 66,921 (2,607) 1,848 (10,487) 78,321 Depreciation (31,355) (12,974) (31,148) (130) (150) (17) (75,774) Reversal of impairment losses - - 5,664 - - - 5,664 Write-off (19,389) (4,583) (7,394) - - - (31,366) Total assets 317,969 99,904 182,784 5,020 6,071 28,792 640,540 Employees (average) 102 10 138 11 80 - 341 Employees at year end 102 10 146 10 77 - 345 Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2015 Revenue 44,808 32,388 131,897 - 597 - 209,690 Sale of crude oil 29,180 955 131,897 - 597 - 162,629 Sale of gas 15,628 31,433 - - - - 47,061 Production costs (28,704) (8,056) (48,534) - (1,448) - (86,742) Royalties (1,973) (2,998) (8,150) - (34) - (13,155) Transportation costs (2,441) - (2,068) - (2) - (4,511) Share-based payment (132) - (234) - (197) - (563) Other costs (24,158) (5,058) (38,082) - (1,215) - (68,513) Operating (loss) profit (180,264) 6,639 (37,227) (6,719) (2,350) (12,570) (232,491) Operating netback 15,254 24,393 80,355 44 (1,732) (287) 118,027 Adjusted EBITDA (183) 20,460 66,736 (6,520) (684) (6,022) 73,787 Depreciation (39,227) (13,568) (52,434) (129) (199) - (105,557) Impairment loss (104,515) - (45,059) - - - (149,574) Write-off (25,751) - (4,333) - - - (30,084) Total assets 381,143 114,974 153,071 4,287 3,181 47,143 703,799 Employees (average) 153 11 130 16 93 - 403 Employees at year end 106 12 133 11 90 - 352 Approximately 76 67 66 10 20 22 8 4 3 9 12 3 Amounts in US$ '000 2017 2016 2015 Operating netback 228,308 122,147 118,027 Administrative expenses (38,937) (32,323) (30,590) Geological and geophysical expenses (13,595) (11,503) (13,650) Adjusted EBITDA for reportable segments 175,776 78,321 73,787 Unrealized loss on commodity risk management contracts (13,300) (3,068) - Depreciation (a) (74,885) (75,774) (105,557) Share-based payment (4,075) (3,367) (8,223) Impairment and write-off of unsuccessful exploration efforts (5,834) (25,702) (179,658) Others (b) 1,314 977 (12,840) Operating profit (loss) 78,996 (28,613) (232,491) Financial expenses (53,511) (36,229) (36,924) Financial income 2,016 2,128 1,269 Foreign exchange (loss) profit (2,193) 13,872 (33,474) Profit (Loss) before tax 25,308 (48,842) (301,620) (a) Net of capitalised costs for oil stock included in Inventories. (b) In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2017
Disclosure Of Revenue [Abstract]
Disclosure of revenue [text block]	Note 7 Revenue Amounts in US$ '000 2017 2016 2015 Sale of crude oil 279,162 145,193 162,629 Sale of gas 50,960 47,477 47,061 330,122 192,670 209,690

Commodity risk management contr

Commodity risk management contracts	12 Months Ended
	Dec. 31, 2017
Disclosure Of Commodity risk management contracts [Abstract]
Disclosure Of Commodity Risk Management Contracts Explanatory [Text Block]	Note 8 Commodity risk management contracts The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars or zero-premium 3 ways (put spread plus call), and were placed with major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protect the Group from potential non-performance risk by its counterparties. The Group’s derivatives are accounted for as non-hedge derivatives as of 31 December 2017 and therefore all changes in the fair values of its derivative contracts are recognised as gains or losses in the results of the periods in which they occur. Period Reference Type Volume Price US$/bbl 1 October 2017 - 31 March 2018 ICE BRENT Zero Premium Collar 4,000 50.00 Put 54.90 Call 1 October 2017 - 31 March 2018 ICE BRENT Zero Premium Collar 2,000 50.00 Put 54.95 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 2,000 52.00 Put 60.00 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 1,000 52.00 Put 58.40 Call 1 April 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 2,000 52.00 Put 58.25 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.55 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.50 Call 1 April 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.60 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 2,000 43.00-53.00 Put 64.55 Call 1 July 2018 - 30 September 2018 ICE BRENT Zero Premium 3 Way 5,000 43.00-53.00 Put 69.00 Call 2017 2016 2015 Realized (loss) gain on commodity risk management contracts (2,148) 514 - Unrealized loss on commodity risk management contracts (13,300) (3,068) - Total (15,448) (2,554) -

Production and operating costs

Production and operating costs	12 Months Ended
	Dec. 31, 2017
Disclosure Of Production And Operating Costs [Abstract]
Disclosure Of Production And Operating Costs Explanatory [Text Block]	Note 9 Production and operating costs Amounts in US$ '000 2017 2016 2015 Well and facilities maintenance 14,722 13,160 19,974 Staff costs (Note 11) 15,017 10,859 17,999 Share-based payment (Notes 11) 457 622 563 Royalties 28,697 11,497 13,155 Consumables 11,902 8,283 8,591 Transportation costs 2,969 2,281 4,511 Equipment rental 5,818 3,868 3,517 Safety and Insurance costs 2,591 2,222 3,239 Gas plant costs 6,069 6,300 2,878 Field camp 2,377 1,687 2,645 Non operated blocks costs 1,213 1,082 2,127 Other costs 7,155 5,374 7,543 98,987 67,235 86,742

Depreciation

Depreciation	12 Months Ended
	Dec. 31, 2017
Disclosure Of Depreciation [Abstract]
Disclosure of depreciation and amortisation expense [text block]	Note 10 Depreciation Amounts in US$ '000 2017 2016 2015 Oil and gas properties 57,725 61,080 84,849 Production facilities and machinery 14,558 10,788 15,467 Furniture, equipment and vehicles 1,948 2,702 2,850 Buildings and improvements 844 920 874 Depreciation of property, plant and equipment (a) 75,075 75,490 104,040 Related to: Productive assets 72,283 71,868 100,316 Administrative assets 2,792 3,622 3,724 Depreciation total (a) 75,075 75,490 104,040 (a)

Staff costs and Directors Remun

Staff costs and Directors Remuneration	12 Months Ended
	Dec. 31, 2017
Disclosure of Staff costs and Directors Remuneration [Abstract]
Disclosure Of Staff Costs And Directors Remuneration Explanatory [Text Block]	Note 11 Staff costs and Directors Remuneration 2017 2016 2015 Number of employees at year end 405 345 352 Amounts in US$ '000 Wages and salaries 44,891 36,059 40,574 Share-based payments (Note 30) 4,075 3,367 8,223 Social security charges 5,364 3,792 6,197 Director’s fees and allowance 3,458 2,088 1,238 57,788 45,306 56,232 Recognised as follows: Production and operating costs 15,474 11,481 18,562 Geological and geophysical expenses 11,026 10,439 11,336 Administrative expenses 31,288 23,386 26,334 57,788 45,306 56,232 Board of Directors’ and key managers’ remuneration Salaries and fees 9,674 7,337 6,549 Share-based payments 2,322 1,211 6,544 Other benefits in kind 287 112 167 12,283 8,660 13,260 Directors’ Remuneration Executive Executive Non- Director Fees Cash Gerald O’Shaughnessy US$ 400,000 - - - US$ 400,000 James F. Park US$ 800,000 US$ 800,000 - - US$ 1,600,000 Pedro Aylwin (a) - - - - - Peter Ryalls (b) - - US$ 115,000 9,388 US$ 165,010 Juan Cristóbal Pavez (c) - - US$ 110,000 15,408 US$ 210,020 Carlos Gulisano - - US$ 110,000 15,408 US$ 210,020 Robert Bedingfield (d) - - US$ 102,500 15,408 US$ 202,520 Michael Dingman - - US$ 46,667 8,853 US$ 105,012 Jamie Coulter - - US$ 50,000 6,020 US$ 95,641 a b c d The non-executive Directors annual fees correspond to US$ 80,000 100,000 20,000 10,000

Geological and geophysical expe

Geological and geophysical expenses	12 Months Ended
	Dec. 31, 2017
Disclosure Of Geological and geophysical expenses [Abstract]
Disclosure of geological and geophysical expenses [Text Block]	Note 12 Geological and geophysical expenses Amounts in US$ '000 2017 2016 2015 Staff costs (Note 11) 10,525 9,541 10,557 Share-based payment (Notes 11) 501 898 779 Allocation to capitalised project (6,402) (2,119) (598) Other services 3,070 1,962 3,093 7,694 10,282 13,831

Administrative expenses

Administrative expenses	12 Months Ended
	Dec. 31, 2017
Disclosure Of Administrative expenses [Abstract]
Disclosure of general and administrative expense [text block]	Note 13 Administrative expenses Amounts in US$ '000 2017 2016 2015 Staff costs (Note 11) 24,713 19,451 18,215 Share-based payment (Notes 11) 3,117 1,847 6,881 Consultant fees 5,120 3,894 4,115 Office expenses 2,506 2,217 2,535 Travel expenses 2,772 1,717 1,497 Director’s fees and allowance (Note 11) 3,458 2,088 1,238 Communication and IT costs 2,109 2,013 1,791 Allocation to joint operations (7,646) (4,365) (4,203) Other administrative expenses 5,905 5,308 5,402 42,054 34,170 37,471

Selling expenses

Selling expenses	12 Months Ended
	Dec. 31, 2017
Disclosure of Selling expenses [Abstract]
Disclosure of selling expenses [text block]	Note 14 Selling expenses Amounts in US$ '000 2017 2016 2015 Transportation 864 3,559 4,760 Selling taxes and other 272 663 451 1,136 4,222 5,211

Financial results

Financial results	12 Months Ended
	Dec. 31, 2017
Disclosure Of Financial costs [Abstract]
Disclosure of finance income (cost) [text block]	Note 15 Financial results Amounts in US$ '000 2017 2016 2015 Financial expenses Interest and amortisation of debt issue costs (27,823) (28,984) (28,983) Interest with related parties (2,224) (1,587) (1,560) Less: amounts capitalised on qualifying assets 611 255 637 Borrowings cancellation costs (17,575) - - Bank charges and other financial results (3,721) (3,220) (4,443) Unwinding of long-term liabilities (Note 28) (2,779) (2,693) (2,575) (53,511) (36,229) (36,924) Financial income Interest received 2,016 2,128 1,269 2,016 2,128 1,269 Foreign exchange gains and losses Foreign exchange (loss) gain (2,193) 13,872 (33,474) (2,193) 13,872 (33,474) Total Financial results (53,688) (20,229) (69,129)

Tax reforms

Tax reforms	12 Months Ended
	Dec. 31, 2017
Disclosure of Tax reforms [Abstract]
Disclosure Of New Tax Reforms Explanatory [Text Block]	Note 16 Tax reforms Colombia A tax reform has been enacted in Colombia during December 2016. The legislation included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions and the repeal of certain corporate-level taxes. The legislation also aimed to raise tax revenue mostly by increasing the rate of the value added tax (VAT) to 19 16 The legislation also included the following provisions that are intended to simplify the corporate income tax system by: ⋅ Eliminating the “CREE” tax on corporations and the CREE surtax (CREE is the Spanish acronym for the “fairness tax”). ⋅ Introducing a temporary income surtax of 6 Accordingly, with this tax reform, the corporate income tax will have the following rate schedule (applied beyond a limited profit threshold): ⋅ 40 34 6 ⋅ 37 33 4 ⋅ 33 There is an increase in the tax rate on deemed income relating to increases in a taxpayer’s net worth (i.e., the increase in the value of a taxpayer’s assets); the rate is increased from 3 3.5 Other changes to the income tax law were the following: ⋅ New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 5% for dividends distributed out of the distributing entity’s previously taxed profits; and (2) 35% for dividends distributed out of the distributing entity’s previously untaxed profits, plus an additional 5% after having applied and deducted the initial 35% withholding. ⋅ A general 15 ⋅ Lengthen the statute of limitations with respect to tax returns and assessments. ⋅ Limit loss carryforwards to 12 years ⋅ Allow for a deduction of VAT paid on certain acquisitions or imports of capital goods when calculating the taxpayer’s income tax liability. ⋅ Retain the tax on long-term capital gains at 10 The legislation also revises and refines tax accounting standards based on IFRS rules. Argentina A tax reform has been enacted in Argentina during December 2017. The legislation included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions. Most of the tax provisions are effective from fiscal year 2018. With this tax reform, the corporate income tax -previously 35 ⋅ 30 ⋅ 25 Other changes include the following: ⋅ New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 7% for dividends distributed out of the distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and (2) 13% for dividends distributed out of the distributing entity’s previously taxed profits of fiscal years 2020 and onwards. ⋅ Application of inflation adjustment for corporate tax purposes is reinstated under certain circumstances. ⋅ Possible tax revaluation of investment in fixed assets, under payment of a special tax. ⋅ Allow for short term recovery of VAT paid on acquisitions or imports of capital goods, when non recoverable with VAT on usual sales.

Income tax

Income tax	12 Months Ended
	Dec. 31, 2017
Disclosure Of Income tax [Abstract]
Disclosure of income tax [text block]	Note 17 Income tax Amounts in US$ '000 2017 2016 2015 Current tax (48,449) (12,359) (7,262) Deferred income tax (Note 18) 5,304 555 24,316 (43,145) (11,804) 17,054 Amounts in US$ '000 2017 2016 2015 Profit (Loss) before tax 25,308 (48,842) (301,620) Tax losses from non-taxable jurisdictions 22,708 12,318 15,852 Taxable profit (loss) 48,016 (36,524) (285,768) Income tax calculated at domestic tax rates applicable to Profit (Losses) Income in the respective countries (31,107) (809) 62,589 Tax losses where no deferred tax benefit is recognised (8,111) (6,616) (16,325) Effect of currency translation on tax base (2,330) (2,840) (6,776) Changes in the income tax rate (Note 16) 542 220 (625) Non recoverable tax loss carry-forwards - - (15,537) Non-taxable results (a) (2,139) (1,759) (6,272) Income tax (43,145) (11,804) 17,054 (a) Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities. Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Income tax rates in those countries where the Group operates (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15 40 Amounts in US$ '000 2017 2016 2015 Argentina 4,849 2,908 3,834 Chile (a) 345,104 280,290 209,910 Brazil (a) 33,721 16,057 - Total tax losses at 31 December 383,674 299,255 213,744 (a) At the balance sheet date deferred tax assets in respect of tax losses in Argentina and in certain Companies in Chile have not been recognised as there is insufficient evidence of future taxable profits to offset them (in the case of Argentina, before the statute of limitation of these tax losses causes them to expire). Expiring date Amounts in US$ '000 2020 754 2021 1,446 2022 2,649

Deferred income tax

Deferred income tax	12 Months Ended
	Dec. 31, 2017
Disclosure of deferred income tax [Abstract]
Disclosure of deferred taxes [text block]	Note 18 Deferred income tax Amounts in US$ '000 2017 2016 Deferred tax at 1 January 20,283 17,691 Reclassification (a) - 574 Currency translation differences (237) 1,463 Income statement credit 5,304 555 Deferred tax at 31 December 25,350 20,283 (a) Corresponds to differences between income tax provision and the final tax return presented. Amounts in US$ '000 At the beginning Currency (Charged) At end of year Deferred tax assets Difference in depreciation 19,225 (237) (2,817) 16,171 Taxable losses 3,828 - 7,637 11,465 Total 2017 23,053 (237) 4,820 27,636 Total 2016 34,646 1,463 (13,056) 23,053 Amounts in US$ '000 At the beginning Credited to Reclassification (a) At end Deferred tax liabilities Difference in depreciation (17,308) (2,766) - (20,074) Taxable losses 14,538 3,250 - 17,788 Total 2017 (2,770) 484 - (2,286) Total 2016 (16,955) 13,611 574 (2,770) (a) Corresponds to differences between income tax provision and the final tax return presented.

Earnings per share

Earnings per share	12 Months Ended
	Dec. 31, 2017
Disclosure of earning per share [Abstract]
Disclosure of earnings per share [text block]	Note 19 Earnings per share Amounts in US$ '000 except for shares 2017 2016 2015 Numerator: Loss for the year attributable to owners (24,228) (49,092) (234,031) Denominator: Weighted average number of shares used in basic EPS 60,093,191 59,777,145 57,759,001 (Losses) after tax per share (US$) – basic (0.40) (0.82) (4.05) Amounts in US$ '000 except for shares 2017 (a) 2016 2015 Weighted average number of shares used in basic EPS 60,093,191 59,777,145 57,759,001 Effect of dilutive potential common shares (a) Weighted average number of common shares for the purposes of diluted earnings per shares 60,093,191 59,777,145 57,759,001 (Losses) after tax per share (US$) – diluted (0.40) (0.82) (4.05) (a) 4,564,777 1,390,706 1,032,279

Property, plant and equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2017
Disclosure of property plant and equipments [Abstract]
Disclosure of property, plant and equipment [text block]	Note 20 Property, plant and equipment Amounts in US$'000 Oil &; gas Furniture, Production Buildings Construction in Exploration and (b) Total Cost at 1 January 2015 749,947 12,057 111,646 9,527 59,425 140,444 1,083,046 Additions (4,640) (a) 954 - 272 36,543 12,299 45,428 Currency translation differences (27,522) (182) (2,577) (92) - (1,510) (31,883) Disposals (241) (13) (1,685) (84) - - (2,023) Write-off / Impairment loss (128,956) - (13,242) - (7,376) (30,084) (c) (179,658) Transfers 60,404 929 30,690 895 (58,769) (34,149) - Cost at 31 December 2015 648,992 13,745 124,832 10,518 29,823 87,000 914,910 Additions (3,531) (a) 406 466 - 20,322 18,181 35,844 Currency translation differences 16,132 126 2,077 35 73 790 19,233 Disposals - (22) - - - - (22) Write-off / Impairment reversal 5,664 - - - - (31,366) (d) (25,702) Transfers 24,984 102 5,038 - (17,292) (12,832) - Cost at 31 December 2016 692,241 14,357 132,413 10,553 32,926 61,773 944,263 Additions 7,997 (a) 954 - - 66,953 49,455 125,359 Currency translation differences (1,142) (12) (147) (3) (62) (104) (1,470) Disposals - (112) - (189) - - (301) Write-off / Impairment reversal - - - - - (5,834) (e) (5,834) Transfers 77,408 211 25,130 - (61,827) (40,922) - Cost at 31 December 2017 776,504 15,398 157,396 10,361 37,990 64,368 1,062,017 Depreciation and write-down at 1 January 2015 (240,439) (4,449) (45,147) (2,244) - - (292,279) Depreciation (84,849) (2,850) (15,467) (874) - - (104,040) Disposals - 8 - 15 - - 23 Currency translation differences 4,115 (26) - (92) - - 3,997 Depreciation and write-down at 31 December 2015 (321,173) (7,317) (60,614) (3,195) - - (392,299) Depreciation (61,080) (2,702) (10,788) (920) - - (75,490) Disposals - 8 - - - - 8 Currency translation differences (2,486) (38) (296) (16) - - (2,836) Depreciation and write-down at 31 December 2016 (384,739) (10,049) (71,698) (4,131) - - (470,617) Depreciation (57,725) (1,948) (14,558) (844) - - (75,075) Disposals - 73 - 38 - - 111 Currency translation differences 930 8 24 5 - - 967 Depreciation and write-down at 31 December 2017 (441,534) (11,916) (86,232) (4,932) - - (544,614) Carrying amount at 31 December 2015 327,819 6,428 64,218 7,323 29,823 87,000 522,611 Carrying amount at 31 December 2016 307,502 4,308 60,715 6,422 32,926 61,773 473,646 Carrying amount at 31 December 2017 334,970 3,482 71,164 5,429 37,990 64,368 517,403 (a) (b) 53,764 53,523 64,094 Amounts in US$ '000 Total Exploration wells at 31 December 2015 22,906 Additions 15,088 Write-offs (19,949) Transfers (9,795) Exploration wells at 31 December 2016 8,250 Additions 35,299 Write-offs (3,664) Transfers (29,281) Exploration wells at 31 December 2017 10,604 As of 31 December 2017, there were two exploratory wells that have been capitalised for a period less than a year amounting to US$ 4,488 6,116 (d) (e)

Subsidiary undertakings

Subsidiary undertakings	12 Months Ended
	Dec. 31, 2017
Disclosure of subsidiary undertakings [Abstract]
Disclosure of interests in subsidiaries [text block]	Note 21 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2017 (a) (a) Non controlling interest held by LGI: · Consolidated Statement of Comprehensive Income: Total comprehensive income for the year 2017 include a profit of US$ 13,536 2,791 · Consolidated Statement of Financial Position: Total Equity as of 31 December 2017 includes US$ 29,330 16,168 15,953 22,082 · Consolidated Statement of Changes in Equity: Dividends distributed to non-controlling interest of US$ 479 6,406 Name and registered office Ownership interest Subsidiaries GeoPark Argentina Limited (Bermuda) 100% GeoPark Argentina Limited – Argentinean Branch 100% (a) GeoPark Latin America Limited (Bermuda) 100% GeoPark Latin America Limited – Agencia en Chile 100% (a) GeoPark S.A. (Chile) 100% (a) (b) GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil) 100% (a) GeoPark Chile S.A. (Chile) 80% (a) (c) GeoPark Fell S.p.A. (Chile) 80% (a) (c) GeoPark Magallanes Limitada (Chile) 80% (a) (c) GeoPark TdF S.A. (Chile) 68.8% (a) (d) GeoPark Colombia S.A. (Chile) 100% (a) (b) GeoPark Colombia SAS (Colombia) 80% (a) (c) GeoPark Latin America S.L.U. (Spain) 100% (a) GeoPark Colombia Coöperatie U.A. (The Netherlands) 80% (a) (c) GeoPark S.A.C. (Peru) 100% (a) GeoPark Perú S.A.C. (Peru) 100% (a) GeoPark Operadora del Perú S.A.C. (Peru) 100% (a) GeoPark Peru S.L.U. (Spain) 100% (a) GeoPark Brazil S.L.U. (Spain) 100% (a) GeoPark Colombia E&;P S.A.(Panama) 100% (a) (b) GeoPark Colombia E&;P Sucursal Colombia (Colombia) 100% (a) (b) GeoPark Mexico S.A.P.I. de C.V. (Mexico) 100% (b) Ogarrio E&;P S.A.P.I. de C.V. (Mexico) 51% (a) (b) GeoPark (UK) Limited (United Kingdom) 100% Joint operations Tranquilo Block (Chile) 50% (e) Flamenco Block (Chile) 50% (e) Campanario Block (Chile) 50% (e) Isla Norte Block (Chile) 60% (e) Yamu/Carupana Block (Colombia) 89.5%/100% (e) Llanos 34 Block (Colombia) 45% (e) Llanos 32 Block (Colombia) 12.5% CPO-4 Block (Colombia) 50% (e) Puelen Block (Argentina) 18% Sierra del Nevado Block (Argentina) 18% CN-V Block (Argentina) 50% (e) Manati Field (Brazil) 10% (a) Indirectly owned. (b) Dormant companies. (c) LG International has 20 (d) LG International has 20 14 31.2 (e) GeoPark is the operator. Corporate structure reorganization During 2017, the Company decided to incorporate a subsidiary in the United Kingdom to conduct the businesses in Latin America by adopting all the key resolutions and decisions necessary for such purpose. Also, a tax reform enacted in The Netherlands during September 2017 that would harm the Group´s cashflow, forced the Group to decide the re-domiciliation of its 100% owned Dutch subsidiaries to Spain.

Prepaid taxes

Prepaid taxes	12 Months Ended
	Dec. 31, 2017
Disclosure of Prepaid taxes [Abstract]
Disclosure of prepaid taxes [text block]	Note 22 Prepaid taxes Amounts in US$ '000 2017 2016 V.A.T. 27,674 14,052 Income tax payments in advance 1,258 4,517 Other prepaid taxes 939 98 Total prepaid taxes 29,871 18,667 Classified as follows: Current 26,048 15,815 Non current 3,823 2,852 Total prepaid taxes 29,871 18,667

Inventories

Inventories	12 Months Ended
	Dec. 31, 2017
Classes of current inventories [abstract]
Disclosure of inventories [text block]	Note 23 Inventories Amounts in US$ '000 2017 2016 Crude oil 1,969 1,521 Materials and spares 3,769 1,994 5,738 3,515

Trade receivables and Prepaymen

Trade receivables and Prepayments and other receivables	12 Months Ended
	Dec. 31, 2017
Trade and other receivables [abstract]
Disclosure of trade and other receivables [text block]	Note 24 Trade receivables and Prepayments and other receivables Amounts in US$ '000 2017 2016 Trade receivables 19,519 18,426 19,519 18,426 To be recovered from co-venturers (Note 33) 2,455 3,311 Related parties receivables (Note 33) 56 42 Prepayments and other receivables 5,242 4,290 7,753 7,643 Total 27,272 26,069 Classified as follows: Current 27,037 25,828 Non current 235 241 Total 27,272 26,069 Trade receivables that are aged by less than three months are not considered impaired. As of 31 December 2017 and 2016, there are no balances that were aged by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no balances overdue between 31 days and 90 days as of 31 December 2017 and 2016. Amounts in US$ '000 2017 2016 At 1 January 741 596 Foreign exchange (income) loss (147) 145 594 741 The credit period for trade receivables is 30 The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature.

Financial instruments by catego

Financial instruments by category	12 Months Ended
	Dec. 31, 2017
Financial Instruments [Abstract]
Disclosure of financial instruments [text block]	Note 25 Financial instruments by category Assets as per statement Amounts in US$ '000 of financial position 2017 2016 Loans and receivables Trade receivables 19,519 18,426 To be recovered from co-venturers (Note 33) 2,455 3,311 Other financial assets (a) 43,488 22,027 Cash and cash equivalents 134,755 73,563 200,217 117,327 (a) Non current other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations and also include a non current account receivable with the previous owners of one of the Colombian subsidiaries (see Note 28). Current other financial assets corresponds to the security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original maturities up to twelve months and over three months. Liabilities as per statement of financial position Amounts in US$ '000 2017 2016 Liabilities at fair value through profit and loss Derivative financial instrument liabilities 19,289 3,067 19,289 3,067 Other financial liabilities at amortised cost Trade payables 52,557 23,650 Payables to related parties (Note 33) 31,184 27,801 To be paid to co-venturers (Note 33) 10,015 1,614 Borrowings 426,204 358,672 519,960 411,737 Total financial liabilities 539,249 414,804 Credit quality of financial assets Amounts in US$ '000 2017 2016 Trade receivables Counterparties with an external credit rating (Moody’s) B2 70 7,056 Ba3 8,788 - Baa3 3,614 3,729 Counterparties without an external credit rating Group1 (a) 7,047 7,641 Total trade receivables 19,519 18,426 (a) Group 1 – existing customers (more than 6 months) with no defaults in the past. All trade receivables are denominated in US Dollars, except in Brazil where are denominated in Brazilian Real. Cash at bank and other financial assets (a) Amounts in US$ '000 2017 2016 Counterparties with an external credit rating (Moody’s, S&;P, Fitch, BRC Investor Services) A1 553 813 A2 298 - A3 63,853 - Aaa 15,040 - Aa3 11,401 42,798 AAA 19,634 14 B2 31 - Ba1 18 - Ba2 7 - Baa1 307 100 Baa2 4,078 4,094 Ba3 2,815 3,497 B3 - 10 BBB 15,064 - Counterparties without an external credit rating 45,123 44,252 Total 178,222 95,578 (a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21 12 Financial liabilities - contractual undiscounted cash flows Less than 1 Between 1 Between 2 Over 5 Amounts in US$ '000 year and 2 years and 5 years years At 31 December 2017 Borrowings 27,625 27,625 82,875 480,250 Trade payables 52,557 - - - Payables to related parties 7,331 2,068 27,087 - 87,513 29,693 109,962 480,250 At 31 December 2016 Borrowings 48,958 43,304 355,064 - Trade payables 23,650 - - - Payables to related parties 1,561 1,561 22,018 - 74,169 44,865 377,082 - Fair value measurement of financial instruments Accounting policies for financial instruments have been applied to classify as either: loans and receivables, held-to-maturity, available-for-sale, or fair value through profit and loss. For financial instruments that are measured in the statement of financial position at fair value, IFRS 13 requires a disclosure of fair value measurements by level according to the following fair value measurement hierarchy: Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices). Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs). This note provides an update on the judgements and estimates made by the Group in determining the fair values of the financial instruments since the last annual financial report. (a) Fair value hierarchy At 31 December Amounts in US$ '000 Level 2 2017 Liabilities Derivative financial instrument liabilities Commodity risk management contracts 19,289 19,289 Total Liabilities 19,289 19,289 At 31 December Amounts in US$ '000 Level 2 2016 Liabilities Derivative financial instrument liabilities Commodity risk management contracts 3,067 3,067 Total Liabilities 3,067 3,067 There were no transfers between Level 2 and 3 during the period. The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as at 31 December 2017. (b) Valuation techniques used to determine fair values Specific valuation techniques used to value financial instruments include: ⋅ The use of quoted market prices or dealer quotes for similar instruments. ⋅ The market-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. ⋅ The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the resulting fair value estimates are included in level 2. (c) Fair values of other financial instruments (unrecognised) The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest receivable/payable is either close to current market rates or the instruments are short-term in nature. Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short term portion where interest has already been fixed. They are classified under other financial liabilities and measured at their amortized cost. The fair value of these financial instruments at 31 December 2017 amounts to US$ 425,118,000 346,180,000 6.90 7.60

Share capital

Share capital	12 Months Ended
	Dec. 31, 2017
Disclosure Of Share capital [Abstract]
Disclosure of issued capital [text block]	Note 26 Share capital Issued share capital 2017 2016 Common stock (amounts in US$ ‘000) 61 60 The share capital is distributed as follows: Common shares, of nominal US$ 0.001 60,596,219 59,940,881 Total common shares in issue 60,596,219 59,940,881 Authorised share capital US$ per share 0.001 0.001 Number of common shares (US$ 0.001 each) 5,171,949,000 5,171,949,000 Amount in US$ 5,171,949 5,171,949 Details regarding the share capital of the Company are set out below: Common shares As of 31 December 2017, the outstanding common shares confer the following rights on the holder: · the right to one vote per share; · ranking pari passu Shares Shares issued closing US$(000) GeoPark common shares history Date (millions) (millions) Closing Shares outstanding at the end of 2015 59.5 59 Stock awards Feb 2016 0.4 59.9 60 Stock awards Dec 2016 0.5 60.4 60 Stock awards Dec 2016 0.1 60.5 60 Buyback program Dec 2016 (0.6) 59.9 60 Shares outstanding at the end of 2016 59.9 60 Stock awards Jan 2017 0.1 60.0 60 Stock awards Dec 2017 0.1 60.1 60 Stock awards Dec 2017 0.5 60.6 61 Shares outstanding at the end of 2017 60.6 61 Stock Award Program and Other Share Based Payments On 14 December 2017, 490,000 2,513 On 15 December 2016, 379,500 3,940 On 12 November 2015 and 22 December 2015, 817,600 478,000 11,359 3,577 In January 2017, 82,306 332 On 8 February 2016, 468,405 1,512 On 13 September 2017, 12,546 43 On 6 September 2016, 8,333 38 On 30 November 2015, 720,000 7,309 During 2017, the Company issued 70,485 137,897 99,555 257,000 541,848 486,692 Buyback Program On 19 December 2014, the Company approved a program to repurchase up to US$ 10,000,000 0.001 1,991,000 1,615,000

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2017
Disclosure Of Borrowings [Abstract]
Disclosure of borrowings [text block]	Note 27 Borrowings Amounts in US$ '000 2017 2016 Outstanding amounts as of 31 December 2024 Notes (a) 426,124 - Notes GeoPark Latin America Agencia en Chile (b) - 304,059 Banco Itaú (c) - 49,763 Banco de Chile (d) - 4,709 Banco de Crédito e Inversiones (e) 80 141 426,204 358,672 Classified as follows: Current 7,664 39,283 Non current 418,540 319,389 (a) During September 2017, the Company successfully placed US$ 425,000,000 The Notes carry a coupon of 6.50 6.90 3.5 2 The net proceeds from the Notes were used by the Company (i) to make a capital contribution to its wholly-owned subsidiary, GeoPark Latin America Limited Agencia en Chile (“GeoPark LA Agencia”), providing it with sufficient funds to fully repay the 7.50% senior secured notes due 2020 and to pay any related fees and expenses, including call premium, and (ii) for general corporate purposes, including capital expenditures and to repay existing indebtedness. (b) During February 2013, the Group successfully placed US$ 300,000,000 7.50 11 February 2020 (c) During March 2014, GeoPark executed a loan agreement with Itaú BBA International for US$ 70,450,000 10 (d) During December 2015, GeoPark executed a loan agreement with Banco de Chile for US$ 7,028,000 2.35 (e) During February 2016, GeoPark executed a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 4.14 As of the date of these Consolidated Financial Statements, the Group has available credit lines for over US$ 33,000,000

Provisions and other long-term

Provisions and other long-term liabilities	12 Months Ended
	Dec. 31, 2017
Disclosure Of Provisions and other long-term liabilities [Abstract]
Disclosure of provisions [text block]	Note 28 Provisions and other long-term liabilities Amounts in US$ ‘000 Asset retirement Deferred Other Total At 1 January 2016 31,617 5,033 5,800 42,450 Addition to provision 1,195 1,375 2,686 5,256 Recovery of abandonments costs (5,504) - - (5,504) Exchange difference (1,614) - 538 (1,076) Foreign currency translation 1,614 - - 1,614 Amortisation - (2,924) - (2,924) Unwinding of discount 2,554 - 139 2,693 At 31 December 2016 29,862 3,484 9,163 42,509 Addition to provision 5,943 - 2,220 8,163 Exchange difference 134 - 1,154 1,288 Foreign currency translation (134) - - (134) Amortisation - (657) - (657) Unwinding of discount 2,607 - 172 2,779 Unused amounts reversed - - (2,535) (2,535) Amounts used during the year (337) (1,375) (3,417) (5,129) At 31 December 2017 38,075 1,452 6,757 46,284 The provision for asset retirement obligation relates to the estimation of future disbursements related to the abandonment and decommissioning of oil and gas wells (see Note 4). Deferred income relates to contributions received to improve the project economics of the gas wells in Chile. The amortisation is in line with the related asset. The addition in 2016 and the amounts used in 2017 correspond to the deferred income related to the take or pay provision associated to gas sales in Brazil. As of 31 December 2016, Other included a provision for an amount of US$ 5,636,000 3,389,000

Trade and other payables

Trade and other payables	12 Months Ended
	Dec. 31, 2017
Disclosure Of Trade and other payables [Abstract]
Disclosure of trade and other payables [text block]	Note 29 Trade and other payables Amounts in US$ '000 2017 2016 V.A.T 1,118 1,102 Trade payables 52,557 23,650 Payables to related parties (a) 31,184 27,801 Customer advance payments (Note 3) 10,000 20,000 Staff costs to be paid 9,143 7,749 Royalties to be paid 4,110 1,503 Taxes and other debts to be paid 4,191 3,355 To be paid to co-venturers (Note 33) 10,015 1,614 122,318 86,774 Classified as follows: Current 96,397 52,008 Non current 25,921 34,766 (a) July 2020 8 The average credit period (expressed as creditor days) during the year ended 31 December 2017 was 95 83 The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value.

Share-based payment

Share-based payment	12 Months Ended
	Dec. 31, 2017
Disclosure Of Share-based Payment [Abstract]
Disclosure of share-based payment arrangements [text block]	Note 30 Share-based payment IPO Award Program and Executive Stock Option plan The Group has established different stock awards programs and other share-based payment plans to incentivise the Directors, senior management and employees, enabling them to benefit from the increased market capitalisation of the Company. Stock Award Program and Other Share Based Payments During 2008, GeoPark Shareholders voted to authorize the Board to use up to 12 During 2016, the Group approved a share-based compensation program for 1,619,105 · All employees are eligible. · Exercise price is equal to the nominal value of shares. · Vesting period is three years. · Each employee could receive up to three salaries by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should be above US$ 3 Also during 2016, the Group approved a plan named Value Creation Plan (“VCP”) oriented to Top Management. Main characteristics of the VCP are: · Awards payables in a variable number of shares which shall not exceed the quantity of 2,976,781 · Subject to certain market conditions, among others, reaching a stock market price for the Company shares of US$ 4.05 · Vesting date: VCP has been classified as an equity-settled plan. Awards Awards at granted Awards the in the Awards Awards at year Charged to net loss / profit Year of issuance beginning year forfeited exercised end 2017 2016 2015 2016 1,619,105 - 31,109 - 1,587,996 865 445 - 2014 490,000 - - 490,000 - 838 821 898 2013 - - - - - - - 594 2012 - - - - - - 855 636 2011 - - - - - - - 879 Subtotal 1,703 2,121 3,007 Stock options to Executive Directors - - - - - - - 2,390 Shares granted to Non-Executive Directors - 70,485 70,485 454 400 371 VCP 2013 - - - - - - - 617 VCP 2016 - - - - - 1,868 934 - Executive Directors Bonus - - - - - - (325) 400 Key Management Bonus 82,306 - - 82,306 - - 202 1,438 Stock awards for service contracts - 12,546 - 12,546 - 50 35 - 2,191,411 83,031 31,109 655,337 1,587,996 4,075 3,367 8,223 The awards that are forfeited correspond to employees that had left the Group before vesting date.

Interests in Joint operations

Interests in Joint operations	12 Months Ended
	Dec. 31, 2017
Disclosure Of Interests in Joint operations [Abstract]
Disclosure of interests in joint arrangements [text block]	Note 31 Interests in Joint operations The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina. In Chile, GeoPark is the operator in all the blocks. In Colombia, GeoPark is the operator in Llanos 34 and Yamu/Carupana blocks. In Argentina, GeoPark is the operator in CN-V block. PP&;E Operating Subsidiary / E&;E Other Total Total NET ASSETS/ (loss) Joint operation Interest Assets Assets Assets Liabilities (LIABILITIES) Revenue profit 2017 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 55 55 (432) (377) - (48) GeoPark TdF S.A. Flamenco Block 50 % 9,893 - 9,893 (1,223) 8,670 879 (1,422) Campanario Block 50 % 17,347 - 17,347 (233) 17,114 - (150) Isla Norte Block 60 % 9,553 - 9,553 (60) 9,493 - (161) Colombia SAS Yamu/Carupana Block 89.5 % 4,741 1 4,742 (2,993) 1,749 3,072 (2,721) Llanos 34 Block 45 % 131,193 4,563 135,756 (5,847) 129,909 259,815 163,917 Llanos 32 Block 12.5 % 835 209 1,044 (492) 552 1,784 (319) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 44,167 19,126 63,293 (11,444) 51,849 34,238 12,731 POT-T-747 70 % 849 358 1,207 (1,091) 116 - - GeoPark Argentina Limited – Argentinean Branch CN-V Block 50 % 6,819 347 7,166 (984) 6,182 70 (1,163) Puelen Block 18 % 1,318 72 1,390 (232) 1,158 - (546) Sierra del Nevado Block 18 % 568 169 737 (837) (100) - (474) PP&;E Operating Subsidiary / E&;E Other Total Total NET ASSETS/ (loss) Joint operation Interest Assets Assets Assets Liabilities (LIABILITIES) Revenue profit 2016 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 55 55 (424) (369) - (40) GeoPark TdF S.A. Flamenco Block 50 % 15,108 - 15,108 (93) 15,015 1,004 (1,988) Campanario Block 50 % 29,718 - 29,718 (1) 29,717 - (399) Isla Norte Block 60 % 9,920 - 9,920 (1) 9,919 5 (438) Colombia SAS Yamu/Carupana Block 89.5 % 3,418 - 3,418 (2,289) 1,129 18 (307) Llanos 34 Block 45 % 79,811 693 80,504 (3,943) 76,561 125,400 83,193 Llanos 32 Block 10 % 3,819 - 3,819 (211) 3,608 2,303 1,043 GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 54,166 15,791 69,957 (8,442) 61,515 29,719 20,945 2015 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 45 45 (2) 43 - (69) GeoPark TdF S.A. Flamenco Block 50 % 14,932 - 14,932 (53) 14,879 1,810 (51,411) Campanario Block 50 % 27,570 - 27,570 (10) 27,560 13 (7,267) Isla Norte Block 60 % 8,583 - 8,583 (16) 8,567 355 (5,661) Colombia SAS Llanos 17 Block 36.84 % - - - (93) (93) 3 (6,325) Yamu/Carupana Block 89.5 % 3,569 2,061 5,630 (2,235) 3,395 1,409 (16,552) Llanos 34 Block 45 % 76,667 429 77,096 (3,295) 73,801 114,276 53,049 Llanos 32 Block 10 % 3,106 96 3,202 (213) 2,989 8,258 (1,343) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 50,801 12,930 63,731 (10,395) 53,336 32,388 20,354 Capital commitments are disclosed in Note 32 (b).

Commitments

Commitments	12 Months Ended
	Dec. 31, 2017
Disclosure Of Commitments [Abstract]
Disclosure of commitments [text block]	Note 32 Commitments (a) Royalty commitments In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using a level of production sliding scale at a rate which ranges between 6 8 1 Average daily production in barrels Production Royalty rate Up to 5,000 8% 5,000 to 125,000 8% + (production - 5,000)*0.1 125,000 to 400,000 20% 400,000 to 600,000 20% + (production - 400,000)*0.025 Greater than 600,000 25% When the API is lower than 15°, the payment is reduced to the 75% of the total calculation. In accordance with Llanos 34 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI exceeds the base price settled in table A, the Group should deliver to ANH a share of the production net of royalties in accordance with the following formula: Q = ((P – Po) / P) x S; where Q = Economic right to be delivered to ANH, P = WTI, Po = Base price (see table A) and S = Share (see table B). Table A Table B °API Po (US$/barrel) WTI (P) S >29° 30.22 Po < P < 2Po 30 % >22°<29° 31.39 2Po < P < 3Po 35 % >15°<22° 32.56 3Po < P < 4Po 40 % >10°<15° 46.50 4Po < P < 5Po 45 % 5Po < P 50 % Additionally, under the terms of the Winchester Stock Purchase Agreement, GeoPark is obligated to make certain payments to the previous owners of Winchester based on the production and sale of hydrocarbons discovered by exploration wells drilled after 25 October 2011. These payments involve an overriding royalty equal to an estimated 4 80,000,000 90,000,000 11,369,000 5,414,000 7,100,000 9,981,000 3,772,000 9,200,000 In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties are calculated at 5 3 5 In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5 10 7.5 In Argentina, crude oil production accrues royalties payable to the Province of Mendoza equivalent to 12 (b) Capital commitments Colombia The VIM 3 Block minimum investment program consists of 200 sq km of 2D seismic and drilling one exploratory well, with a total estimated investment of US$ 22,290,800 The Llanos 34 Block ( 45 6,255,000 3,008,000 The Llanos 32 Block ( 12 587,500 Argentina On 20 August 2014, the consortium of GeoPark and Pluspetrol was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina de Energia S.A. ("EMESA"). The consortium consists of Pluspetrol (Operator with a 72 10 18 1,200,000 On 22 July 2015, GeoPark signed a farm-in agreement with Wintershall for the CN-V Block in Argentina. GeoPark will operate during the exploratory phase and receive a 50 10,000,000 5,455,000 Chile The remaining investment commitment for the second exploratory phase in the Flamenco Block relates to the drilling of one exploratory well to be assumed 100 2,100,000 The investment commitment for the first exploratory period in the Campanario and Isla Norte Blocks has already been fulfilled. The investments to be made in the second exploratory period will be assumed 100 · Campanario Block: 3 exploratory wells before 10 July 2019 (US$ 4,758,000 · Isla Norte Block: 2 exploratory wells before 7 May 2019 (US$ 2,855,000 As of 31 December 2017, the Group has established guarantees for its total commitments. Brazil The future investment commitments assumed by GeoPark are up to: · SEAL-T-268 Block: before 15 May 2017 (US$ 230,000 · REC-T-94 Block: 2 exploratory wells before 12 July 2017 (US$ 2,300,000 · REC-T-93 Block: 3D seismic before 20 December 2018 (US$ 50,000 · REC-T-128 Block: 1 exploratory well before 20 December 2018 (US$ 2,690,000 · POT-T-747 Block: 1 exploratory well before 20 December 2018 (US$ 1,840,000 · POT-T-882 Block: 35 sq km of 2D seismic before 20 December 2018 (US$ 480,000 · POT-T-619 Block: 1 well before 16 September 2018 (US$ 700,000 (c) Operating lease commitments – Group company as lessee The Group leases various plant and machinery under non-cancellable operating lease agreements. The Group also leases offices under non-cancellable operating lease agreements. The lease terms are between 2 and 3 years, and most of lease agreements are renewable at the end of the lease period at market rate. During 2017 a total amount of US$ 46,195,000 47,871,000 16,731,000 34,160,000 32,058,000 7,102,000 Amounts in US$ ’000 2017 2016 2015 Operating lease commitments Falling due within 1 year 32,180 67,752 12,878 Falling due within 1 – 3 years 5,777 14,031 8,257 Falling due within 3 – 5 years 2,793 5,066 2,456 Falling due over 5 years - 114 309 Total minimum lease payments 40,750 86,963 23,900

Related parties

Related parties	12 Months Ended
	Dec. 31, 2017
Disclosure Of Related Parties [Abstract]
Disclosure of related party [text block]	Note 33 Related parties Controlling interest Common Percentage of outstanding Shareholder shares common shares James F. Park (a) 7,891,269 13.02 % Gerald E. O’Shaughnessy (b) 7,193,316 11.87 % Manchester Financial Group, LP 5,103,439 8.42 % IFC Equity Investments (c) 3,422,476 5.65 % Juan Cristóbal Pavez (d) 2,961,520 4.89 % Other shareholders 34,024,199 56.15 % 60,596,219 100.00 % (a) Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of our Board of Directors. (b) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, and other investment vehicles. (c) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff. (d) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 83,716 Balances outstanding and transactions with related parties Balances Transaction in at year Account (Amounts in ´000) the year end Related Party Relationship 2017 To be recovered from co-venturers - 2,455 Joint Operations Joint Operations Prepayments and other receivables - 56 LGI Partner Payables account - (31,184) LGI Partner To be paid to co-venturers - (10,015) Joint Operations Joint Operations Financial results 2,224 - LGI Partner Geological and geophysical expenses 170 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 411 - Pedro Aylwin Executive Director (b) 2016 To be recovered from co-venturers - 3,311 Joint Operations Joint Operations Prepayments and other receivables - 42 LGI Partner Payables account - (27,801) LGI Partner To be paid to co-venturers - (1,614) Joint Operations Joint Operations Financial results 1,587 - LGI Partner Geological and geophysical expenses 113 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 371 - Pedro Aylwin Executive Director (b) 2015 To be recovered from co-venturers - 4,634 Joint Operations Joint Operations Prepayments and other receivables - 38 LGI Partner Payables account - (21,045) LGI Partner To be paid to co-venturers - (113) Joint Operations Joint Operations Financial results 1,560 - LGI Partner Geological and geophysical expenses 101 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 66 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 377 - Pedro Aylwin Executive Director (b) (a) Corresponding to consultancy services. (b) Corresponding to wages and salaries for US$ 271,000 246,000 317,000 140,000 125,000 60,000 There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11.

Fees paid to Auditors

Fees paid to Auditors	12 Months Ended
	Dec. 31, 2017
Auditor's remuneration [abstract]
Disclosure of auditors' remuneration [text block]	Note 34 Fees paid to Auditors Amounts in US$ '000 2017 2016 2015 Audit fees 726 487 557 Audit related fees 137 - - Tax services fees 212 134 129 Non-audit services fees 39 - - Fees paid to auditors 1,114 621 686 Non-audit services fees relate to consultancy and other services for 2017.

Business transactions

Business transactions	12 Months Ended
	Dec. 31, 2017
Disclosure Of Business transactions [Abstract]
Disclosure Of Business Transactions Explanatory [Text Block]	Note 35 Business transactions a. Peru Entry in Peru The Group has executed a Joint Investment Agreement and Joint Operating Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in and operate the Morona Block located in northern Peru. GeoPark will assume a 75 25 The Morona Block, also known as Lote 64, covers an area of 1.9 In accordance with the terms of the agreement, GeoPark has committed to carry Petroperu on a work program that provides for testing and start-up production of one of the existing wells in the field, subject to certain technical and economic conditions being met. During 2017, GeoPark recognised an initial consideration owed to Petroperu that could be up to US$ 10,684,000 b. Colombia Swap operation On 19 November 2015, the Colombian subsidiary agreed to exchange its 10 10 Following this transaction, GeoPark continued to be the operator and have an 89.5 100 296,000 Acquisition of Tiple Block GeoPark executed a joint operation agreement related to certain exploration activities in a new high-potential exploration acreage (“Tiple Block Acreage”) in the Llanos Basin in Colombia, through a partnership with CEPSA Colombia S.A. (a subsidiary of CEPSA SAU, the Spanish integrated energy and petrochemical company). The Tiple Block Acreage is located adjacent to GeoPark’s Llanos 34 Block (GeoPark operated, 45 21,000 The agreement provides for GeoPark to drill one exploration well, which is scheduled to be drilled in the first half of 2018. The total estimated investment amounts to between US$ 7,000,000 8,000,000 Incremental interest in Llanos 32 Block On 22 August 2017, GeoPark acquired an additional 2.5 Zamuro Farm-in agreement GeoPark executed a farm-in agreement to drill the Zamuro exploration prospect, which is located in the Llanos 32 block (GeoPark non-operated, 12.5 56.25 c. Argentina Acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet blocks On 18 December 2017, GeoPark executed an asset purchase agreement to acquire a 100 52,000,000 As of the date of these Consolidated Financial Statements, GeoPark has recorded the security deposit of US$ 15,600,000

Impairment test on Property, pl

Impairment test on Property, plant and equipment	12 Months Ended
	Dec. 31, 2017
Disclosure of impairment of assets [Abstract]
Disclosure of impairment of assets [text block]	Note 36 Impairment test on Property, plant and equipment Oil price crisis started in the second half of 2014 and prices fell dramatically, WTI and Brent, the main international oil price markers, fell more than 60% between October 2014 and February 2016. Because of those market conditions, during 2015, the Group undertook a decisive cost cutting program to ensure its ability to both maximize the work program and preserve its liquidity. The main decisions included: - Reduction of its capital investment taking advantage of the discretionary work program. - Deferment of capital projects by regulatory authority and partner agreement. - Renegotiation and reduction of oil and gas service contracts, including drilling and civil work contractors, as well as transportation trucking and pipeline costs. - Operating cost improved efficiencies and temporary suspension of certain marginal producing oil and gas fields. During February 2015, the Group reduced its workforce significantly. This reduction streamlined certain internal functions and departments for creating a more efficient workforce in the current economic environment. As a result, the Group achieved cost savings associated with the reduction of full-time and temporary employees, excluding one-time termination costs. Continuous efforts and actions to reduce costs and preserve liquidity have continued since. As a result of the situation described, the Group recognised an impairment loss of US$ 149,574,000 The Management of the Group considers as Cash Generating Unit (CGU) each of the blocks in which the Group has working or economic interests. The blocks with no material investment on fixed assets or with operations that are not linked to oil prices were not subject to impairment test. During 2016 and 2017 the impairment tests were reviewed. The main assumptions taken into account for the impairment tests for the blocks below mentioned were: - The future oil prices have been calculated taking into consideration the oil curves prices available in the market, provided by international advisory companies, weighted through internal estimations in accordance with price curves used by D&;M; - Three price scenarios were projected and weighted in order to minimize misleading: low price, middle price and high price (see below table “Oil price scenarios”); - The table “Oil price scenarios” was based on Brent future price estimations; the Group adjusted this marker price on its model valuation to reflect the effective price applicable in each location (see Note 3 “Price risk”); - The model valuation was based on the expected cash flow approach; - The revenues were calculated linking price curves with levels of production according to certified reserves (see below table “Oil price scenarios”); - The levels of production have been linked to certified risked 1P, 2P and 3P reserves (see Note 4); - Production and structure costs were estimated considering internal historical data according to GeoPark’s own records and aligned to 2018 approved budget; - The capital expenditures were estimated considering the drilling campaign necessary to develop the certified reserves; - The assets subject to impairment test are the ones classified as Oil and Gas properties and Production facilities and machinery; - The carrying amount subject to impairment test includes mineral interest, if any; - The income tax charges have considered future changes in the applicable income tax rates (see Note 16). (a) Amounts in US$ per Bbl. Weighted market price used for the Year Low price (15%) Middle price (60%) High price (25%) impairment test 2018 64.9 64.9 64.9 64.9 2019 53.2 62.5 71.7 63.4 2020 54.4 63.9 73.4 64.9 Over 2021 54.3 63.7 73.2 64.7 (a) The percentages indicated between brackets represent the Group estimation regarding each price scenario. As a consequence of the evaluation no additional impairment loss was recognised in 2017. In 2016, part of the impairment recorded in Colombia was reversed for an amount of US$ 5,664,000

Supplemental information on oil

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. 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 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 45,059,000 Table 3 - Results of operations for oil and gas producing activities 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. As of 31 December 2017 As of 31 December 2016 As of 31 December 2015 Oil and Natural gas Oil and Natural gas Oil and Natural gas 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 99 91 20 2 1 9 31.2 (b) Llanos 34 Block, Cuerva Block and Yamu Block account for 98 1 1 99 1 94 3 20 (c) BCAM-40 Block accounts for 100 (d) Morona Block accounts for 100 (e) Fell Block accounts for 97 99 100 20 3 1 31.2 (f) Llanos 34, Cuerva Block and Yamu Block account for 97 2 1 100 95 4 20 The amounts of proved reserves disclosed herein as of 31 December 2017 include 13,934.1 8,796.2 7,281.3 4,101.5 7,356.0 7,345.8 Table 5 - Net proved reserves of oil, condensate and natural gas 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 - The impact of lower average oil prices resulting in a 2 1 - 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 - Better than expected performance from existing wells, resulting in an increase of 9 8 1 - Such increase was partially offset by lower average oil prices impacting the La Cuerva and Yamu blocks in Colombia, resulting in a 2 (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 - 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 - The impact of higher average oil prices resulting in a 2.5 0.4 - 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 (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 - Better than expected performance from existing wells that resulted in an increase of 13 3 10 - 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 9 4 (d) For the year ended 31 December 2017, the Group’s proved natural gas reserves were revised downwards by 13.7 - 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 - The above was partially offset by an increase of 6.8 0.8 (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 61.4 73.9

Summary of significant accoun44

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Summary of significant accounting policies [Abstract]
Disclosure of basis of preparation of financial statements [text block]	2.1 The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost convention. The Consolidated Financial Statements are presented in thousands of United States Dollars (US$'000) and all values are rounded to the nearest thousand (US$'000), except in the footnotes and where otherwise indicated. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”. All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise indicated.
Disclosure of Accounting Policy for New and Amended Standards Adopted [Text Block]	New and amended standards adopted by the Group ⋅ Recognition of Deferred Tax Assets for Unrealised Losses – Amendments to IAS 12 ⋅ Disclosure initiative – Amendments to IAS 7 The adoption of these amendments did not have any impact on the current period or any prior period and is not likely to affect future periods. New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2017 and not early adopted. ⋅ IFRS 2 Share based payments: amended in June 2016 to clarify the measurement basis for cash-settled share-based payments and the accounting for modifications that change an award from cash-settled to equity-settled. It also introduces an exception to IFRS 2 principles by requiring an award to be treated as if it was wholly equity-settled, where an employer is obliged to withhold an amount for the employee’s tax obligation associated with a share-based payment and pay that amount to the tax authority. It is effective for annual periods beginning on or after January 1, 2018. The Group estimates that these amendments will not have a material impact on the Group’s operating results or financial position. ⋅ IFRS 9 Financial Instruments and associated amendments to various other standards: IFRS 9 replaces the multiple classification and measurement models in IAS 39. Classification of debt assets will be driven by the entity’s business model for managing the financial assets and the contractual cash flow characteristics of the financial assets. A debt instrument is measured at amortised cost if: a) the objective of the business model is to hold the financial asset for the collection of the contractual cash flows, and b) the contractual cash flows under the instrument solely represent payments of principal and interest. All other debt and equity instruments, including investments in complex debt instruments and equity investments, must be recognised at fair value. All fair value movements on financial assets are taken through the statement of profit or loss, except for equity investments that are not held for trading, which may be recorded in the statement of profit or loss or in reserves (without subsequent recycling to profit or loss). For financial liabilities that are measured under the fair value option entities will need to recognise the part of the fair value change that is due to changes in their own credit risk in other comprehensive income rather than profit or loss. The new hedge accounting rules (released in December 2013) align hedge accounting more closely with common risk management practices. As a general rule, it will be easier to apply hedge accounting going forward. The new impairment model under IFRS 9 requires the recognition of impairment provisions based on expected credit losses rather than only incurred credit losses as is the case under IAS 39. It applies to financial assets classified at amortised cost, debt instruments measured at fair value through other comprehensive income, contract assets under IFRS 15, lease receivables, loan commitments and certain financial guarantee contracts. The new standard also introduces expanded disclosure requirements and changes in presentation. Management has assessed the effects of applying the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected. ⋅ IFRS 15 Revenue from contracts with customers and associated amendments to various other standards: The IASB has issued a new standard for the recognition of revenue. This will replace IAS 18 which covers contracts for goods and services and IAS 11 which covers construction contracts. The new standard is based on the principle that revenue is recognised when control of a good or service transfers to a customer so the notion of control replaces the existing notion of risks and rewards. These accounting changes may have flow-on effects on the entity’s business practices regarding systems, processes and controls, compensation and bonus plans, contracts, tax planning and investor communications. Entities will have a choice of full retrospective application, or prospective application with additional disclosures. It is mandatory for financial years commencing on or after 1 January 2018. The Group intends to adopt the standard using the modified retrospective approach which means that the cumulative impact of the adoption will be recognised in retained earnings as of 1 January 2018 and that comparatives will not be restated. Management has assessed the effects of applying the new standard on the Group’s Consolidated Financial Statements and concluded that no material impact will be expected. ⋅ IFRS 16 Leases: will affect primarily the accounting by lessees and will result in the recognition of almost all leases on balance sheet. The standard removes the current distinction between operating and financing leases and requires recognition of an asset (the right to use the leased item) and a financial liability to pay rentals for virtually all lease contracts. An optional exemption exists for short-term and low-value leases. The accounting by lessors will not significantly change. Some differences may arise as a result of the new guidance on the definition of a lease. The Group has not yet determined to what extent its commitments will result in the recognition of an asset and a liability for future payments and how this will affect the Group’s profit and classification of cash flows. Some of the commitments may be covered by the exception for short-term and low-value leases and some commitments may relate to arrangements that will not qualify as leases under IFRS 16. At this stage, the Group does not intend to adopt the standard before its effective date. The Group intends to apply the simplified transition approach and will not restate comparative amounts for the year prior to first adoption. ⋅ IFRIC 22 Foreign Currency Transactions and Advance Consideration: issued in December 2016. The interpreta-tion addresses how to determine the date of the transaction for the purpose of determining the exchange rate to use on initial recognition of the related asset, expense or income related to an entity that has received or paid an advance consideration in a foreign currency. The date of the transaction is the date on which an entity initially rec-ognises the non-monetary asset or non-monetary liability arising from the payment or receipt of advance consid-eration. It is effective for annual periods beginning on January 1, 2018. The Group estimates that these interpreta-tions will not have a material impact on the Group’s operating results or financial position. ⋅ Sale or contribution of assets between an investor and its associate or joint venture – Amendments to IFRS 10 and IAS 28: The amendments clarify the accounting treatment for sales or contribution of assets between an investor and its associates or joint ventures. ⋅ Improvements to IFRSs – 2014-2016 Cycle: amendments issued in December 2016 that are effective for periods beginning on or after January 1, 2018. The Group estimates that these amendments will not have an impact on the Group’s operating results or financial position. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.
Disclosure of going concern [text block]	2.2 The Directors regularly monitor the Group's cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecast operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches. Considering macroeconomic environment conditions, the performance of the operations, the US$ 425,000,000 99
Disclosure of basis of consolidation [text block]	2.3 Consolidation Subsidiaries are all entities (including structured entities) over which the group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred by the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred. The excess of the consideration transferred, the amount of any non-controlling interest in the acquired entity, and the acquisition-date fair value of any previous equity interest in the acquired entity over the fair value of the identifiable net assets acquired is recorded as goodwill. If the total of consideration transferred, non-controlling interest recognised and previously held interest measured is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognised directly in the income statement. Intercompany transactions, balances and unrealised gains on transactions between the Group and its subsidiaries are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group.
Description of accounting policy for segment reporting [text block]	2.4 Segment reporting Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and People departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports.
Description of accounting policy for foreign currency translation [text block]	2.5 Foreign currency translation a) Functional and presentation currency The Consolidated Financial Statements are presented in US Dollars, which is the Group’s presentation currency. Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Chile, Colombia, Peru and Argentina is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the Brazilian Real. b) Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Consolidated Statement of Income.
Description of accounting policy for investments in joint arrangements [Text Block]	Under IFRS 11 investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined them to be joint operations. The Group combines its share in the joint operations individual assets, liabilities, results and cash flows on a line-by-line basis with similar items in its financial statements.
Description of accounting policy for recognition of revenue [text block]	2.7 Revenue recognition Revenue from the sale of crude oil and gas is recognised in the Consolidated Statement of Income when risk is transferred to the purchaser, and if the revenue can be measured reliably and is expected to be received. Revenue is shown net of VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. See Note 32 (a).
Description Of Accounting Policy For Production And Operating Costs [text block]	2.8 Production and operating costs Production costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, leasing and royalties are also included within this account.
DescriptionOfAccountingPolicyForFinanceIncomeAndCostsExplanatory [Text Block]	Financial results include interest expenses, interest income, bank charges, the amortisation of financial assets and liabilities, and foreign exchanges gain and losses. The Group has capitalised borrowing cost for wells and facilities that were initiated after 1 January 2009. The capitalisation rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s general borrowings during the year, which was 6.90 7.98 amounted to 610,841 254,950 637,390
Description of accounting policy for property, plant and equipment [text block]	2.10 Property, plant and equipment Property, plant and equipment are stated at historical cost less depreciation and impairment charge, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation. Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalising exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income. Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of exploratory wells. No depreciation and/or amortisation are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which the determination is made depending whether they have found reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. A charge of US$ 5,834 31,366 30,084 All field development costs are considered construction in progress until they are finished and capitalised within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties. Workovers of wells made to develop reserves and/or increase production are capitalised as development costs. Maintenance costs are charged to the Consolidated Statement of Income when incurred. Capitalised costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs and is based on current year end unescalated price levels. Changes in reserves and cost estimates are recognised prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. Depreciation of the remaining property, plant and equipment assets (i.e. furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between 3 years 10 years Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow up the performance of the business. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.12).
Description of accounting policy for provisions [text block]	Provisions for asset retirement obligations, deferred income, restructuring obligations and legal claims are recognised when the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to the passage of time is recognised as financial expense. The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded, the Group capitalises the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalised cost is depreciated over the estimated useful life of the related asset. According to interpretations and application of current legislation and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are included in the financial statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset. Relates to contributions received in cash from the Group’s clients to improve the project economics of gas wells. The amounts collected are reflected as a deferred income in the balance sheet and recognised in the Consolidated Statement of Income over the productive life of the associated wells. The depreciation of the gas wells that generated the deferred income is charged to the Consolidated Statement of Income simultaneously with the amortisation of the deferred income. The addition in 2016 and the amounts used in 2017 correspond to the deferred income related to the take or pay provision associated to gas sales in Brazil.
Description of accounting policy for impairment of non-financial assets [text block]	2.12 Impairment of non-financial assets Assets that are not subject to depreciation and/or amortisation (i.e.: exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation and/or amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date. No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable. During 2017, no impairment loss was recognised (impairment loss reversed for US$ 5,664,000 149,574,000
Description of accounting policy for leases [text block]	2.13 Lease contracts All current lease contracts are considered to be operating leases on the basis that the lessor retains substantially all the risks and rewards related to the ownership of the leased asset. Payments related to operating leases and other rental agreements are recognised in the Consolidated Income Statement on a straight line basis over the term of the contract. The Group's total commitment relating to operating leases and rental agreements is disclosed in Note 32. Leases in which substantially all of the risks and rewards of ownership are transferred to the lessee are classified as finance leases. Under a finance lease, the Group as lessor has to recognise an amount receivable equal to the aggregate of the minimum lease payments plus any unguaranteed residual value accruing to the lessor, discounted at the interest rate implicit in the lease.
Description of accounting policy for measuring inventories [text block]	2.14 Inventories Inventories comprise crude oil and materials. Crude oil is measured at the lower of cost and net realisable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method.
Description of accounting policy for deferred income tax [text block]	2.15 Current and deferred income tax The tax expense for the year comprises current and deferred tax. Tax is recognised in the Consolidated Statement of Income. The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the balance sheet date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted as of the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. In addition, the Group has tax-loss carry-forwards in certain taxing jurisdictions that are available to be offset against future taxable profit. However, deferred tax assets are recognised only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. Deferred income tax liabilities are provided on taxable temporary differences arising from investments in subsidiaries and joint arrangements, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred tax is recognised in respect of the retained earnings of overseas subsidiaries only if at the date of the statements of financial position, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future. In the event that these differences revert in total (e.g. dividends are declared and paid), the deferred tax liability which the Group would have to recognise amounts to approximately US$ 12,300 Deferred tax balances are provided in full, with no discounting.
Description of accounting policy for financial assets [text block]	2.16 Financial assets Financial assets are divided into the following categories: loans and receivables; financial assets at fair value through profit or loss; available-for-sale financial assets; and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial recognition, depending on the purpose for which the investments were acquired. The designation of financial assets is re-evaluated at every reporting date at which a choice of classification or accounting treatment is available. All financial assets are recognised when the Group becomes a party to the contractual provisions of the instrument. All financial assets are initially recognised at fair value, plus transaction costs. Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date. Interest and other cash flows resulting from holding financial assets are recognised in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured. Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. The Group’s loans and receivables comprise trade receivables, prepayments and other receivables and cash and cash equivalents in the balance sheet. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. Loans and receivables are subsequently measured at amortised cost using the effective interest method, less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Statement of Income. All of the Group’s financial assets are classified as loan and receivables.
Description Of Accounting Policy For Other Financial Assets [text block]	2.17 Other financial assets Non current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes. Current other financial assets include the security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original maturities up to twelve months and over three months.
Description of accounting policy for impairment of financial assets [text block]	2.18 Impairment of financial assets Provision against trade receivables is made when objective evidence is received that the Group will not be able to collect all amounts due to it in accordance with the original terms of those receivables. The amount of the write-down is determined as the difference between the asset's carrying amount and the present value of estimated future cash flows.
Description of accounting policy for determining components of cash and cash equivalents [text block]	2.19 Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position.
Description of accounting policy for trade and other payables [text block]	2.20 Trade and other payables Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.
Description of accounting policy for derivative financial instruments [text block]	2.21 Derivatives Derivative financial instruments are recognised in the statement of financial position as assets or liabilities and initially and subsequently measured at fair value through profit and loss. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period. The market-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. Gains and losses arising from changes in fair value are recognised in the Consolidated Statement of Income within Commodity risk management contracts. For more information about derivatives please refer to Note 8.
Description of accounting policy for borrowings [text block]	2.22 Borrowings Borrowings are obligations to pay cash and are recognised when the Group becomes a party to the contractual provisions of the instrument. Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the Consolidated Statement of Income over the period of the borrowings using the effective interest method. Direct issue costs are charged to the Consolidated Statement of Income on an accruals basis using the effective interest method.
Description of accounting policy for issued capital [text block]	2.23 Share capital Equity comprises the following: ⋅ "Share capital" representing the nominal value of equity shares. ⋅ "Share premium" representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issuance. ⋅ "Other reserve" representing: - the equity element attributable to shares granted according to IFRS 2 but not issued at year end or, - the difference between the proceeds from the transaction with non-controlling interests received against the book value of the shares acquired in the Chilean and Colombian subsidiaries. ⋅ "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries. ⋅ "(Accumulated losses) Retained earnings" representing accumulated earnings and losses.
Description of accounting policy for share-based payment transactions [text block]	2.24 Share-based payment The Group operates a number of equity-settled and cash-settled share-based compensation plans comprising share awards payments to certain employees and other third party contractors. Share-based payment transactions are measured in accordance with IFRS 2. Fair value of the stock option plan for employee or contractors services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted calculated using the Geometric Brownian Motion method. Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At each balance sheet date, the entity revises its estimates of the number of options that are expected to vest. It recognises the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment to equity. The fair value of the share awards payments is determined at the grant date by reference of the market value of the shares and recognised as an expense over the vesting period. When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised. For cash-settled share-based payment transactions, if any, the Company measures the services acquired for amounts that are based on the price of the Company’s shares. The fair value of the liability incurred is measured using Geometric Brownian Motion method. Until the liability is settled, the Company is required to remeasure the fair value of the liability at each reporting date and at the date of settlement, with any changes in value recognised in profit or loss for the period.

Financial Instruments-risk ma45

Financial Instruments-risk management (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Financial Instruments-risk management [Abstract]
Disclosure of detailed information about gearing ratios [text block]	The gearing ratios at 31 December 2017 and 2016 were as follows: Amounts in US$ '000 2017 2016 Net Debt 291,449 285,109 Total Equity 126,840 141,593 Total Capital 418,289 426,702 Gearing Ratio 70 % 67 %

Consolidated Statement of Cas46

Consolidated Statement of Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Consolidated Statement Of Cash Flow [Abstract]
Disclosure Of Detailed Information About Non-cash Transaction Cash Flow [text block]	The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flow: Amounts in US$ '000 2017 2016 2015 Increase in asset retirement obligation 5,943 1,195 985 Increase in provisions for other long-term liabilities 2,053 3,468 - Purchase of property, plant and equipment 11,759 (4,657) 830
Disclosure Of Detailed Information About Changes In Working Capital [text block]	Changes in working capital shown in the Consolidated Statement of Cash Flow are disclosed as follows: Amounts in US$ '000 2017 2016 2015 Increase in Prepaid taxes (14,802) (2,351) (16,611) (Increase) Decrease in Inventories (2,031) 466 2,752 (Increase) Decrease in Trade receivables (1,344) (4,811) 22,470 (Increase) Decrease in Prepayments and other receivables and Other assets (8,623) (1,758) 405 Customer advance (repayments) payments (10,000) 20,000 - Security deposit granted (Note 35) (15,600) - - Increase (Decrease) in Trade and other payables 27,122 374 (33,120) (25,278) 11,920 (24,104)

Segment information (Tables)

Segment information (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Segment information [Abstract]
Disclosure of segment information by geographical segments [Text Block]	Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2017 Revenue 32,738 34,238 263,076 - 70 - 330,122 Sale of crude oil 15,873 910 262,309 - 70 - 279,162 Sale of gas 16,865 33,328 767 - - - 50,960 Realized loss on commodity risk management contracts - - (2,148) - - - (2,148) Production and operating costs (20,999) (10,737) (66,913) - (338) - (98,987) Royalties (1,314) (3,134) (24,236) - (13) - (28,697) Transportation costs (1,211) - (1,678) - (80) - (2,969) Share-based payment (170) (39) (248) - - - (457) Other costs (18,304) (7,564) (40,751) - (245) - (66,864) Operating (loss) profit (19,675) 4,434 116,290 (3,850) (3,430) (14,773) 78,996 Operating netback 11,222 23,540 194,013 - (467) - 228,308 Adjusted EBITDA 4,070 20,166 168,303 (3,505) (2,183) (11,075) 175,776 Depreciation (23,730) (10,809) (40,010) (139) (159) (38) (74,885) Write-off (546) (2,978) (1,625) - (685) - (5,834) Total assets 301,931 91,604 288,429 22,099 30,924 51,176 786,163 Employees (average) 102 12 164 13 88 - 379 Employees at year end 102 12 180 19 92 - 405 Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2016 Revenue 36,723 29,719 126,228 - - - 192,670 Sale of crude oil 18,774 688 125,731 - - - 145,193 Sale of gas 17,949 29,031 497 - - - 47,477 Realized gain on commodity risk management contracts - - 514 - - - 514 Production and operating costs (22,169) (8,459) (36,607) - - - (67,235) Royalties (1,495) (2,721) (7,281) - - - (11,497) Transportation costs (1,170) - (1,111) - - - (2,281) Share-based payment (138) (71) (413) - - - (622) Other costs (19,366) (5,667) (27,802) - - - (52,835) Operating (loss) profit (44,969) (645) 31,463 (3,147) 370 (11,685) (28,613) Operating netback 13,696 21,356 87,523 41 (378) (91) 122,147 Adjusted EBITDA 5,159 17,487 66,921 (2,607) 1,848 (10,487) 78,321 Depreciation (31,355) (12,974) (31,148) (130) (150) (17) (75,774) Reversal of impairment losses - - 5,664 - - - 5,664 Write-off (19,389) (4,583) (7,394) - - - (31,366) Total assets 317,969 99,904 182,784 5,020 6,071 28,792 640,540 Employees (average) 102 10 138 11 80 - 341 Employees at year end 102 10 146 10 77 - 345 Amounts in US$ '000 Chile Brazil Colombia Peru Argentina Corporate Total 2015 Revenue 44,808 32,388 131,897 - 597 - 209,690 Sale of crude oil 29,180 955 131,897 - 597 - 162,629 Sale of gas 15,628 31,433 - - - - 47,061 Production costs (28,704) (8,056) (48,534) - (1,448) - (86,742) Royalties (1,973) (2,998) (8,150) - (34) - (13,155) Transportation costs (2,441) - (2,068) - (2) - (4,511) Share-based payment (132) - (234) - (197) - (563) Other costs (24,158) (5,058) (38,082) - (1,215) - (68,513) Operating (loss) profit (180,264) 6,639 (37,227) (6,719) (2,350) (12,570) (232,491) Operating netback 15,254 24,393 80,355 44 (1,732) (287) 118,027 Adjusted EBITDA (183) 20,460 66,736 (6,520) (684) (6,022) 73,787 Depreciation (39,227) (13,568) (52,434) (129) (199) - (105,557) Impairment loss (104,515) - (45,059) - - - (149,574) Write-off (25,751) - (4,333) - - - (30,084) Total assets 381,143 114,974 153,071 4,287 3,181 47,143 703,799 Employees (average) 153 11 130 16 93 - 403 Employees at year end 106 12 133 11 90 - 352
Disclosure of detailed information about reconciliation of total Operating netback to total loss profit before income tax [text block]	A reconciliation of total Operating netback to total profit (loss) before income tax is provided as follows: Amounts in US$ '000 2017 2016 2015 Operating netback 228,308 122,147 118,027 Administrative expenses (38,937) (32,323) (30,590) Geological and geophysical expenses (13,595) (11,503) (13,650) Adjusted EBITDA for reportable segments 175,776 78,321 73,787 Unrealized loss on commodity risk management contracts (13,300) (3,068) - Depreciation (a) (74,885) (75,774) (105,557) Share-based payment (4,075) (3,367) (8,223) Impairment and write-off of unsuccessful exploration efforts (5,834) (25,702) (179,658) Others (b) 1,314 977 (12,840) Operating profit (loss) 78,996 (28,613) (232,491) Financial expenses (53,511) (36,229) (36,924) Financial income 2,016 2,128 1,269 Foreign exchange (loss) profit (2,193) 13,872 (33,474) Profit (Loss) before tax 25,308 (48,842) (301,620) (a) Net of capitalised costs for oil stock included in Inventories. (b) In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Revenue [Abstract]
Disclosure Of Detailed Information On Revenue [text block]	Amounts in US$ '000 2017 2016 2015 Sale of crude oil 279,162 145,193 162,629 Sale of gas 50,960 47,477 47,061 330,122 192,670 209,690

Commodity risk management con49

Commodity risk management contracts (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Commodity risk management contracts [Abstract]
Disclosure of detailed information about derivative contract [text block]	The following table presents the Group’s derivative contracts in force as of 31 December 2017: Period Reference Type Volume Price US$/bbl 1 October 2017 - 31 March 2018 ICE BRENT Zero Premium Collar 4,000 50.00 Put 54.90 Call 1 October 2017 - 31 March 2018 ICE BRENT Zero Premium Collar 2,000 50.00 Put 54.95 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 2,000 52.00 Put 60.00 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 1,000 52.00 Put 58.40 Call 1 April 2018 - 30 June 2018 ICE BRENT Zero Premium Collar 2,000 52.00 Put 58.25 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.55 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.50 Call 1 April 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 1,000 42.00-52.00 Put 59.60 Call 1 January 2018 - 30 June 2018 ICE BRENT Zero Premium 3 Way 2,000 43.00-53.00 Put 64.55 Call 1 July 2018 - 30 September 2018 ICE BRENT Zero Premium 3 Way 5,000 43.00-53.00 Put 69.00 Call
Disclosure of detailed information about gainloss on commodity risk management contracts [text block]	The table below summarizes the gain (loss) on the commodity risk management contracts: 2017 2016 2015 Realized (loss) gain on commodity risk management contracts (2,148) 514 - Unrealized loss on commodity risk management contracts (13,300) (3,068) - Total (15,448) (2,554) -

Production and operating costs

Production and operating costs (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Production And Operating Costs [Abstract]
Disclosure Of Detailed Information On Production And Operating Costs [text block]	Amounts in US$ '000 2017 2016 2015 Well and facilities maintenance 14,722 13,160 19,974 Staff costs (Note 11) 15,017 10,859 17,999 Share-based payment (Notes 11) 457 622 563 Royalties 28,697 11,497 13,155 Consumables 11,902 8,283 8,591 Transportation costs 2,969 2,281 4,511 Equipment rental 5,818 3,868 3,517 Safety and Insurance costs 2,591 2,222 3,239 Gas plant costs 6,069 6,300 2,878 Field camp 2,377 1,687 2,645 Non operated blocks costs 1,213 1,082 2,127 Other costs 7,155 5,374 7,543 98,987 67,235 86,742

Depreciation (Tables)

Depreciation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Depreciation [Abstract]
Disclosure Of Detailed Information On Depreciation [text block]	Amounts in US$ '000 2017 2016 2015 Oil and gas properties 57,725 61,080 84,849 Production facilities and machinery 14,558 10,788 15,467 Furniture, equipment and vehicles 1,948 2,702 2,850 Buildings and improvements 844 920 874 Depreciation of property, plant and equipment (a) 75,075 75,490 104,040 Related to: Productive assets 72,283 71,868 100,316 Administrative assets 2,792 3,622 3,724 Depreciation total (a) 75,075 75,490 104,040 (a)

Staff costs and Directors Rem52

Staff costs and Directors Remuneration (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Staff costs and Directors Remuneration [Abstract]
Disclosure of Employee Compensation Explanatory [text block]	2017 2016 2015 Number of employees at year end 405 345 352 Amounts in US$ '000 Wages and salaries 44,891 36,059 40,574 Share-based payments (Note 30) 4,075 3,367 8,223 Social security charges 5,364 3,792 6,197 Director’s fees and allowance 3,458 2,088 1,238 57,788 45,306 56,232 Recognised as follows: Production and operating costs 15,474 11,481 18,562 Geological and geophysical expenses 11,026 10,439 11,336 Administrative expenses 31,288 23,386 26,334 57,788 45,306 56,232 Board of Directors’ and key managers’ remuneration Salaries and fees 9,674 7,337 6,549 Share-based payments 2,322 1,211 6,544 Other benefits in kind 287 112 167 12,283 8,660 13,260
Disclosure of information about key management personnel [text block]	Executive Executive Non- Director Fees Cash Gerald O’Shaughnessy US$ 400,000 - - - US$ 400,000 James F. Park US$ 800,000 US$ 800,000 - - US$ 1,600,000 Pedro Aylwin (a) - - - - - Peter Ryalls (b) - - US$ 115,000 9,388 US$ 165,010 Juan Cristóbal Pavez (c) - - US$ 110,000 15,408 US$ 210,020 Carlos Gulisano - - US$ 110,000 15,408 US$ 210,020 Robert Bedingfield (d) - - US$ 102,500 15,408 US$ 202,520 Michael Dingman - - US$ 46,667 8,853 US$ 105,012 Jamie Coulter - - US$ 50,000 6,020 US$ 95,641 a b c d

Geological and geophysical ex53

Geological and geophysical expenses (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Geological and geophysical expenses [Abstract]
Disclosure of detailed information about geological and geophysical expenses [text block]	Amounts in US$ '000 2017 2016 2015 Staff costs (Note 11) 10,525 9,541 10,557 Share-based payment (Notes 11) 501 898 779 Allocation to capitalised project (6,402) (2,119) (598) Other services 3,070 1,962 3,093 7,694 10,282 13,831

Administrative expenses (Tables

Administrative expenses (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Administrative expenses [Abstract]
Disclosure of detailed information about administrative expenses [text block]	Amounts in US$ '000 2017 2016 2015 Staff costs (Note 11) 24,713 19,451 18,215 Share-based payment (Notes 11) 3,117 1,847 6,881 Consultant fees 5,120 3,894 4,115 Office expenses 2,506 2,217 2,535 Travel expenses 2,772 1,717 1,497 Director’s fees and allowance (Note 11) 3,458 2,088 1,238 Communication and IT costs 2,109 2,013 1,791 Allocation to joint operations (7,646) (4,365) (4,203) Other administrative expenses 5,905 5,308 5,402 42,054 34,170 37,471

Selling expenses (Tables)

Selling expenses (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Selling expenses [Abstract]
Disclosure of detailed information about selling expenses [text block]	Amounts in US$ '000 2017 2016 2015 Transportation 864 3,559 4,760 Selling taxes and other 272 663 451 1,136 4,222 5,211

Financial results (Tables)

Financial results (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Financial costs [Abstract]
Disclosure of detailed information about net financial income or expense [text block]	Amounts in US$ '000 2017 2016 2015 Financial expenses Interest and amortisation of debt issue costs (27,823) (28,984) (28,983) Interest with related parties (2,224) (1,587) (1,560) Less: amounts capitalised on qualifying assets 611 255 637 Borrowings cancellation costs (17,575) - - Bank charges and other financial results (3,721) (3,220) (4,443) Unwinding of long-term liabilities (Note 28) (2,779) (2,693) (2,575) (53,511) (36,229) (36,924) Financial income Interest received 2,016 2,128 1,269 2,016 2,128 1,269 Foreign exchange gains and losses Foreign exchange (loss) gain (2,193) 13,872 (33,474) (2,193) 13,872 (33,474) Total Financial results (53,688) (20,229) (69,129)

Income tax (Tables)

Income tax (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Income tax [Abstract]
Major components of tax expense income [text block]	Amounts in US$ '000 2017 2016 2015 Current tax (48,449) (12,359) (7,262) Deferred income tax (Note 18) 5,304 555 24,316 (43,145) (11,804) 17,054
Summary of Income Tax Reconciliation Explanatory [text block]	The tax on the Group’s profit (loss) before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows: Amounts in US$ '000 2017 2016 2015 Profit (Loss) before tax 25,308 (48,842) (301,620) Tax losses from non-taxable jurisdictions 22,708 12,318 15,852 Taxable profit (loss) 48,016 (36,524) (285,768) Income tax calculated at domestic tax rates applicable to Profit (Losses) Income in the respective countries (31,107) (809) 62,589 Tax losses where no deferred tax benefit is recognised (8,111) (6,616) (16,325) Effect of currency translation on tax base (2,330) (2,840) (6,776) Changes in the income tax rate (Note 16) 542 220 (625) Non recoverable tax loss carry-forwards - - (15,537) Non-taxable results (a) (2,139) (1,759) (6,272) Income tax (43,145) (11,804) 17,054 (a) Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities.
Disclosure Of Temporary Difference Unused Tax Losses And Unused Tax Credits Explanatory [text block]	The Group has significant tax losses available which can be utilised against future taxable profit in the following countries: Amounts in US$ '000 2017 2016 2015 Argentina 4,849 2,908 3,834 Chile (a) 345,104 280,290 209,910 Brazil (a) 33,721 16,057 - Total tax losses at 31 December 383,674 299,255 213,744 (a) Taxable losses have no expiration date.
Deferred tax assets in respect of tax losses explanatory [text block]	Expiring dates for tax losses accumulated at 31 December 2017 are: Expiring date Amounts in US$ '000 2020 754 2021 1,446 2022 2,649

Deferred income tax (Tables)

Deferred income tax (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of deferred income tax [Abstract]
Disclosure of Detailed Information about Deferred Tax Asset Liability Explanatory [Text Block]	The gross movement on the deferred income tax account is as follows: Amounts in US$ '000 2017 2016 Deferred tax at 1 January 20,283 17,691 Reclassification (a) - 574 Currency translation differences (237) 1,463 Income statement credit 5,304 555 Deferred tax at 31 December 25,350 20,283 (a) Corresponds to differences between income tax provision and the final tax return presented.
Disclosure of temporary difference, unused tax losses and unused tax credits [text block]	The breakdown and movement of deferred tax assets and liabilities as of 31 December 2017 and 2016 are as follows: Amounts in US$ '000 At the beginning Currency (Charged) At end of year Deferred tax assets Difference in depreciation 19,225 (237) (2,817) 16,171 Taxable losses 3,828 - 7,637 11,465 Total 2017 23,053 (237) 4,820 27,636 Total 2016 34,646 1,463 (13,056) 23,053 Amounts in US$ '000 At the beginning Credited to Reclassification (a) At end Deferred tax liabilities Difference in depreciation (17,308) (2,766) - (20,074) Taxable losses 14,538 3,250 - 17,788 Total 2017 (2,770) 484 - (2,286) Total 2016 (16,955) 13,611 574 (2,770) (a) Corresponds to differences between income tax provision and the final tax return presented.

Earnings per share (Tables)

Earnings per share (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of earning per share [Abstract]
Earnings per share [text block]	Amounts in US$ '000 except for shares 2017 2016 2015 Numerator: Loss for the year attributable to owners (24,228) (49,092) (234,031) Denominator: Weighted average number of shares used in basic EPS 60,093,191 59,777,145 57,759,001 (Losses) after tax per share (US$) – basic (0.40) (0.82) (4.05) Amounts in US$ '000 except for shares 2017 (a) 2016 2015 Weighted average number of shares used in basic EPS 60,093,191 59,777,145 57,759,001 Effect of dilutive potential common shares (a) Weighted average number of common shares for the purposes of diluted earnings per shares 60,093,191 59,777,145 57,759,001 (Losses) after tax per share (US$) – diluted (0.40) (0.82) (4.05) (a) 4,564,777 1,390,706 1,032,279

Property, plant and equipment (

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Property Plant And Equipments [Line Items]
Disclosure of detailed information about property, plant and equipment [text block]	Amounts in US$'000 Oil &; gas Furniture, Production Buildings Construction in Exploration and (b) Total Cost at 1 January 2015 749,947 12,057 111,646 9,527 59,425 140,444 1,083,046 Additions (4,640) (a) 954 - 272 36,543 12,299 45,428 Currency translation differences (27,522) (182) (2,577) (92) - (1,510) (31,883) Disposals (241) (13) (1,685) (84) - - (2,023) Write-off / Impairment loss (128,956) - (13,242) - (7,376) (30,084) (c) (179,658) Transfers 60,404 929 30,690 895 (58,769) (34,149) - Cost at 31 December 2015 648,992 13,745 124,832 10,518 29,823 87,000 914,910 Additions (3,531) (a) 406 466 - 20,322 18,181 35,844 Currency translation differences 16,132 126 2,077 35 73 790 19,233 Disposals - (22) - - - - (22) Write-off / Impairment reversal 5,664 - - - - (31,366) (d) (25,702) Transfers 24,984 102 5,038 - (17,292) (12,832) - Cost at 31 December 2016 692,241 14,357 132,413 10,553 32,926 61,773 944,263 Additions 7,997 (a) 954 - - 66,953 49,455 125,359 Currency translation differences (1,142) (12) (147) (3) (62) (104) (1,470) Disposals - (112) - (189) - - (301) Write-off / Impairment reversal - - - - - (5,834) (e) (5,834) Transfers 77,408 211 25,130 - (61,827) (40,922) - Cost at 31 December 2017 776,504 15,398 157,396 10,361 37,990 64,368 1,062,017 Depreciation and write-down at 1 January 2015 (240,439) (4,449) (45,147) (2,244) - - (292,279) Depreciation (84,849) (2,850) (15,467) (874) - - (104,040) Disposals - 8 - 15 - - 23 Currency translation differences 4,115 (26) - (92) - - 3,997 Depreciation and write-down at 31 December 2015 (321,173) (7,317) (60,614) (3,195) - - (392,299) Depreciation (61,080) (2,702) (10,788) (920) - - (75,490) Disposals - 8 - - - - 8 Currency translation differences (2,486) (38) (296) (16) - - (2,836) Depreciation and write-down at 31 December 2016 (384,739) (10,049) (71,698) (4,131) - - (470,617) Depreciation (57,725) (1,948) (14,558) (844) - - (75,075) Disposals - 73 - 38 - - 111 Currency translation differences 930 8 24 5 - - 967 Depreciation and write-down at 31 December 2017 (441,534) (11,916) (86,232) (4,932) - - (544,614) Carrying amount at 31 December 2015 327,819 6,428 64,218 7,323 29,823 87,000 522,611 Carrying amount at 31 December 2016 307,502 4,308 60,715 6,422 32,926 61,773 473,646 Carrying amount at 31 December 2017 334,970 3,482 71,164 5,429 37,990 64,368 517,403 (a) (b) 53,764 53,523 64,094 (c) (d) (e)
Exploration Wells [Member]
Disclosure Of Property Plant And Equipments [Line Items]
Disclosure of detailed information about property, plant and equipment [text block]	Amounts in US$ '000 Total Exploration wells at 31 December 2015 22,906 Additions 15,088 Write-offs (19,949) Transfers (9,795) Exploration wells at 31 December 2016 8,250 Additions 35,299 Write-offs (3,664) Transfers (29,281) Exploration wells at 31 December 2017 10,604

Subsidiary undertakings (Tables

Subsidiary undertakings (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of subsidiary undertakings [Abstract]
Disclosure of subsidiaries [text block]	Details of the subsidiaries and joint operations of the Group are set out below: Name and registered office Ownership interest Subsidiaries GeoPark Argentina Limited (Bermuda) 100% GeoPark Argentina Limited – Argentinean Branch 100% (a) GeoPark Latin America Limited (Bermuda) 100% GeoPark Latin America Limited – Agencia en Chile 100% (a) GeoPark S.A. (Chile) 100% (a) (b) GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil) 100% (a) GeoPark Chile S.A. (Chile) 80% (a) (c) GeoPark Fell S.p.A. (Chile) 80% (a) (c) GeoPark Magallanes Limitada (Chile) 80% (a) (c) GeoPark TdF S.A. (Chile) 68.8% (a) (d) GeoPark Colombia S.A. (Chile) 100% (a) (b) GeoPark Colombia SAS (Colombia) 80% (a) (c) GeoPark Latin America S.L.U. (Spain) 100% (a) GeoPark Colombia Coöperatie U.A. (The Netherlands) 80% (a) (c) GeoPark S.A.C. (Peru) 100% (a) GeoPark Perú S.A.C. (Peru) 100% (a) GeoPark Operadora del Perú S.A.C. (Peru) 100% (a) GeoPark Peru S.L.U. (Spain) 100% (a) GeoPark Brazil S.L.U. (Spain) 100% (a) GeoPark Colombia E&;P S.A.(Panama) 100% (a) (b) GeoPark Colombia E&;P Sucursal Colombia (Colombia) 100% (a) (b) GeoPark Mexico S.A.P.I. de C.V. (Mexico) 100% (b) Ogarrio E&;P S.A.P.I. de C.V. (Mexico) 51% (a) (b) GeoPark (UK) Limited (United Kingdom) 100% Joint operations Tranquilo Block (Chile) 50% (e) Flamenco Block (Chile) 50% (e) Campanario Block (Chile) 50% (e) Isla Norte Block (Chile) 60% (e) Yamu/Carupana Block (Colombia) 89.5%/100% (e) Llanos 34 Block (Colombia) 45% (e) Llanos 32 Block (Colombia) 12.5% CPO-4 Block (Colombia) 50% (e) Puelen Block (Argentina) 18% Sierra del Nevado Block (Argentina) 18% CN-V Block (Argentina) 50% (e) Manati Field (Brazil) 10% (a) Indirectly owned. (b) Dormant companies. (c) LG International has 20 (d) LG International has 20 14 31.2 (e) GeoPark is the operator.

Prepaid taxes (Tables)

Prepaid taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Prepaid taxes [Abstract]
Disclosure Of Detailed Information About Prepaid Taxes [text block]	Amounts in US$ '000 2017 2016 V.A.T. 27,674 14,052 Income tax payments in advance 1,258 4,517 Other prepaid taxes 939 98 Total prepaid taxes 29,871 18,667 Classified as follows: Current 26,048 15,815 Non current 3,823 2,852 Total prepaid taxes 29,871 18,667

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2017
Classes of current inventories [abstract]
Disclosure of detailed information about inventories [text block]	Amounts in US$ '000 2017 2016 Crude oil 1,969 1,521 Materials and spares 3,769 1,994 5,738 3,515

Trade receivables and Prepaym64

Trade receivables and Prepayments and other receivables (Tables)	12 Months Ended
	Dec. 31, 2017
Trade and other receivables [abstract]
Disclosure of detailed information about trade receivables and prepayments and other receivables [text block]	Amounts in US$ '000 2017 2016 Trade receivables 19,519 18,426 19,519 18,426 To be recovered from co-venturers (Note 33) 2,455 3,311 Related parties receivables (Note 33) 56 42 Prepayments and other receivables 5,242 4,290 7,753 7,643 Total 27,272 26,069 Classified as follows: Current 27,037 25,828 Non current 235 241 Total 27,272 26,069
Disclosure of movements on the provision for impairment of trade and other receivables [text block]	Amounts in US$ '000 2017 2016 At 1 January 741 596 Foreign exchange (income) loss (147) 145 594 741

Financial instruments by cate65

Financial instruments by category (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of detailed information about financial instruments [line items]
Disclosure of detailed information about financial instruments [text block]	Assets as per statement Amounts in US$ '000 of financial position 2017 2016 Loans and receivables Trade receivables 19,519 18,426 To be recovered from co-venturers (Note 33) 2,455 3,311 Other financial assets (a) 43,488 22,027 Cash and cash equivalents 134,755 73,563 200,217 117,327 (a) Non current other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations and also include a non current account receivable with the previous owners of one of the Colombian subsidiaries (see Note 28). Current other financial assets corresponds to the security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original maturities up to twelve months and over three months. Liabilities as per statement of financial position Amounts in US$ '000 2017 2016 Liabilities at fair value through profit and loss Derivative financial instrument liabilities 19,289 3,067 19,289 3,067 Other financial liabilities at amortised cost Trade payables 52,557 23,650 Payables to related parties (Note 33) 31,184 27,801 To be paid to co-venturers (Note 33) 10,015 1,614 Borrowings 426,204 358,672 519,960 411,737 Total financial liabilities 539,249 414,804
Disclosure of credit quality of trade receivables [Text Block]	Amounts in US$ '000 2017 2016 Trade receivables Counterparties with an external credit rating (Moody’s) B2 70 7,056 Ba3 8,788 - Baa3 3,614 3,729 Counterparties without an external credit rating Group1 (a) 7,047 7,641 Total trade receivables 19,519 18,426 (a) Group 1 – existing customers (more than 6 months) with no defaults in the past.
Disclosure of maturity analysis for non-derivative financial liabilities [text block]	The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows. Less than 1 Between 1 Between 2 Over 5 Amounts in US$ '000 year and 2 years and 5 years years At 31 December 2017 Borrowings 27,625 27,625 82,875 480,250 Trade payables 52,557 - - - Payables to related parties 7,331 2,068 27,087 - 87,513 29,693 109,962 480,250 At 31 December 2016 Borrowings 48,958 43,304 355,064 - Trade payables 23,650 - - - Payables to related parties 1,561 1,561 22,018 - 74,169 44,865 377,082 -
Disclosure Of Financial liabilities Measured And Recognised At Fair Value And On Recurring Basis [text block]	The following table presents the Group’s financial assets and financial liabilities measured and recognised at fair value at 31 December 2017 and 2016 on a recurring basis: At 31 December Amounts in US$ '000 Level 2 2017 Liabilities Derivative financial instrument liabilities Commodity risk management contracts 19,289 19,289 Total Liabilities 19,289 19,289 At 31 December Amounts in US$ '000 Level 2 2016 Liabilities Derivative financial instrument liabilities Commodity risk management contracts 3,067 3,067 Total Liabilities 3,067 3,067
Cash At Bank And Other Financial Assets [Member]
Disclosure of detailed information about financial instruments [line items]
Disclosure of credit quality of cash at bank and other financial assets [text block]	Cash at bank and other financial assets (a) Amounts in US$ '000 2017 2016 Counterparties with an external credit rating (Moody’s, S&;P, Fitch, BRC Investor Services) A1 553 813 A2 298 - A3 63,853 - Aaa 15,040 - Aa3 11,401 42,798 AAA 19,634 14 B2 31 - Ba1 18 - Ba2 7 - Baa1 307 100 Baa2 4,078 4,094 Ba3 2,815 3,497 B3 - 10 BBB 15,064 - Counterparties without an external credit rating 45,123 44,252 Total 178,222 95,578 (a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21 12

Share capital (Tables)

Share capital (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Share capital [Abstract]
Disclosure of issued share capital [text block]	Issued share capital 2017 2016 Common stock (amounts in US$ ‘000) 61 60 The share capital is distributed as follows: Common shares, of nominal US$ 0.001 60,596,219 59,940,881 Total common shares in issue 60,596,219 59,940,881 Authorised share capital US$ per share 0.001 0.001 Number of common shares (US$ 0.001 each) 5,171,949,000 5,171,949,000 Amount in US$ 5,171,949 5,171,949
Disclosure of detailed information about common shares [text block]	Shares Shares issued closing US$(000) GeoPark common shares history Date (millions) (millions) Closing Shares outstanding at the end of 2015 59.5 59 Stock awards Feb 2016 0.4 59.9 60 Stock awards Dec 2016 0.5 60.4 60 Stock awards Dec 2016 0.1 60.5 60 Buyback program Dec 2016 (0.6) 59.9 60 Shares outstanding at the end of 2016 59.9 60 Stock awards Jan 2017 0.1 60.0 60 Stock awards Dec 2017 0.1 60.1 60 Stock awards Dec 2017 0.5 60.6 61 Shares outstanding at the end of 2017 60.6 61

Borrowings (Tables)

Borrowings (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Borrowings [Abstract]
Disclosure of detailed information about borrowings [text block]	Amounts in US$ '000 2017 2016 Outstanding amounts as of 31 December 2024 Notes (a) 426,124 - Notes GeoPark Latin America Agencia en Chile (b) - 304,059 Banco Itaú (c) - 49,763 Banco de Chile (d) - 4,709 Banco de Crédito e Inversiones (e) 80 141 426,204 358,672 Classified as follows: Current 7,664 39,283 Non current 418,540 319,389 (a) During September 2017, the Company successfully placed US$ 425,000,000 The Notes carry a coupon of 6.50 6.90 3.5 2 The net proceeds from the Notes were used by the Company (i) to make a capital contribution to its wholly-owned subsidiary, GeoPark Latin America Limited Agencia en Chile (“GeoPark LA Agencia”), providing it with sufficient funds to fully repay the 7.50% senior secured notes due 2020 and to pay any related fees and expenses, including call premium, and (ii) for general corporate purposes, including capital expenditures and to repay existing indebtedness. (b) During February 2013, the Group successfully placed US$ 300,000,000 7.50 11 February 2020 (c) During March 2014, GeoPark executed a loan agreement with Itaú BBA International for US$ 70,450,000 10 (d) During December 2015, GeoPark executed a loan agreement with Banco de Chile for US$ 7,028,000 2.35 (e) During February 2016, GeoPark executed a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 4.14

Provisions and other long-ter68

Provisions and other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Provisions and other long-term liabilities [Abstract]
Disclosure of detailed information about provisions and other long-term liabilities [text block]	Amounts in US$ ‘000 Asset retirement Deferred Other Total At 1 January 2016 31,617 5,033 5,800 42,450 Addition to provision 1,195 1,375 2,686 5,256 Recovery of abandonments costs (5,504) - - (5,504) Exchange difference (1,614) - 538 (1,076) Foreign currency translation 1,614 - - 1,614 Amortisation - (2,924) - (2,924) Unwinding of discount 2,554 - 139 2,693 At 31 December 2016 29,862 3,484 9,163 42,509 Addition to provision 5,943 - 2,220 8,163 Exchange difference 134 - 1,154 1,288 Foreign currency translation (134) - - (134) Amortisation - (657) - (657) Unwinding of discount 2,607 - 172 2,779 Unused amounts reversed - - (2,535) (2,535) Amounts used during the year (337) (1,375) (3,417) (5,129) At 31 December 2017 38,075 1,452 6,757 46,284

Trade and other payables (Table

Trade and other payables (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Trade and other payables [Abstract]
Disclosure of detailed information of trade and other payables [text block]	Amounts in US$ '000 2017 2016 V.A.T 1,118 1,102 Trade payables 52,557 23,650 Payables to related parties (a) 31,184 27,801 Customer advance payments (Note 3) 10,000 20,000 Staff costs to be paid 9,143 7,749 Royalties to be paid 4,110 1,503 Taxes and other debts to be paid 4,191 3,355 To be paid to co-venturers (Note 33) 10,015 1,614 122,318 86,774 Classified as follows: Current 96,397 52,008 Non current 25,921 34,766 (a) July 2020 8

Share-based payment (Tables)

Share-based payment (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Share-based Payment [Abstract]
Disclosure of detailed information about stock awards programs, share based payments [text block]	Details of these costs and the characteristics of the different stock awards programs and other share based payments are described in the following table and explanations: Awards Awards at granted Awards the in the Awards Awards at year Charged to net loss / profit Year of issuance beginning year forfeited exercised end 2017 2016 2015 2016 1,619,105 - 31,109 - 1,587,996 865 445 - 2014 490,000 - - 490,000 - 838 821 898 2013 - - - - - - - 594 2012 - - - - - - 855 636 2011 - - - - - - - 879 Subtotal 1,703 2,121 3,007 Stock options to Executive Directors - - - - - - - 2,390 Shares granted to Non-Executive Directors - 70,485 70,485 454 400 371 VCP 2013 - - - - - - - 617 VCP 2016 - - - - - 1,868 934 - Executive Directors Bonus - - - - - - (325) 400 Key Management Bonus 82,306 - - 82,306 - - 202 1,438 Stock awards for service contracts - 12,546 - 12,546 - 50 35 - 2,191,411 83,031 31,109 655,337 1,587,996 4,075 3,367 8,223

Interests in Joint operations (

Interests in Joint operations (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Interests in Joint operations [Abstract]
Disclosure of interests in joint operations [Text Block]	PP&;E Operating Subsidiary / E&;E Other Total Total NET ASSETS/ (loss) Joint operation Interest Assets Assets Assets Liabilities (LIABILITIES) Revenue profit 2017 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 55 55 (432) (377) - (48) GeoPark TdF S.A. Flamenco Block 50 % 9,893 - 9,893 (1,223) 8,670 879 (1,422) Campanario Block 50 % 17,347 - 17,347 (233) 17,114 - (150) Isla Norte Block 60 % 9,553 - 9,553 (60) 9,493 - (161) Colombia SAS Yamu/Carupana Block 89.5 % 4,741 1 4,742 (2,993) 1,749 3,072 (2,721) Llanos 34 Block 45 % 131,193 4,563 135,756 (5,847) 129,909 259,815 163,917 Llanos 32 Block 12.5 % 835 209 1,044 (492) 552 1,784 (319) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 44,167 19,126 63,293 (11,444) 51,849 34,238 12,731 POT-T-747 70 % 849 358 1,207 (1,091) 116 - - GeoPark Argentina Limited – Argentinean Branch CN-V Block 50 % 6,819 347 7,166 (984) 6,182 70 (1,163) Puelen Block 18 % 1,318 72 1,390 (232) 1,158 - (546) Sierra del Nevado Block 18 % 568 169 737 (837) (100) - (474) PP&;E Operating Subsidiary / E&;E Other Total Total NET ASSETS/ (loss) Joint operation Interest Assets Assets Assets Liabilities (LIABILITIES) Revenue profit 2016 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 55 55 (424) (369) - (40) GeoPark TdF S.A. Flamenco Block 50 % 15,108 - 15,108 (93) 15,015 1,004 (1,988) Campanario Block 50 % 29,718 - 29,718 (1) 29,717 - (399) Isla Norte Block 60 % 9,920 - 9,920 (1) 9,919 5 (438) Colombia SAS Yamu/Carupana Block 89.5 % 3,418 - 3,418 (2,289) 1,129 18 (307) Llanos 34 Block 45 % 79,811 693 80,504 (3,943) 76,561 125,400 83,193 Llanos 32 Block 10 % 3,819 - 3,819 (211) 3,608 2,303 1,043 GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 54,166 15,791 69,957 (8,442) 61,515 29,719 20,945 2015 GeoPark Magallanes Ltda. Tranquilo Block 50 % - 45 45 (2) 43 - (69) GeoPark TdF S.A. Flamenco Block 50 % 14,932 - 14,932 (53) 14,879 1,810 (51,411) Campanario Block 50 % 27,570 - 27,570 (10) 27,560 13 (7,267) Isla Norte Block 60 % 8,583 - 8,583 (16) 8,567 355 (5,661) Colombia SAS Llanos 17 Block 36.84 % - - - (93) (93) 3 (6,325) Yamu/Carupana Block 89.5 % 3,569 2,061 5,630 (2,235) 3,395 1,409 (16,552) Llanos 34 Block 45 % 76,667 429 77,096 (3,295) 73,801 114,276 53,049 Llanos 32 Block 10 % 3,106 96 3,202 (213) 2,989 8,258 (1,343) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10 % 50,801 12,930 63,731 (10,395) 53,336 32,388 20,354

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Commitments [Abstract]
Disclosure of Detailed Information Of Royalties Commitments [text block]	Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties on Colombian production of light and medium oil are calculated on a field-by-field basis, using the following sliding scale:
Disclosure of finance lease and operating lease by lessee [text block]	The future aggregate minimum lease payments under non-cancellable operating leases are as follows: Amounts in US$ ’000 2017 2016 2015 Operating lease commitments Falling due within 1 year 32,180 67,752 12,878 Falling due within 1 – 3 years 5,777 14,031 8,257 Falling due within 3 – 5 years 2,793 5,066 2,456 Falling due over 5 years - 114 309 Total minimum lease payments 40,750 86,963 23,900

Related parties (Tables)

Related parties (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Related Parties [Abstract]
Disclosure of the Company's main shareholders [Text Block]	Common Percentage of outstanding Shareholder shares common shares James F. Park (a) 7,891,269 13.02 % Gerald E. O’Shaughnessy (b) 7,193,316 11.87 % Manchester Financial Group, LP 5,103,439 8.42 % IFC Equity Investments (c) 3,422,476 5.65 % Juan Cristóbal Pavez (d) 2,961,520 4.89 % Other shareholders 34,024,199 56.15 % 60,596,219 100.00 % (a) Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of our Board of Directors. (b) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, and other investment vehicles. (c) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff. (d) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 83,716
Disclosure of balances and transactions with related parties [text block]	Balances Transaction in at year Account (Amounts in ´000) the year end Related Party Relationship 2017 To be recovered from co-venturers - 2,455 Joint Operations Joint Operations Prepayments and other receivables - 56 LGI Partner Payables account - (31,184) LGI Partner To be paid to co-venturers - (10,015) Joint Operations Joint Operations Financial results 2,224 - LGI Partner Geological and geophysical expenses 170 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 411 - Pedro Aylwin Executive Director (b) 2016 To be recovered from co-venturers - 3,311 Joint Operations Joint Operations Prepayments and other receivables - 42 LGI Partner Payables account - (27,801) LGI Partner To be paid to co-venturers - (1,614) Joint Operations Joint Operations Financial results 1,587 - LGI Partner Geological and geophysical expenses 113 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 371 - Pedro Aylwin Executive Director (b) 2015 To be recovered from co-venturers - 4,634 Joint Operations Joint Operations Prepayments and other receivables - 38 LGI Partner Payables account - (21,045) LGI Partner To be paid to co-venturers - (113) Joint Operations Joint Operations Financial results 1,560 - LGI Partner Geological and geophysical expenses 101 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 66 - Carlos Gulisano Non-Executive Director (a) Administrative expenses 377 - Pedro Aylwin Executive Director (b) (a) Corresponding to consultancy services. (b) Corresponding to wages and salaries for US$ 271,000 246,000 317,000 140,000 125,000 60,000

Fees paid to Auditors (Tables)

Fees paid to Auditors (Tables)	12 Months Ended
	Dec. 31, 2017
Auditor's remuneration [abstract]
Disclosure of detailed information about auditors' remuneration [Text Block]	Amounts in US$ '000 2017 2016 2015 Audit fees 726 487 557 Audit related fees 137 - - Tax services fees 212 134 129 Non-audit services fees 39 - - Fees paid to auditors 1,114 621 686

Impairment test on Property, 75

Impairment test on Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of impairment of assets [Abstract]
Disclosure of detailed information about oil price scenarios [text block]	Table Oil price scenarios (a) Amounts in US$ per Bbl. Weighted market price used for the Year Low price (15%) Middle price (60%) High price (25%) impairment test 2018 64.9 64.9 64.9 64.9 2019 53.2 62.5 71.7 63.4 2020 54.4 63.9 73.4 64.9 Over 2021 54.3 63.7 73.2 64.7 (a) The percentages indicated between brackets represent the Group estimation regarding each price scenario.

Supplemental information on o76

Supplemental information on oil and gas activities (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Supplemental information on oil and gas activities [Abstract]
Disclosure of detailed information about cost incurred in oil and gas property acquisition, exploration, and development activities [text block]	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.
Disclosure of capitalized costs relating to oil and gas producing activities disclosure [text block]	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 45,059,000
Disclosure Of Detailed Information About Results Of Operations For Oil And Gas Producing Activities [text block]	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.
Disclosure Of Detailed Information About Proved Developed And Undeveloped Oil And Gas Reserve Quantities [text block]	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 Natural gas Oil and Natural gas Oil and Natural gas 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 99 91 20 2 1 9 31.2 (b) Llanos 34 Block, Cuerva Block and Yamu Block account for 98 1 1 99 1 94 3 20 (c) BCAM-40 Block accounts for 100 (d) Morona Block accounts for 100 (e) Fell Block accounts for 97 99 100 20 3 1 31.2 (f) Llanos 34, Cuerva Block and Yamu Block account for 97 2 1 100 95 4 20
Disclosure Of Detailed Information About Increasedecrease In Proved Reserves [text block]	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 - The impact of lower average oil prices resulting in a 2 1 - 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 - Better than expected performance from existing wells, resulting in an increase of 9 8 1 - Such increase was partially offset by lower average oil prices impacting the La Cuerva and Yamu blocks in Colombia, resulting in a 2 (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 - 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 - The impact of higher average oil prices resulting in a 2.5 0.4 - 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 (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 - Better than expected performance from existing wells that resulted in an increase of 13 3 10 - 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 9 4 (d) For the year ended 31 December 2017, the Group’s proved natural gas reserves were revised downwards by 13.7 - 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 - The above was partially offset by an increase of 6.8 0.8 (e) In Chile, the extensions and discoveries are primary due to the Uaken Field discovery in the Fell Block.
Disclosure Of Detailed Information About Standardized Measure Of Discounted Future Cash Flows Related To Proved Reserves [text block]	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
Disclosure Of Detailed Information About Changes In Standardized Measure Of Discounted Future Net Cash Flows [text block]	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

Summary of significant accoun77

Summary of significant accounting policies (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure summary of significant accounting policies [Line Items]
Capitalisation rate of borrowing costs eligible for capitalisation	6.90%	7.98%	7.98%
Borrowing costs capitalised	$ 610,841	$ 254,950	$ 637,390
Reversal of impairment loss		5,664,000
Impairment loss	$ 0		149,574,000
Percentage of debt maturing in more than five years	99.00%
Write-off of Unsuccessful Exploration Efforts	$ 5,834,000	$ 31,366,000	$ 30,084,000
Deferred Tax Liability Unrecognised	$ 12,300,000
Top of range [member]
Disclosure summary of significant accounting policies [Line Items]
Useful lives or depreciation rates, property, plant and equipment	10 years	10 years	10 years
Bottom of range [member]
Disclosure summary of significant accounting policies [Line Items]
Useful lives or depreciation rates, property, plant and equipment	3 years	3 years	3 years

Financial Instruments-risk ma78

Financial Instruments-risk management (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Financial Instruments-risk management [Abstract]
Net Debt	$ 291,449	$ 285,109
Total Equity	126,840	141,593	$ 200,167	$ 479,126
Capital	$ 418,289	$ 426,702
Gearing Ratio	70.00%	67.00%

Financial Instruments-risk ma79

Financial Instruments-risk management (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Financial Instruments-risk management [Line Items]
Foreign exchange gain (loss)	$ (2,193,000)	$ 13,872,000	$ (33,474,000)
Percentage of debt maturing in more than five years	99.00%
Borrowings, maturity	21 September 2024
Borrowings	$ 426,204,000	$ 358,672,000
Borrowings, interest rate	6.50%	7.50%
Gearing Ratio	70.00%	67.00%
Notional amount	$ 425,000,000
Proceeds from borrowings, classified as financing activities	$ 425,000,000	$ 186,000	7,036,000
Senior Secured Notes [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Borrowings, maturity		2,020
Borrowings, interest rate		7.50%
Fixed interest rate [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Borrowings, interest rate	6.50%
Colombian subsidiary oil sales to Trafigura [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Percentage of entity's revenue	99.00%
Currency risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Description Of Currency Devaluation Effect On Post Tax Loss	If the Argentine Peso, the Chilean Peso and the Colombian Peso had each devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$1,538,000 (US$2,683,400 in 2016 and US$ 1,003,300 in 2015).
Liquidity risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Cash	$ 134,755,000
Percentage of debt maturing in more than five years	99.00%
Barrels of oil equivalent per day in production at year end	31,000
Liquidity risk [member] | Trafigura [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Available credit line		$ 100,000,000	$ 100,000,000
Outstanding amounts payable	$ 10,000,000
Commodity price risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Description of fluctuation in price levels	If oil and methanol prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax loss for the year would have been higher by US$ 10,423,000 (US$ 23,655,000 in 2016 and US$ 23,940,000 in 2015).
Interest Rate Risk [Member] | Fixed interest rate [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Borrowings	$ 425,000,000
Interest Rate Risk [Member] | Floating interest rate [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Description of fluctuation in interest rate	At 31 December 2017, the Group has no exposure to fluctuations in the interest rate, since its long-term borrowings were issued at fixed rate. At 31 December 2016 and 2015, if 1% had been added to interest rates on currency-denominated borrowings with all other variables held constant, post tax loss for the year would have been US$ 467,000 and US$ 507,000 higher, respectively.
Credit Risk [Member] | Bottom of range [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Gearing Ratio	30.00%	30.00%	30.00%
Credit Risk [Member] | Top of range [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Gearing Ratio	45.00%	45.00%	45.00%
Credit Risk [Member] | Trafigura [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Percentage of entity's revenue	79.00%
Credit Risk [Member] | ENAP [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Percentage of entity's revenue	5.00%	10.00%	15.00%
Credit Risk [Member] | Methanex Chile S.A. [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Percentage of entity's revenue	5.00%	9.00%	7.00%
Credit Risk [Member] | Petrobras Brazil [Member]
Disclosure Of Financial Instruments-risk management [Line Items]
Percentage of entity's revenue	10.00%	15.00%	15.00%
Argentine Peso [Member] | Currency risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Currency Devaluation Percentage Against Dollar	17.00%	22.00%	52.00%
Chilean Peso [Member] | Currency risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Currency Devaluation Percentage Against Dollar			16.00%
Currency Revaluation Percentage Against Dollar	8.00%	6.00%
Colombian Peso [Member] | Currency risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Currency Devaluation Percentage Against Dollar			32.00%
Currency Revaluation Percentage Against Dollar	1.00%	5.00%
Brazilian Real [Member] | Currency risk [member]
Disclosure Of Financial Instruments-risk management [Line Items]
Currency Devaluation Percentage Against Dollar	2.00%		47.00%
Description Of Currency Devaluation Effect On Post Tax Loss	If the Brazilian Real had devaluated 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 3,100,000 (US$ 5,300,000 in 2016 and US$ 7,400,000 in 2015).
Foreign exchange gain (loss)	$ 1,274,000	$ 14,542,000	$ 35,605,000
Currency Revaluation Percentage Against Dollar		17.00%

Consolidated Statement of Cas80

Consolidated Statement of Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Consolidated Statement Of Cash Flow [Abstract]
Increase in asset retirement obligation	$ 5,943	$ 1,195	$ 985
Increase in provisions for other long-term liabilities	2,053	3,468	0
Purchase of property, plant and equipment	$ 11,759	$ (4,657)	$ 830

Consolidated Statement of Cas81

Consolidated Statement of Cash Flow (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Consolidated Statement Of Cash Flow [Abstract]
Increase in Prepaid taxes	$ (14,802)	$ (2,351)	$ (16,611)
(Increase) Decrease in Inventories	(2,031)	466	2,752
(Increase) Decrease in Trade receivables	(1,344)	(4,811)	22,470
(Increase) Decrease in Prepayments and other receivables and Other assets	(8,623)	(1,758)	405
Customer advance (repayments) payments	(10,000)	20,000	0
Security deposit granted (Note 35)	(15,600)	0	0
Increase (Decrease) in Trade and other payables	27,122	374	(33,120)
Increase (decrease) in working capital	$ (25,278)	$ 11,920	$ (24,104)

Segment information (Details)

Segment information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Number	Dec. 31, 2016USD ($)Number	Dec. 31, 2015USD ($)Number
Disclosure of Segment information [Line Items]
Revenue	$ 330,122	$ 192,670	$ 209,690
Sale of crude oil	279,162	145,193	162,629
Sale of gas	50,960	47,477	47,061
Production and operating costs	98,987	67,235	86,742
Royalties	28,697	11,497	13,155
Transportation costs	864	3,559	4,760
Share-based payment	4,075	3,367	8,223
Operating (loss) profit	78,996	(28,613)	(232,491)
Depreciation	74,885	75,774	105,557
Impairment loss reversed (recognised)	0	5,664	$ (149,574)
Total assets	$ 786,163	$ 640,540
Employees at year end | Number	405	345	352
Other Segments [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 330,122	$ 192,670	$ 209,690
Sale of crude oil	279,162	145,193	162,629
Sale of gas	50,960	47,477	47,061
Realized loss on commodity risk management contracts	(2,148)	514
Production and operating costs	(98,987)	(67,235)	(86,742)
Royalties	(28,697)	(11,497)	(13,155)
Transportation costs	(2,969)	(2,281)	(4,511)
Share-based payment	(457)	(622)	(563)
Other costs	(66,864)	(52,835)	(68,513)
Operating (loss) profit	78,996	(28,613)	(232,491)
Operating netback	228,308	122,147	118,027
Adjusted EBITDA	175,776	78,321	73,787
Depreciation	(74,885)	(75,774)	(105,557)
Impairment loss reversed (recognised)		5,664	(149,574)
Write-off	(5,834)	(31,366)	(30,084)
Total assets	$ 786,163	$ 640,540	$ 703,799
Employees (average)	379	341	403
Employees at year end	405	345	352
Chile [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 32,738	$ 36,723	$ 44,808
Sale of crude oil	15,873	18,774	29,180
Sale of gas	16,865	17,949	15,628
Realized loss on commodity risk management contracts	0	0
Production and operating costs	(20,999)	(22,169)	(28,704)
Royalties	(1,314)	(1,495)	(1,973)
Transportation costs	(1,211)	(1,170)	(2,441)
Share-based payment	(170)	(138)	(132)
Other costs	(18,304)	(19,366)	(24,158)
Operating (loss) profit	(19,675)	(44,969)	(180,264)
Operating netback	11,222	13,696	15,254
Adjusted EBITDA	4,070	5,159	(183)
Depreciation	(23,730)	(31,355)	(39,227)
Impairment loss reversed (recognised)		0	(104,515)
Write-off	(546)	(19,389)	(25,751)
Total assets	$ 301,931	$ 317,969	$ 381,143
Employees (average)	102	102	153
Employees at year end	102	102	106
Brazil [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 34,238	$ 29,719	$ 32,388
Sale of crude oil	910	688	955
Sale of gas	33,328	29,031	31,433
Realized loss on commodity risk management contracts	0	0
Production and operating costs	(10,737)	(8,459)	(8,056)
Royalties	(3,134)	(2,721)	(2,998)
Transportation costs	0	0	0
Share-based payment	(39)	(71)	0
Other costs	(7,564)	(5,667)	(5,058)
Operating (loss) profit	4,434	(645)	6,639
Operating netback	23,540	21,356	24,393
Adjusted EBITDA	20,166	17,487	20,460
Depreciation	(10,809)	(12,974)	(13,568)
Impairment loss reversed (recognised)		0	0
Write-off	(2,978)	(4,583)	0
Total assets	$ 91,604	$ 99,904	$ 114,974
Employees (average)	12	10	11
Employees at year end	12	10	12
Colombia [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 263,076	$ 126,228	$ 131,897
Sale of crude oil	262,309	125,731	131,897
Sale of gas	767	497	0
Realized loss on commodity risk management contracts	(2,148)	514
Production and operating costs	(66,913)	(36,607)	(48,534)
Royalties	(24,236)	(7,281)	(8,150)
Transportation costs	(1,678)	(1,111)	(2,068)
Share-based payment	(248)	(413)	(234)
Other costs	(40,751)	(27,802)	(38,082)
Operating (loss) profit	116,290	31,463	(37,227)
Operating netback	194,013	87,523	80,355
Adjusted EBITDA	168,303	66,921	66,736
Depreciation	(40,010)	(31,148)	(52,434)
Impairment loss reversed (recognised)		5,664	(45,059)
Write-off	(1,625)	(7,394)	(4,333)
Total assets	$ 288,429	$ 182,784	$ 153,071
Employees (average)	164	138	130
Employees at year end	180	146	133
Peru [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 0	$ 0	$ 0
Sale of crude oil	0	0	0
Sale of gas	0	0	0
Realized loss on commodity risk management contracts	0	0
Production and operating costs	0	0	0
Royalties	0	0	0
Transportation costs	0	0	0
Share-based payment	0	0	0
Other costs	0	0	0
Operating (loss) profit	(3,850)	(3,147)	(6,719)
Operating netback	0	41	44
Adjusted EBITDA	(3,505)	(2,607)	(6,520)
Depreciation	(139)	(130)	(129)
Impairment loss reversed (recognised)		0	0
Write-off	0	0	0
Total assets	$ 22,099	$ 5,020	$ 4,287
Employees (average)	13	11	16
Employees at year end	19	10	11
Argentina [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 70	$ 0	$ 597
Sale of crude oil	70	0	597
Sale of gas	0	0	0
Realized loss on commodity risk management contracts	0	0
Production and operating costs	(338)	0	(1,448)
Royalties	(13)	0	(34)
Transportation costs	(80)	0	(2)
Share-based payment	0	0	(197)
Other costs	(245)	0	(1,215)
Operating (loss) profit	(3,430)	370	(2,350)
Operating netback	(467)	(378)	(1,732)
Adjusted EBITDA	(2,183)	1,848	(684)
Depreciation	(159)	(150)	(199)
Impairment loss reversed (recognised)		0	0
Write-off	(685)	0	0
Total assets	$ 30,924	$ 6,071	$ 3,181
Employees (average)	88	80	93
Employees at year end	92	77	90
Corporate [Member]
Disclosure of Segment information [Line Items]
Revenue	$ 0	$ 0	$ 0
Sale of crude oil	0	0	0
Sale of gas	0	0	0
Realized loss on commodity risk management contracts	0	0
Production and operating costs	0	0	0
Royalties	0	0	0
Transportation costs	0	0	0
Share-based payment	0	0	0
Other costs	0	0	0
Operating (loss) profit	(14,773)	(11,685)	(12,570)
Operating netback	0	(91)	(287)
Adjusted EBITDA	(11,075)	(10,487)	(6,022)
Depreciation	(38)	(17)	0
Impairment loss reversed (recognised)		0	0
Write-off	0	0	0
Total assets	$ 51,176	$ 28,792	$ 47,143
Employees (average)	0	0	0
Employees at year end	0	0	0

Segment information (Details 1)

Segment information (Details 1) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Segment information [Line Items]
Administrative expenses		$ (42,054)	$ (34,170)	$ (37,471)
Geological and geophysical expenses		(7,694)	(10,282)	(13,831)
Unrealized loss on commodity risk management contracts		(13,300)	(3,068)	0
Depreciation		(74,885)	(75,774)	(105,557)
Share-based payment		(4,075)	(3,367)	(8,223)
Operating profit (loss)		78,996	(28,613)	(232,491)
Financial expenses		(53,511)	(36,229)	(36,924)
Financial income		2,016	2,128	1,269
Foreign exchange (loss) profit		(2,193)	13,872	(33,474)
Profit (Loss) before tax		25,308	(48,842)	(301,620)
Reportable segments [member]
Disclosure of Segment information [Line Items]
Operating netback		228,308	122,147	118,027
Administrative expenses		(38,937)	(32,323)	(30,590)
Geological and geophysical expenses		(13,595)	(11,503)	(13,650)
Adjusted EBITDA for reportable segments		175,776	78,321	73,787
Unrealized loss on commodity risk management contracts		(13,300)	(3,068)	0
Depreciation	[1]	(74,885)	(75,774)	(105,557)
Share-based payment		(4,075)	(3,367)	(8,223)
Impairment and write-off of unsuccessful exploration efforts		(5,834)	(25,702)	(179,658)
Others	[2]	1,314	977	(12,840)
Operating profit (loss)		78,996	(28,613)	(232,491)
Financial expenses		(53,511)	(36,229)	(36,924)
Financial income		2,016	2,128	1,269
Foreign exchange (loss) profit		(2,193)	13,872	(33,474)
Profit (Loss) before tax		$ 25,308	$ (48,842)	$ (301,620)
[1]	Net of capitalised costs for oil stock included in Inventories.
[2]	In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs.

Segment information (Details Te

Segment information (Details Textual)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Chile [Member]
Disclosure of Segment information [Line Items]
Capital Expenditure Incurred Percentage	10.00%	20.00%	22.00%
Colombia [Member]
Disclosure of Segment information [Line Items]
Capital Expenditure Incurred Percentage	76.00%	67.00%	66.00%
Brazil [Member]
Disclosure of Segment information [Line Items]
Capital Expenditure Incurred Percentage	3.00%	9.00%	12.00%
Argentina [Member]
Disclosure of Segment information [Line Items]
Capital Expenditure Incurred Percentage	8.00%	4.00%	0.00%
Peru [Member]
Disclosure of Segment information [Line Items]
Capital Expenditure Incurred Percentage	3.00%	0.00%	0.00%

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Revenue [Line Items]
Sale of crude oil	$ 279,162	$ 145,193	$ 162,629
Sale of gas	50,960	47,477	47,061
Revenue	$ 330,122	$ 192,670	$ 209,690

Commodity risk management con86

Commodity risk management contracts (Details)	12 Months Ended
	Dec. 31, 2017bbl$ / bbl
1 October 2017 - 31 March 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium Collar
Derivative contracts, number of instruments held | bbl	4,000
1 October 2017 - 31 March 2018 [member] | Written put options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	50
1 October 2017 - 31 March 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	54.90
1 October 2017 - 31 March 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium Collar
Derivative contracts, number of instruments held | bbl	2,000
1 October 2017 - 31 March 2018 [member] | Written put options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	50
1 October 2017 - 31 March 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	54.95
1 January 2018 - 30 June 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium Collar
Derivative contracts, number of instruments held | bbl	2,000
1 January 2018 - 30 June 2018 [member] | Written put options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 January 2018 - 30 June 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	60
1 January 2018 - 30 June 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium Collar
Derivative contracts, number of instruments held | bbl	1,000
1 January 2018 - 30 June 2018 [member] | Written put options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 January 2018 - 30 June 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	58.40
1 April 2018 - 30 June 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium Collar
Derivative contracts, number of instruments held | bbl	2,000
1 April 2018 - 30 June 2018 [member] | Written put options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 April 2018 - 30 June 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	58.25
1 January 2018 - 30 June 2018[member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium 3 Way
Derivative contracts, number of instruments held | bbl	1,000
1 January 2018 - 30 June 2018[member] | Written put options [member] | Bottom of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	42
1 January 2018 - 30 June 2018[member] | Written put options [member] | Top of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 January 2018 - 30 June 2018[member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	59.55
1 January 2018 - 30 June 2018[member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium 3 Way
Derivative contracts, number of instruments held | bbl	1,000
1 January 2018 - 30 June 2018[member] | Written put options [member] | Bottom of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	42
1 January 2018 - 30 June 2018[member] | Written put options [member] | Top of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 January 2018 - 30 June 2018[member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	59.50
1 April 2018 - 30 June 2018 [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium 3 Way
Derivative contracts, number of instruments held | bbl	1,000
1 April 2018 - 30 June 2018 [member] | Written put options [member] | Bottom of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	42
1 April 2018 - 30 June 2018 [member] | Written put options [member] | Top of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	52
1 April 2018 - 30 June 2018 [member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	59.60
1 January 2018 - 30 June 2018[member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium 3 Way
Derivative contracts, number of instruments held | bbl	2,000
1 January 2018 - 30 June 2018[member] | Written put options [member] | Bottom of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	43
1 January 2018 - 30 June 2018[member] | Written put options [member] | Top of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	53
1 January 2018 - 30 June 2018[member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	64.55
1 July 2018 - 30 September 2018[member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivative contracts, Type of Instrument	Zero Premium 3 Way
Derivative contracts, number of instruments held | bbl	5,000
1 July 2018 - 30 September 2018[member] | Written put options [member] | Bottom of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	43
1 July 2018 - 30 September 2018[member] | Written put options [member] | Top of range [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	53
1 July 2018 - 30 September 2018[member] | Purchased call options [member]
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Derivaive price	69

Commodity risk management con87

Commodity risk management contracts (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Consolidated Statement Of Comprehensive Income [Line Items]
Realized (loss) gain on commodity risk management contracts	$ (2,148)	$ 514	$ 0
Unrealized loss on commodity risk management contracts	(13,300)	(3,068)	0
Total	$ (15,448)	$ (2,554)	$ 0

Production and operating cost88

Production and operating costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Production And Operating Costs [Line Items]
Well and facilities maintenance	$ 14,722	$ 13,160	$ 19,974
Staff costs (Note 11)	15,017	10,859	17,999
Share-based payment (Notes 11)	457	622	563
Royalties	28,697	11,497	13,155
Consumables	11,902	8,283	8,591
Transportation costs	2,969	2,281	4,511
Equipment rental	5,818	3,868	3,517
Safety and Insurance costs	2,591	2,222	3,239
Gas plant costs	6,069	6,300	2,878
Field camp	2,377	1,687	2,645
Non operated blocks costs	1,213	1,082	2,127
Other costs	7,155	5,374	7,543
Operating expense	$ 98,987	$ 67,235	$ 86,742

Depreciation (Details)

Depreciation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment	[1]	$ 75,075	$ 75,490	$ 104,040
Oil and gas assets [member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		57,725	61,080	84,849
Machinery [member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		14,558	10,788	15,467
Furniture and Fixtures [Member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		1,948	2,702	2,850
Buildings [member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		844	920	874
Productive Land [Member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		72,283	71,868	100,316
Administrative Assets [Member]
Disclosure Of Depreciation [Line Items]
Depreciation, property, plant and equipment		$ 2,792	$ 3,622	$ 3,724
[1]	Depreciation without considering capitalised costs for oil stock included in Inventories.

Staff costs and Directors Rem90

Staff costs and Directors Remuneration (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Number	Dec. 31, 2016USD ($)Number	Dec. 31, 2015USD ($)Number
Disclosure of Staff costs and Directors Remuneration [Line Items]
Number of employees at year end | Number	405	345	352
Wages and salaries	$ 44,891	$ 36,059	$ 40,574
Share-based payments (Note 30)	4,075	3,367	8,223
Social security charges	5,364	3,792	6,197
Director’s fees and allowance	3,458	2,088	1,238
Employee benefits expense	57,788	45,306	56,232
Salaries and fees	9,674	7,337	6,549
Share-based payments	2,322	1,211	6,544
Other benefits in kind	287	112	167
Key Management Personnel Compensation	12,283	8,660	13,260
Production and operating costs [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Employee benefits expense	15,474	11,481	18,562
Geological and geophysical expenses [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Employee benefits expense	11,026	10,439	11,336
Administrative expenses [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Employee benefits expense	$ 31,288	$ 23,386	$ 26,334

Staff costs and Directors Rem91

Staff costs and Directors Remuneration (Details 1) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)shares
Gerald O’Shaughnessy [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 400,000
Director Fees Paid as Shares | shares	0
James F. Park [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 1,600,000
Director Fees Paid as Shares | shares	0
Pedro Aylwin [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 0	[1]
Director Fees Paid as Shares | shares	0	[1]
Peter Ryalls [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 165,010	[2]
Director Fees Paid as Shares | shares	9,388	[2]
Juan Cristobal Pavez [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 210,020	[3]
Director Fees Paid as Shares | shares	15,408	[3]
Carlos Gulisano [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 210,020
Director Fees Paid as Shares | shares	15,408
Robert Bedingfield [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 202,520	[4]
Director Fees Paid as Shares | shares	15,408	[4]
Michael Dingman [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 105,012
Director Fees Paid as Shares | shares	8,853
Jamie Coulter [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 95,641
Director Fees Paid as Shares | shares	6,020
Executive Directors’ Fees [Member] | Gerald O’Shaughnessy [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 400,000
Executive Directors’ Fees [Member] | James F. Park [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	800,000
Executive Directors’ Fees [Member] | Pedro Aylwin [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[1]
Executive Directors’ Fees [Member] | Peter Ryalls [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[2]
Executive Directors’ Fees [Member] | Juan Cristobal Pavez [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[3]
Executive Directors’ Fees [Member] | Carlos Gulisano [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Fees [Member] | Robert Bedingfield [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[4]
Executive Directors’ Fees [Member] | Michael Dingman [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Fees [Member] | Jamie Coulter [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Bonus [Member] | Gerald O’Shaughnessy [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Bonus [Member] | James F. Park [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	800,000
Executive Directors’ Bonus [Member] | Pedro Aylwin [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[1]
Executive Directors’ Bonus [Member] | Peter Ryalls [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[2]
Executive Directors’ Bonus [Member] | Juan Cristobal Pavez [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[3]
Executive Directors’ Bonus [Member] | Carlos Gulisano [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Bonus [Member] | Robert Bedingfield [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[4]
Executive Directors’ Bonus [Member] | Michael Dingman [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Executive Directors’ Bonus [Member] | Jamie Coulter [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Non-Executive Directors’ Fees [Member] | Gerald O’Shaughnessy [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Non-Executive Directors’ Fees [Member] | James F. Park [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0
Non-Executive Directors’ Fees [Member] | Pedro Aylwin [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	0	[1]
Non-Executive Directors’ Fees [Member] | Peter Ryalls [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	115,000	[2]
Non-Executive Directors’ Fees [Member] | Juan Cristobal Pavez [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	110,000	[3]
Non-Executive Directors’ Fees [Member] | Carlos Gulisano [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	110,000
Non-Executive Directors’ Fees [Member] | Robert Bedingfield [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	102,500	[4]
Non-Executive Directors’ Fees [Member] | Michael Dingman [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	46,667
Non-Executive Directors’ Fees [Member] | Jamie Coulter [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Key management personnel compensation	$ 50,000
[1]	Pedro Aylwin has a service contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director.
[2]	Technical Committee Chairman until his death. Afterwards the Chairman is Carlos Gulisano.
[3]	Compensation Committee Chairman.
[4]	Audit Committee Chairman.

Staff costs and Directors Rem92

Staff costs and Directors Remuneration (Details Textual) - Non-Executive Directors Annual Fees [Member]	12 Months Ended
	Dec. 31, 2017USD ($)
Disclosure of Staff costs and Directors Remuneration [Line Items]
Non-executive Directors annual fees, Settled in Cash	$ 80,000
Non-executive Directors annual fees, Settled in Shares	100,000
Chairman Board of Committee [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Director Serving Board Committee, Annual Fees	20,000
Board of Committee [Member]
Disclosure of Staff costs and Directors Remuneration [Line Items]
Director Serving Board Committee, Annual Fees	$ 10,000

Geological and geophysical ex93

Geological and geophysical expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Geological and geophysical expenses [Line Items]
Staff costs (Note 11)	$ 10,525	$ 9,541	$ 10,557
Share-based payment (Notes 11)	501	898	779
Allocation to capitalised project	(6,402)	(2,119)	(598)
Other services	3,070	1,962	3,093
Geological and geophysical expenses	$ 7,694	$ 10,282	$ 13,831

Administrative expenses (Detail

Administrative expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Administrative expenses [Line Items]
Staff costs (Note 11)	$ 24,713	$ 19,451	$ 18,215
Share-based payment (Notes 11)	3,117	1,847	6,881
Consultant fees	5,120	3,894	4,115
Office expenses	2,506	2,217	2,535
Travel expenses	2,772	1,717	1,497
Director’s fees and allowance (Note 11)	3,458	2,088	1,238
Communication and IT costs	2,109	2,013	1,791
Allocation to joint operations	(7,646)	(4,365)	(4,203)
Other administrative expenses	5,905	5,308	5,402
Administrative expenses	$ 42,054	$ 34,170	$ 37,471

Selling expenses (Details)

Selling expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Selling expenses [Line Items]
Transportation	$ 864	$ 3,559	$ 4,760
Selling taxes and other	272	663	451
Sales and marketing expense	$ 1,136	$ 4,222	$ 5,211

Financial results (Details)

Financial results (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial expenses
Interest and amortisation of debt issue costs	$ (27,823)	$ (28,984)	$ (28,983)
Interest with related parties	(2,224)	(1,587)	(1,560)
Less: amounts capitalised on qualifying assets	611	255	637
Borrowings cancellation costs	(17,575)	0	0
Bank charges and other financial results	(3,721)	(3,220)	(4,443)
Unwinding of long-term liabilities (Note 28)	(2,779)	(2,693)	(2,575)
Financial expenses total	(53,511)	(36,229)	(36,924)
Financial income
Interest received	2,016	2,128	1,269
Financial income total	2,016	2,128	1,269
Foreign exchange gains and losses
Foreign exchange (loss) gain	(2,193)	13,872	(33,474)
Foreign exchange (loss) gain total	(2,193)	13,872	(33,474)
Total Financial results	$ (53,688)	$ (20,229)	$ (69,129)

Tax reforms (Details Textual)

Tax reforms (Details Textual)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Tax reforms [Line Items]
Carryforward period					12 years
Colombia [Member]
Disclosure of Tax reforms [Line Items]
Description of nature of potential income tax consequences that would result from payment of dividend					New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 5% for dividends distributed out of the distributing entity’s previously taxed profits; and (2) 35% for dividends distributed out of the distributing entity’s previously untaxed profits, plus an additional 5% after having applied and deducted the initial 35% withholding.
Value Added Tax Rate					19.00%	16.00%
Colombia [Member] | Scenario Forecasts [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate			33.00%	37.00%	40.00%
Colombia [Member] | Income tax [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					34.00%
Colombia [Member] | Income tax [Member] | Scenario Forecasts [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate				33.00%
Colombia [Member] | Surcharge [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					6.00%
Colombia [Member] | Surcharge [Member] | Scenario Forecasts [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate				4.00%
Colombia [Member] | Tax on deemed income [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					3.50%	3.00%
Colombia [Member] | income tax for non-residents [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					15.00%
Colombia [Member] | Capital gain Tax [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					10.00%
Argentina [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate					35.00%
Argentina [Member] | Scenario Forecasts [Member]
Disclosure of Tax reforms [Line Items]
Applicable tax rate	25.00%	25.00%	30.00%	30.00%
Description of nature of potential income tax consequences that would result from payment of dividend				New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 7% for dividends distributed out of the distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and (2) 13% for dividends distributed out of the distributing entity’s previously taxed profits of fiscal years 2020 and onwards.

Income tax (Details)

Income tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Income tax [Line Items]
Current tax	$ (48,449)	$ (12,359)	$ (7,262)
Deferred income tax (Note 18)	5,304	555	24,316
Tax expense (income), continuing operations	$ (43,145)	$ (11,804)	$ 17,054

Income tax (Details 1)

Income tax (Details 1) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Income tax [Line Items]
Profit (Loss) before tax		$ 25,308	$ (48,842)	$ (301,620)
Tax losses from non-taxable jurisdictions		22,708	12,318	15,852
Taxable profit (loss)		48,016	(36,524)	(285,768)
Income tax calculated at domestic tax rates applicable to Profit (Losses) Income in the respective countries		(31,107)	(809)	62,589
Tax losses where no deferred tax benefit is recognised		(8,111)	(6,616)	(16,325)
Effect of currency translation on tax base		(2,330)	(2,840)	(6,776)
Changes in the income tax rate (Note 16)		542	220	(625)
Non recoverable tax loss carry-forwards		0	0	(15,537)
Non-taxable results	[1]	(2,139)	(1,759)	(6,272)
Income tax		$ (43,145)	$ (11,804)	$ 17,054
[1]	Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities.

Income tax (Details 2)

Income tax (Details 2) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Income tax [Line Items]
Unused tax losses, deferred tax asset was recognised		$ 383,674	$ 299,255	$ 213,744
Argentina [Member]
Disclosure Of Income tax [Line Items]
Unused tax losses, deferred tax asset was recognised		4,849	2,908	3,834
Brazil [Member]
Disclosure Of Income tax [Line Items]
Unused tax losses, deferred tax asset was recognised	[1]	33,721	16,057	0
Chile [Member]
Disclosure Of Income tax [Line Items]
Unused tax losses, deferred tax asset was recognised	[1]	$ 345,104	$ 280,290	$ 209,910
[1]	Taxable losses have no expiration date.

Income tax (Details 3)

Income tax (Details 3) $ in Thousands	Dec. 31, 2017USD ($)
2,020
Disclosure Of Income tax [Line Items]
Taxable losses	$ 754
2,021
Disclosure Of Income tax [Line Items]
Taxable losses	1,446
2,022
Disclosure Of Income tax [Line Items]
Taxable losses	$ 2,649

Income tax (Details Textual)

Income tax (Details Textual)	12 Months Ended
	Dec. 31, 2017
Bottom of range [member]
Disclosure Of Income tax [Line Items]
Applicable tax rate	15.00%
Top of range [member]
Disclosure Of Income tax [Line Items]
Applicable tax rate	40.00%

Deferred income tax (Details)

Deferred income tax (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Disclosure of deferred income tax [Abstract]
Deferred tax at 1 January		$ 20,283	$ 17,691
Reclassification	[1]	0	574
Currency translation differences		(237)	1,463
Income statement credit		5,304	555
Deferred tax at 31 December		$ 25,350	$ 20,283
[1]	Corresponds to differences between income tax provision and the final tax return presented.

Deferred income tax (Details 1)

Deferred income tax (Details 1) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Disclosure of deferred income tax [Line Items]
At the beginning of year		$ 23,053	$ 34,646
Currency translation differences		(237)	1,463
(Charged) credited to net profit		4,820	(13,056)
At end of year		27,636	23,053
At the beginning of year		(2,770)	(16,955)
Credited to net profit		484	13,611
Reclassification	[1]	0	574
At end of year		(2,286)	(2,770)
Taxable losses
Disclosure of deferred income tax [Line Items]
At the beginning of year		3,828
Currency translation differences		0
(Charged) credited to net profit		7,637
At end of year		11,465	3,828
Difference in depreciation rates and other
Disclosure of deferred income tax [Line Items]
At the beginning of year		(17,308)
Credited to net profit		(2,766)
Reclassification	[1]	0
At end of year		(20,074)	(17,308)
Taxable losses
Disclosure of deferred income tax [Line Items]
At the beginning of year		14,538
Credited to net profit		3,250
Reclassification	[1]	0
At end of year		17,788	14,538
Difference in depreciation rates and other
Disclosure of deferred income tax [Line Items]
At the beginning of year		19,225
Currency translation differences		(237)
(Charged) credited to net profit		(2,817)
At end of year		$ 16,171	$ 19,225
[1]	Corresponds to differences between income tax provision and the final tax return presented.

Earnings per share (Details)

Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Loss for the year attributable to owners		$ (24,228)	$ (49,092)	$ (234,031)
Denominator:
(Losses) after tax per share (US$) - basic		$ (0.40)	$ (0.82)	$ (4.05)
Effect of dilutive potential common shares
(Losses) after tax per share (US$) - diluted		$ (0.40)	$ (0.82)	$ (4.05)
Retained Earnings [Member]
Numerator:
Loss for the year attributable to owners		$ (24,228)	$ (49,092)	$ (234,031)
Denominator:
Weighted average number of shares used in basic EPS	[1]	60,093,191	59,777,145	57,759,001
(Losses) after tax per share (US$) - basic		$ (0.40)	$ (0.82)	$ (4.05)
Weighted average number of shares used in basic EPS	[1]	60,093,191	59,777,145	57,759,001
Effect of dilutive potential common shares
Weighted average number of common shares for the purposes of diluted earnings per shares	[1]	60,093,191	59,777,145	57,759,001
(Losses) after tax per share (US$) - diluted	[1]	$ (0.40)	$ (0.82)	$ (4.05)
[1]	For the year ended 31 December 2017, there were 4,564,777 (1,390,706 in 2016 and 1,032,279 in 2015) of potential shares that could have a dilutive impact but were considered antidilutive due to negative earnings.

Earnings per share (Details Tex

Earnings per share (Details Textual)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of earning per share [Line Items]
Description of instruments with potential future dilutive effect not included in calculation of diluted earnings per share	4,564,777	1,390,706	1,032,279

Property, plant and equipmen107

Property, plant and equipment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		$ 473,646		$ 522,611
Depreciation	[1]	(75,075)		(75,490)		$ (104,040)
Property, plant and equipment		517,403		473,646		522,611
Oil and gas assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		307,502		327,819
Depreciation		(57,725)		(61,080)		(84,849)
Property, plant and equipment		334,970		307,502		327,819
Buildings [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		6,422		7,323
Depreciation		(844)		(920)		(874)
Property, plant and equipment		5,429		6,422		7,323
Construction in Progress [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		32,926		29,823
Property, plant and equipment		37,990		32,926		29,823
Furniture Equipment And Vehicle [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		4,308		6,428
Property, plant and equipment		3,482		4,308		6,428
Production facilities and machinery [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		60,715		64,218
Property, plant and equipment		71,164		60,715		64,218
Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		61,773		87,000
Property, plant and equipment		64,368		61,773		87,000
Gross carrying amount [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		944,263		914,910		1,083,046
Additions		125,359		35,844		45,428
Currency translation differences		(1,470)		19,233		(31,883)
Disposals		(301)		(22)		(2,023)
Write-off / Impairment loss		(5,834)		(25,702)		(179,658)
Transfers		0		0		0
Property, plant and equipment		1,062,017		944,263		914,910
Gross carrying amount [member] | Oil and gas assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		692,241		648,992		749,947
Additions	[2]	7,997		(3,531)		(4,640)
Currency translation differences		(1,142)		16,132		(27,522)
Disposals		0		0		(241)
Write-off / Impairment loss		0		5,664		(128,956)
Transfers		77,408		24,984		60,404
Property, plant and equipment		776,504		692,241		648,992
Gross carrying amount [member] | Buildings [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		10,553		10,518		9,527
Additions		0		0		272
Currency translation differences		(3)		35		(92)
Disposals		(189)		0		(84)
Write-off / Impairment loss		0		0		0
Transfers		0		0		895
Property, plant and equipment		10,361		10,553		10,518
Gross carrying amount [member] | Construction in Progress [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		32,926		29,823		59,425
Additions		66,953		20,322		36,543
Currency translation differences		(62)		73		0
Disposals		0		0		0
Write-off / Impairment loss		0		0		(7,376)
Transfers		(61,827)		(17,292)		(58,769)
Property, plant and equipment		37,990		32,926		29,823
Gross carrying amount [member] | Furniture Equipment And Vehicle [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		14,357		13,745		12,057
Additions		954		406		954
Currency translation differences		(12)		126		(182)
Disposals		(112)		(22)		(13)
Write-off / Impairment loss		0		0		0
Transfers		211		102		929
Property, plant and equipment		15,398		14,357		13,745
Gross carrying amount [member] | Production facilities and machinery [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		132,413		124,832		111,646
Additions		0		466		0
Currency translation differences		(147)		2,077		(2,577)
Disposals		0		0		(1,685)
Write-off / Impairment loss		0		0		(13,242)
Transfers		25,130		5,038		30,690
Property, plant and equipment		157,396		132,413		124,832
Gross carrying amount [member] | Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		61,773		87,000		140,444
Additions		49,455		18,181		12,299
Currency translation differences		(104)		790		(1,510)
Disposals		0		0		0
Write-off / Impairment loss		(5,834)	[3]	(31,366)	[4]	(30,084)	[5]
Transfers		(40,922)		(12,832)		(34,149)
Property, plant and equipment		64,368		61,773		87,000
Accumulated depreciation, amortisation and impairment [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		(470,617)		(392,299)		(292,279)
Currency translation differences		967		(2,836)		3,997
Depreciation		(75,075)		(75,490)		(104,040)
Disposals		111		8		23
Property, plant and equipment		(544,614)		(470,617)		(392,299)
Accumulated depreciation, amortisation and impairment [member] | Oil and gas assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		(384,739)		(321,173)		(240,439)
Currency translation differences		930		(2,486)		4,115
Depreciation		(57,725)		(61,080)		(84,849)
Disposals		0		0		0
Property, plant and equipment		(441,534)		(384,739)		(321,173)
Accumulated depreciation, amortisation and impairment [member] | Buildings [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		(4,131)		(3,195)		(2,244)
Currency translation differences		5		(16)		(92)
Depreciation		(844)		(920)		(874)
Disposals		38		0		15
Property, plant and equipment		(4,932)		(4,131)		(3,195)
Accumulated depreciation, amortisation and impairment [member] | Construction in Progress [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		0		0		0
Currency translation differences		0		0		0
Depreciation		0		0		0
Disposals		0		0		0
Property, plant and equipment		0		0		0
Accumulated depreciation, amortisation and impairment [member] | Furniture Equipment And Vehicle [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		(10,049)		(7,317)		(4,449)
Currency translation differences		8		(38)		(26)
Depreciation		(1,948)		(2,702)		(2,850)
Disposals		73		8		8
Property, plant and equipment		(11,916)		(10,049)		(7,317)
Accumulated depreciation, amortisation and impairment [member] | Production facilities and machinery [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		(71,698)		(60,614)		(45,147)
Currency translation differences		24		(296)		0
Depreciation		(14,558)		(10,788)		(15,467)
Disposals		0		0		0
Property, plant and equipment		(86,232)		(71,698)		(60,614)
Accumulated depreciation, amortisation and impairment [member] | Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		0		0		0
Currency translation differences		0		0		0
Depreciation		0		0		0
Disposals		0		0		0
Property, plant and equipment		$ 0		$ 0		$ 0
[1]	Depreciation without considering capitalised costs for oil stock included in Inventories.
[2]	Corresponds to the effect of change in estimate of assets retirement obligations.
[3]	Corresponds to five unsuccessful exploratory wells, one well drilled in Colombia (Llanos 34 Block), one well drilled in Brazil (REC-T-94 Block) and three non-operated wells drilled in Argentina (Puelen and Sierra del Nevado Blocks) in 2017. The charge also includes the loss generated by the write-off of the seismic cost for Campanario and Isla Norte Blocks in Chile generated by the relinquishment of 327 sq km in 2017.
[4]	Corresponds to the write-off of five wells drilled in previous years in the Chilean blocks for which no additional work would be performed, the loss generated by the write-off of the seismic cost for Llanos 62 Block in Colombia generated by the relinquishment of the area in September 2016. In addition, during September 2016, five blocks in Brazil were relinquished so the associated investment was written off.
[5]	Corresponds to the cost of two unsuccessful exploratory wells in Colombia (one well in CPO4 Block and one well in Llanos 32). The charge also includes the loss generated by the write-off of the seismic cost for Flamenco Block in Chile generated by the relinquishment of 143 sq km in November 2015 and the write off of two wells drilled in previous years in the same block for which no additional work would be performed.

Property, plant and equipmen108

Property, plant and equipment (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 517,403	$ 473,646	$ 522,611
Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	64,368	61,773	87,000
Exploration Wells [Member] | Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Additions	35,299	15,088
Write-offs	(3,664)	(19,949)
Transfers	(29,281)	(9,795)
Property, plant and equipment	$ 10,604	$ 8,250	$ 22,906

Property, plant and equipmen109

Property, plant and equipment (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 517,403	$ 473,646	$ 522,611
Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	64,368	61,773	87,000
seismic and other exploratory assets [Member] | Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	53,764	53,523	64,094
Exploration Wells [Member] | Exploration and evaluation assets [member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	10,604	$ 8,250	$ 22,906
Exploration Wells [Member] | Exploration and evaluation assets [member] | Period of capitalization less than one year [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	4,488
Exploration Wells [Member] | Exploration and evaluation assets [member] | Period of capitalization more than one year [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 6,116

Subsidiary undertakings (Detail

Subsidiary undertakings (Details)	12 Months Ended
	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Proportion of ownership interest in subsidiary	100.00%
Flamenco Block Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Flamenco Block (Chile)
Proportion of ownership interest in subsidiary	50.00%	[1]
Campanario Block Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Campanario Block (Chile)
Proportion of ownership interest in subsidiary	50.00%	[1]
Isla Norte Block Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Isla Norte Block (Chile)
Proportion of ownership interest in subsidiary	60.00%	[1]
YamuCarupana Block Colombia [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Yamu/Carupana Block (Colombia)
Proportion of ownership interest in subsidiary	89.50%	[1]
Llanos 32 Block Colombia [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Llanos 32 Block (Colombia)
Proportion of ownership interest in subsidiary	12.50%
CPO-4 Block (Colombia) [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	CPO-4 Block (Colombia)
Proportion of ownership interest in subsidiary	50.00%	[1]
Puelen Block Argentina [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Puelen Block (Argentina)
Proportion of ownership interest in subsidiary	18.00%
Sierra del Nevado Block Argentina [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Sierra del Nevado Block (Argentina)
Proportion of ownership interest in subsidiary	18.00%
CN-V Block Argentina [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	CN-V Block (Argentina)
Proportion of ownership interest in subsidiary	50.00%	[1]
Manati Field Brazil [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Manati Field (Brazil)
Proportion of ownership interest in subsidiary	10.00%
Tranquilos Block Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Tranquilo Block (Chile)
Proportion of ownership interest in subsidiary	50.00%
GeoPark Argentina Limited - Bermuda [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Argentina Limited (Bermuda)
Proportion of ownership interest in subsidiary	100.00%
GeoPark Argentina Limited - Argentinean Branch [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Argentina Limited – Argentinean Branch
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Latin America Limited (Bermuda) [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Latin America Limited (Bermuda)
Proportion of ownership interest in subsidiary	100.00%
GeoPark Latin America Limited - Agencia en Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Latin America Limited – Agencia en Chile
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark S.A. Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark S.A. (Chile)
Proportion of ownership interest in subsidiary	100.00%	[2],[3]
GeoPark Brazil Exploracao y Producao de Petroleo e Gas Ltda. Brazil [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Chile S.A. Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Chile S.A. (Chile)
Proportion of ownership interest in subsidiary	80.00%	[2],[4]
GeoPark Fell S.p.A. Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Fell S.p.A. (Chile)
Proportion of ownership interest in subsidiary	80.00%	[2],[4]
GeoPark Magallanes Limitada Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Magallanes Limitada (Chile)
Proportion of ownership interest in subsidiary	80.00%	[2],[4]
GeoPark Colombia S.A. Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Colombia S.A. (Chile)
Proportion of ownership interest in subsidiary	100.00%	[2],[3]
GeoPark Colombia SAS Colombia [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Colombia SAS (Colombia)
Proportion of ownership interest in subsidiary	80.00%	[2],[4]
GeoPark Colombia Cooperatie U.A. The Netherlands [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Colombia Coöperatie U.A. (The Netherlands)
Proportion of ownership interest in subsidiary	80.00%	[2],[4]
GeoPark S.A.C. Peru [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark S.A.C. (Peru)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Peru S.A.C. Peru [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Perú S.A.C. (Peru)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Operadora del Peru S.A.C. Peru [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Operadora del Perú S.A.C. (Peru)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Colombia E and P S.A.(Panama) [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Colombia E&P S.A.(Panama)
Proportion of ownership interest in subsidiary	100.00%	[2],[3]
GeoPark Colombia E and P Sucursal Colombia (Colombia) [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Colombia E&P Sucursal Colombia (Colombia)
Proportion of ownership interest in subsidiary	100.00%	[2],[3]
GeoPark Latin America S.L.U. Spain [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Latin America S.L.U. (Spain)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Peru S.L.U. Spain [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Peru S.L.U. (Spain)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Brazil S.L.U. Spain [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Brazil S.L.U. (Spain)
Proportion of ownership interest in subsidiary	100.00%	[2]
GeoPark Mexico S.A.P.I. de C.V. Mexico [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark Mexico S.A.P.I. de C.V. (Mexico)
Proportion of ownership interest in subsidiary	100.00%	[3]
Ogarrio E and P S.A.P.I. de C.V. (Mexico) [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	Ogarrio E&P S.A.P.I. de C.V. (Mexico)
Proportion of ownership interest in subsidiary	51.00%	[2],[3]
GeoPark UK Limited United Kingdom [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark (UK) Limited (United Kingdom)
Proportion of ownership interest in subsidiary	100.00%
GeoPark TdF S.A. Chile [Member]
Disclosure of subsidiaries [line items]
Name of subsidiary	GeoPark TdF S.A. (Chile)
Proportion of ownership interest in subsidiary	68.80%	[2],[5]
[1]	GeoPark is the operator.
[2]	Indirectly owned.
[3]	Dormant companies.
[4]	LG International has 20% interest.
[5]	LG International has 20% interest through GeoPark Chile S.A. and a 14% direct interest, totaling 31.2%.

Subsidiary undertakings (Det111

Subsidiary undertakings (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of subsidiaries [line items]
Profit (loss), attributable to non-controlling interests	$ 6,391	$ (11,554)	$ (50,535)
Non-controlling interests	41,915	35,828
Dividends recognised as distributions to non-controlling interests	$ (479)	(6,406)
Proportion of ownership interest in subsidiary	100.00%
LG International Corp [Member]
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	20.00%
LG International Corp [Member] | Direct Interest [Member]
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	14.00%
LG International Corp [Member] | Total Interest [Member]
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	31.20%
GeoPark Chile S.A [Member]
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	20.00%
Profit (loss), attributable to non-controlling interests	$ (6,200)	(10,379)	(33,260)
Non-controlling interests	15,953	22,082
GeoPark Colombia Cooperatie U.A [Member]
Disclosure of subsidiaries [line items]
Profit (loss), attributable to non-controlling interests	13,536	2,791	(7,085)
Non-controlling interests	29,330	16,168
Dividends recognised as distributions to non-controlling interests	479	6,406
GeoPark TdF S.A [Member]
Disclosure of subsidiaries [line items]
Profit (loss), attributable to non-controlling interests	(945)	(3,966)	$ (10,190)
Non-controlling interests	$ (3,368)	$ (2,422)

Prepaid taxes (Details)

Prepaid taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Prepaid taxess [Line Items]
V.A.T.	$ 27,674	$ 14,052
Income tax payments in advance	1,258	4,517
Other prepaid taxes	939	98
Total prepaid taxes	29,871	18,667
Classified as follows:
Current	26,048	15,815
Non current	3,823	2,852
Total prepaid taxes	$ 29,871	$ 18,667

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Inventories [Line Items]
Crude oil	$ 1,969	$ 1,521
Materials and spares	3,769	1,994
Inventories	$ 5,738	$ 3,515

Trade receivables and Prepay114

Trade receivables and Prepayments and other receivables (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Trade receivables and Prepayments and other receivables [Line Items]
Trade receivables	$ 19,519	$ 18,426
To be recovered from co-venturers (Note 33)	2,455	3,311
Related parties receivables (Note 33)	56	42
Prepayments and other receivables	5,242	4,290
Prepayments and accrued income	7,753	7,643
Total	27,272	26,069
Current	27,037	25,828
Non current	235	241
Total	$ 27,272	$ 26,069

Trade receivables and Prepay115

Trade receivables and Prepayments and other receivables (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Trade receivables and Prepayments and other receivable [Line Items]
At 1 January	$ 741	$ 596
Foreign exchange (income) loss	(147)	145
At 31 December	$ 594	$ 741

Trade receivables and Prepay116

Trade receivables and Prepayments and other receivables (Details Textual) - Trade receivables [member] - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of financial assets [line items]
Credit period for trade receivables	30 days	30 days
Later than three months [member] | Financial assets past due but not impaired [member]
Disclosure of financial assets [line items]
Financial assets	$ 0	$ 0
Later than one month and not later than two months [member] | Financial assets past due but not impaired [member]
Disclosure of financial assets [line items]
Financial assets	$ 0	$ 0

Financial instruments by cat117

Financial instruments by category (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Liabilities at fair value through profit and loss
Financial liabilities		$ 539,249	$ 414,804
Derivative financial instrument liabilities		19,289	3,067
Financial liabilities at fair value through profit or loss		19,289	3,067
Loans and Receivables
Loans and receivables		200,217	117,327
Other Financial Liabilities At Amortised Cost
Other financial liabilities at amortised cost		519,960	411,737
Trade payables [Member]
Other Financial Liabilities At Amortised Cost
Other financial liabilities at amortised cost		52,557	23,650
Payables to related [Member]
Other Financial Liabilities At Amortised Cost
Other financial liabilities at amortised cost		31,184	27,801
To be paid to co-venturers [Member]
Other Financial Liabilities At Amortised Cost
Other financial liabilities at amortised cost		10,015	1,614
Borrowing [Member]
Other Financial Liabilities At Amortised Cost
Other financial liabilities at amortised cost		426,204	358,672
To be recovered from co-venturers [Member]
Loans and Receivables
Loans and receivables		2,455	3,311
Other financial assets [Member]
Loans and Receivables
Loans and receivables	[1]	43,488	22,027
Trade receivables [member]
Loans and Receivables
Loans and receivables		19,519	18,426
Cash and cash equivalents [Member]
Loans and Receivables
Loans and receivables		$ 134,755	$ 73,563
[1]	Non current other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations and also include a non current account receivable with the previous owners of one of the Colombian subsidiaries (see Note 28). Current other financial assets corresponds to the security deposit granted in relation to the purchase of Argentinian assets (see Note 35) and short term investments with original maturities up to twelve months and over three months.

Financial instruments by cat118

Financial instruments by category (Details 1) - Financial assets neither past due nor impaired [member] - Trade receivables [member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Financial instruments by category [Line Items]
Financial assets	$ 19,519	$ 18,426
Existing customers (more than 6 months) with no defaults in the past [Member]
Disclosure of Financial instruments by category [Line Items]
Financial assets	7,047	7,641
External credit rating B2
Disclosure of Financial instruments by category [Line Items]
Financial assets	70	7,056
External credit rating Ba3
Disclosure of Financial instruments by category [Line Items]
Financial assets	8,788	0
External credit rating Baa3
Disclosure of Financial instruments by category [Line Items]
Financial assets	$ 3,614	$ 3,729

Financial instruments by cat119

Financial instruments by category (Details 2) - Financial assets neither past due nor impaired [member] - Cash at bank and other financial asset [Member] - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	$ 178,222	$ 95,578
Unrated credit exposure [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	45,123	44,252
External credit rating A1 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	553	813
External credit rating A2 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	298	0
External credit rating A3 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	63,853	0
External credit rating Aaa [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	15,040	0
External credit rating Aa3 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	11,401	42,798
External credit rating AAA [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	19,634	14
External credit rating Baa2 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	4,078	4,094
External credit rating Ba1 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	18	0
External credit rating Baa1 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	307	100
External credit rating Ba2 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	7	0
External credit rating B2 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	31	0
External credit rating Ba3 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	2,815	3,497
External credit rating BBB [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	15,064	0
External credit rating B3 [Member]
Disclosure of Financial instrument category [Line Items]
Financial assets	[1]	$ 0	$ 10
[1]	The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21,000 (US$ 12,000 in 2016).

Financial instruments by cat120

Financial instruments by category (Details 3) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Not later than one year [member]
Disclosure of detailed information about financial instruments [line items]
Bank borrowings, undiscounted cash flows	$ 27,625	$ 48,958
Trade and other payables, undiscounted cash flows	52,557	23,650
Payables to related parties, undiscounted cash flows	7,331	1,561
Non-derivative financial liabilities, undiscounted cash flows	87,513	74,169
Later than one year and not later than two years [member]
Disclosure of detailed information about financial instruments [line items]
Bank borrowings, undiscounted cash flows	27,625	43,304
Trade and other payables, undiscounted cash flows	0	0
Payables to related parties, undiscounted cash flows	2,068	1,561
Non-derivative financial liabilities, undiscounted cash flows	29,693	44,865
Later than two years and not later than five years [member]
Disclosure of detailed information about financial instruments [line items]
Bank borrowings, undiscounted cash flows	82,875	355,064
Trade and other payables, undiscounted cash flows	0	0
Payables to related parties, undiscounted cash flows	27,087	22,018
Non-derivative financial liabilities, undiscounted cash flows	109,962	377,082
Later than five years [member]
Disclosure of detailed information about financial instruments [line items]
Bank borrowings, undiscounted cash flows	480,250	0
Trade and other payables, undiscounted cash flows	0	0
Payables to related parties, undiscounted cash flows	0	0
Non-derivative financial liabilities, undiscounted cash flows	$ 480,250	$ 0

Financial instruments by cat121

Financial instruments by category (Details 4) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Liabilities
Total Liabilities	$ 19,289	$ 3,067
Level 2 of fair value hierarchy [member]
Liabilities
Total Liabilities	19,289
Recurring fair value measurement [member]
Liabilities
Total Liabilities		3,067
Recurring fair value measurement [member] | Level 2 of fair value hierarchy [member]
Liabilities
Total Liabilities		3,067
Recurring fair value measurement [member] | Commodity price risk [member]
Liabilities
Commodity risk management contracts	19,289	3,067
Recurring fair value measurement [member] | Commodity price risk [member] | Level 2 of fair value hierarchy [member]
Liabilities
Commodity risk management contracts	$ 19,289	$ 3,067

Financial instruments by cat122

Financial instruments by category (Details Textual) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Financial instruments by categorys [Line Items]
Cash on hand	$ 21,000	$ 12,000	$ 10,000
Financial liabilities, at fair value	$ 425,118,000	$ 346,180,000
Borrowings, interest rate	6.50%	7.50%
Financial liabilities [Member]
Disclosure of Financial instruments by categorys [Line Items]
Borrowings, interest rate	6.90%	7.60%

Share capital (Details)

Share capital (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 19, 2014
Disclosure Of Share capital [Line Items]
Common stock (amounts in US$ ‘000)	$ 61,000	$ 60,000	$ 59,000
Common shares, of nominal US$ 0.001	60,596,219	59,940,881
US$ per share	$ 0.001	$ 0.001		$ 0.001
Number of common shares (US$ 0.001 each)	5,171,949,000	5,171,949,000
Amount in US$	$ 5,171,949	$ 5,171,949
Ordinary shares [member]
Disclosure Of Share capital [Line Items]
Common shares, of nominal US$ 0.001	60,596,219	59,940,881

Share capital (Details 1)

Share capital (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Share capital [Line Items]
Number of shares issued	60,596,219	59,940,881
Number of shares outstanding	60,600,000	59,900,000	59,500,000
Issued capital	$ 61	$ 60	$ 59
Stock awards One [Member]
Disclosure Of Share capital [Line Items]
The date of common shares movement.	Jan. 1, 2017	Feb. 1, 2016
Number of shares issued	100,000	400,000
Number of shares outstanding	60,000,000	59,900,000
Issued capital	$ 60	$ 60
Stock awards Two [Member]
Disclosure Of Share capital [Line Items]
The date of common shares movement.	Dec. 1, 2017	Dec. 1, 2016
Number of shares issued	100,000	500,000
Number of shares outstanding	60,100,000	60,400,000
Issued capital	$ 60	$ 60
Stock awards Three [Member]
Disclosure Of Share capital [Line Items]
The date of common shares movement.	Dec. 1, 2017	Dec. 1, 2016
Number of shares issued	500,000	100,000
Number of shares outstanding	60,600,000	60,500,000
Issued capital	$ 61	$ 60
Buyback program [Member]
Disclosure Of Share capital [Line Items]
The date of common shares movement.		Dec. 1, 2016
Number of shares issued		(600,000)
Number of shares outstanding		59,900,000
Issued capital		$ 60

Share capital (Details Textual)

Share capital (Details Textual) - USD ($)	Dec. 14, 2017	Sep. 13, 2017	Dec. 15, 2016	Sep. 06, 2016	Feb. 08, 2016	Nov. 12, 2015	Jan. 31, 2017	Dec. 22, 2015	Nov. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 19, 2014
Disclosure Of Share capital [Line items]
Common shares issued to Non-Executive Directors										70,485	137,897	99,555
Share premium, common shares issued to Non-Executive Directors										$ 257,000	$ 541,848	$ 486,692
Par value per share										$ 0.001	$ 0.001		$ 0.001
Repurchase of common shares													$ 10,000,000
Increase (decrease) in number of shares outstanding										0	(588,868)	(370,074)
Purchase of treasury shares											$ 1,991,000	$ 1,615,000
Number of Shares Issued During the Period	490,000	12,546	379,500	8,333	468,405	817,600	82,306	478,000	720,000
Issue of equity	$ 2,513,000	$ 43,000	$ 3,940,000	$ 38,000	$ 1,512,000	$ 11,359,000	$ 332,000	$ 3,577,000	$ 7,309,000

Borrowings (Details)

Borrowings (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Borrowings [Line Items]
Borrowings		$ 426,204	$ 358,672
Current borrowings		7,664	39,283
Non-current portion of non-current borrowings		418,540	319,389
Notes GeoPark Latin America Agencia en Chile [Member]
Disclosure Of Borrowings [Line Items]
Borrowings	[1]	0	304,059
Banco Itau [Member]
Disclosure Of Borrowings [Line Items]
Borrowings	[2]	0	49,763
Banco de Chile [Member]
Disclosure Of Borrowings [Line Items]
Borrowings	[3]	0	4,709
Banco de Credito e Inversiones [Member]
Disclosure Of Borrowings [Line Items]
Borrowings	[4]	80	141
2024 Notes [Member]
Disclosure Of Borrowings [Line Items]
Borrowings	[5]	$ 426,124	$ 0
[1]	During February 2013, the Group successfully placed US$ 300,000,000 notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws. The Notes carried a coupon of 7.50% per annum and mature on 11 February 2020. These Notes were fully repaid in September 2017.
[2]	During March 2014, GeoPark executed a loan agreement with Itaú BBA International for US$ 70,450,000 to finance the acquisition of a 10% working interest in the Manatí field in Brazil. The loan was fully repaid in September 2017.
[3]	During December 2015, GeoPark executed a loan agreement with Banco de Chile for US$ 7,028,000 to finance the start-up of new Ache gas field in GeoPark-operated Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per annum. The interest and the principal have been paid on monthly basis; with a six months grace period, with final maturity on December 2017. As of the date of these Consolidated Financial Statements, the loan was fully repaid.
[4]	During February 2016, GeoPark executed a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of vehicles for the Chilean operation. The interest rate applicable to this loan is 4.14% per annum. The interest and the principal will be paid on monthly basis, with final maturity on February 2019.
[5]	During September 2017, the Company successfully placed US$ 425,000,000 notes which were offered to qualified institutional buyers in accordance with Rule 144A under the United States Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the United States Securities Act. The Notes carry a coupon of 6.50% per annum. Final maturity of the notes will be 21 September 2024. The Notes are secured with a pledge of all of the equity interests of the Company, directly or indirectly, in GeoPark Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance cost for this transaction amounted to US$ 6,683,000 (debt issuance effective rate: 6.90%). The indenture governing the Notes due 2024 includes incurrence test covenants that provides among other things, that, during the first two years from the issuance date, the Net Debt to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, as specified in the indenture governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others, (other than in each case, certain specific exceptions). As of the date of these Consolidated Financial Statements, the Company is in compliance of all the indenture’s provisions and covenants. The net proceeds from the Notes were used by the Company (i) to make a capital contribution to its wholly-owned subsidiary, GeoPark Latin America Limited Agencia en Chile (“GeoPark LA Agencia”), providing it with sufficient funds to fully repay the 7.50% senior secured notes due 2020 and to pay any related fees and expenses, including call premium, and (ii) for general corporate purposes, including capital expenditures and to repay existing indebtedness.

Borrowings (Details Textual)

Borrowings (Details Textual) - USD ($)	1 Months Ended	12 Months Ended
	Feb. 28, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Feb. 29, 2016	Mar. 31, 2014
Disclosure Of Borrowings [Line Items]
Borrowings, interest rate		6.50%	7.50%
Notional amount		$ 425,000,000
Borrowings, maturity		21 September 2024
Payments for debt issue costs		$ 6,683,000	$ 0	$ 0
Percentage of voting equity interests acquired		100.00%		100.00%
Line of credit facilities, remaining borrowing capacity		$ 33,000,000
Debt issuance effective rate		6.90%
Ratio Of Net Debt To Adjusted EBITDA		3.5
Ratio Of Adjusted EBITDA To Interest		2
Notes GeoPark Latin America Agencia en Chile [Member]
Disclosure Of Borrowings [Line Items]
Borrowings, interest rate	7.50%
Notional amount	$ 300,000,000
Borrowings, maturity	11 February 2020
Itau BBA International [Member]
Disclosure Of Borrowings [Line Items]
Notional amount							$ 70,450,000
Manati field [Member]
Disclosure Of Borrowings [Line Items]
Percentage of voting equity interests acquired							10.00%
Banco de Chile [Member]
Disclosure Of Borrowings [Line Items]
Notional amount				$ 7,028,000
Borrowings, maturity				31 December 2017
Borrowings, interest rate basis				LIBOR plus 2.35%
Borrowings, adjustment to interest rate basis				2.35%
Banco de Credito e Inversiones [Member]
Disclosure Of Borrowings [Line Items]
Borrowings, interest rate						4.14%
Notional amount						$ 186,000
2024 Notes [Member]
Disclosure Of Borrowings [Line Items]
Borrowings, interest rate					6.50%
Notional amount					$ 425,000,000

Provisions and other long-te128

Provisions and other long-term liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	$ 38,075	$ 29,862	$ 31,617
Deferred income	1,452	3,484	5,033
Other	6,757	9,163	5,800
Total	46,284	42,509	$ 42,450
Addition to provision [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	5,943	1,195
Deferred income	0	1,375
Other	2,220	2,686
Total	8,163	5,256
Recovery of abandonments costs [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation		(5,504)
Deferred income		0
Other		0
Total		(5,504)
Foreign currency translation [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	(134)	1,614
Deferred income	0	0
Other	0	0
Total	(134)	1,614
Exchange difference [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	134	(1,614)
Deferred income	0	0
Other	1,154	538
Total	1,288	(1,076)
Amortisation [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	0	0
Deferred income	(657)	(2,924)
Other	0	0
Total	(657)	(2,924)
Unwinding of discount [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	2,607	2,554
Deferred income	0	0
Other	172	139
Total	2,779	$ 2,693
Unused Amounts Reversed [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	0
Deferred income	0
Other	(2,535)
Total	(2,535)
Amounts Used during The Year [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Asset retirement obligation	(337)
Deferred income	(1,375)
Other	(3,417)
Total	$ (5,129)

Provisions and other long-te129

Provisions and other long-term liabilities (Details Textual) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Provisions and other long-term liabilities [Line Items]
Payments in respect of controversaries settlements	$ 3,389,000
Provision for fiscal controversies [Member]
Disclosure Of Provisions and other long-term liabilities [Line Items]
Other provisions		$ 5,636,000

Trade and other payables (Detai

Trade and other payables (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Trade and other payables [Line Items]
V.A.T		$ 1,118	$ 1,102
Trade payables		52,557	23,650
Payables to related parties	[1]	31,184	27,801
Customer advance payments		10,000	20,000
Staff costs to be paid		9,143	7,749
Royalties to be paid		4,110	1,503
Taxes and other debts to be paid		4,191	3,355
To be paid to co-venturers		10,015	1,614
Trade and other payables		122,318	86,774
Current		96,397	52,008
Non current		$ 25,921	$ 34,766
[1]	The outstanding amount corresponds to advanced cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks. The expected maturity of these balances is July 2020 and the applicable interest rate is 8% per annum.

Trade and other payables (De131

Trade and other payables (Details Textual)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Trade and other payables [Line Items]
Borrowings, maturity	21 September 2024
Borrowings, interest rate	6.50%	7.50%
Average credit period Expressed As Creditor Days	95	83
LG International Corp [Member]
Disclosure Of Trade and other payables [Line Items]
Borrowings, maturity	July 2,020
Borrowings, interest rate	8.00%

Share-based payment (Details)

Share-based payment (Details)	12 Months Ended
	Dec. 31, 2017USD ($)Number	Dec. 31, 2016USD ($)Number	Dec. 31, 2015USD ($)
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	2,191,411
Number of share options granted in share-based payment arrangement	83,031
Number of share options forfeited in share-based payment arrangement	31,109
Number of share options exercised in share-based payment arrangement	655,337
Number of share options outstanding in share-based payment arrangement	1,587,996	2,191,411
Expense from share-based payment transactions with employees | $	$ 4,075,000	$ 3,367,000	$ 8,223,000
Stock options to Executive Directors [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ 0	2,390
VCP 2013 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ 0	617
VCP 2016 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 1,868	$ 934	0
Executive Directors’ Bonus [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ (325)	400
Key Management Bonus [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	82,306
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	82,306
Number of share options outstanding in share-based payment arrangement	0	82,306
Expense from share-based payment transactions with employees | $	$ 0	$ 202	1,438
Stock awards for service contracts [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	12,546
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	12,546
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 50	$ 35	0
Shares granted to Non-Executive Director [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	70,485
Number of share options exercised in share-based payment arrangement	70,485
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 454	$ 400	371
Year of issuance 2016 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	1,619,105
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	31,109
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	1,587,996	1,619,105
Expense from share-based payment transactions with employees | $	$ 865	$ 445	0
Year of issuance 2014 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	490,000
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	490,000
Number of share options outstanding in share-based payment arrangement	0	490,000
Expense from share-based payment transactions with employees | $	$ 838	$ 821	898
Year of issuance 2013 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ 0	594
Year of issuance 2012 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ 855	636
Year of issuance 2011 [Member]
Disclosure Of Share-based Payment [Line Items]
Number of share options outstanding in share-based payment arrangement	0
Number of share options granted in share-based payment arrangement	0
Number of share options forfeited in share-based payment arrangement	0
Number of share options exercised in share-based payment arrangement	0
Number of share options outstanding in share-based payment arrangement	0	0
Expense from share-based payment transactions with employees | $	$ 0	$ 0	879
Subtotal [Member]
Disclosure Of Share-based Payment [Line Items]
Expense from share-based payment transactions with employees | $	$ 1,703	$ 2,121	$ 3,007

Share-based payment (Details Te

Share-based payment (Details Textual) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Share-based Payment [Line Items]
Performance-based Employee long-term incentive plan	12.00%	12.00%
Number of instruments granted in share-based payment arrangement		1,619,105
Maximum awards payable in variable number of shares in share-based payment arrangement		2,976,781
Stock market price		$ 4.05
Vesting date for share-based payment arrangement	Dec. 31, 2018
Description of vesting requirements for share-based payment arrangement, share price threshold		$ 3

Interests in Joint operation134

Interests in Joint operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Interests in Joint operations [Line Items]
PP and E, E and E Assets	$ 517,403	$ 473,646	$ 522,611
Total Assets	786,163	640,540
Total Liabilities	659,323	498,947
Revenue	$ 330,122	$ 192,670	$ 209,690
Tranquilos Block Chile [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	50.00%	50.00%	50.00%
PP and E, E and E Assets	$ 0	$ 0	$ 0
Other Assets	55	55	45
Total Assets	55	55	45
Total Liabilities	(432)	(424)	(2)
Net Assets/ (LIABILITIES)	(377)	(369)	43
Revenue	0	0	0
Operating (loss) profit	$ (48)	$ (40)	$ (69)
Flamenco Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	50.00%	50.00%	50.00%
PP and E, E and E Assets	$ 9,893	$ 15,108	$ 14,932
Other Assets	0	0	0
Total Assets	9,893	15,108	14,932
Total Liabilities	(1,223)	(93)	(53)
Net Assets/ (LIABILITIES)	8,670	15,015	14,879
Revenue	879	1,004	1,810
Operating (loss) profit	$ (1,422)	$ (1,988)	$ (51,411)
Campanario Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	50.00%	50.00%	50.00%
PP and E, E and E Assets	$ 17,347	$ 29,718	$ 27,570
Other Assets	0	0	0
Total Assets	17,347	29,718	27,570
Total Liabilities	(233)	(1)	(10)
Net Assets/ (LIABILITIES)	17,114	29,717	27,560
Revenue	0	0	13
Operating (loss) profit	$ (150)	$ (399)	$ (7,267)
Isla Norte Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	60.00%	60.00%	60.00%
PP and E, E and E Assets	$ 9,553	$ 9,920	$ 8,583
Other Assets	0	0	0
Total Assets	9,553	9,920	8,583
Total Liabilities	(60)	(1)	(16)
Net Assets/ (LIABILITIES)	9,493	9,919	8,567
Revenue	0	5	355
Operating (loss) profit	$ (161)	$ (438)	$ (5,661)
YamuCarupana Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	89.50%	89.50%	89.50%
PP and E, E and E Assets	$ 4,741	$ 3,418	$ 3,569
Other Assets	1	0	2,061
Total Assets	4,742	3,418	5,630
Total Liabilities	(2,993)	(2,289)	(2,235)
Net Assets/ (LIABILITIES)	1,749	1,129	3,395
Revenue	3,072	18	1,409
Operating (loss) profit	$ (2,721)	$ (307)	$ (16,552)
Llanos 34 Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	45.00%	45.00%	45.00%
PP and E, E and E Assets	$ 131,193	$ 79,811	$ 76,667
Other Assets	4,563	693	429
Total Assets	135,756	80,504	77,096
Total Liabilities	(5,847)	(3,943)	(3,295)
Net Assets/ (LIABILITIES)	129,909	76,561	73,801
Revenue	259,815	125,400	114,276
Operating (loss) profit	$ 163,917	$ 83,193	$ 53,049
Llanos 32 Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	12.50%	10.00%	10.00%
PP and E, E and E Assets	$ 835	$ 3,819	$ 3,106
Other Assets	209	0	96
Total Assets	1,044	3,819	3,202
Total Liabilities	(492)	(211)	(213)
Net Assets/ (LIABILITIES)	552	3,608	2,989
Revenue	1,784	2,303	8,258
Operating (loss) profit	$ (319)	$ 1,043	$ (1,343)
POT-T-747 [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	70.00%
PP and E, E and E Assets	$ 849
Other Assets	358
Total Assets	1,207
Total Liabilities	(1,091)
Net Assets/ (LIABILITIES)	116
Revenue	0
Operating (loss) profit	$ 0
Manati field [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	10.00%	10.00%	10.00%
PP and E, E and E Assets	$ 44,167	$ 54,166	$ 50,801
Other Assets	19,126	15,791	12,930
Total Assets	63,293	69,957	63,731
Total Liabilities	(11,444)	(8,442)	(10,395)
Net Assets/ (LIABILITIES)	51,849	61,515	53,336
Revenue	34,238	29,719	32,388
Operating (loss) profit	$ 12,731	$ 20,945	$ 20,354
CN-V Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	50.00%
PP and E, E and E Assets	$ 6,819
Other Assets	347
Total Assets	7,166
Total Liabilities	(984)
Net Assets/ (LIABILITIES)	6,182
Revenue	70
Operating (loss) profit	$ (1,163)
Puelen Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	18.00%
PP and E, E and E Assets	$ 1,318
Other Assets	72
Total Assets	1,390
Total Liabilities	(232)
Net Assets/ (LIABILITIES)	1,158
Revenue	0
Operating (loss) profit	$ (546)
Sierra del Nevado Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest	18.00%
PP and E, E and E Assets	$ 568
Other Assets	169
Total Assets	737
Total Liabilities	(837)
Net Assets/ (LIABILITIES)	(100)
Revenue	0
Operating (loss) profit	$ (474)
Llanos 17 Block [Member]
Disclosure Of Interests in Joint operations [Line Items]
Interest			36.84%
PP and E, E and E Assets			$ 0
Other Assets			0
Total Assets			0
Total Liabilities			(93)
Net Assets/ (LIABILITIES)			(93)
Revenue			3
Operating (loss) profit			$ (6,325)

Commitments (Details)

Commitments (Details)	12 Months Ended
	Dec. 31, 2017
Up to 5,000 [Member]
Disclosure Of Commitments [Line Items]
Average Daily Production In Barrel	Up to 5,000
Description Of Applicable Production Royalty Rate	8%
5,000 to 125,000[Member]
Disclosure Of Commitments [Line Items]
Average Daily Production In Barrel	5,000 to 125,000
Description Of Applicable Production Royalty Rate	8% + (production - 5,000)*0.1
125,000 to 400,000[Member]
Disclosure Of Commitments [Line Items]
Average Daily Production In Barrel	125,000 to 400,000
Description Of Applicable Production Royalty Rate	20%
400,000 to 600,000[Member]
Disclosure Of Commitments [Line Items]
Average Daily Production In Barrel	400,000 to 600,000
Description Of Applicable Production Royalty Rate	20% + (production - 400,000)*0.025
Greater than 600,000 [Member]
Disclosure Of Commitments [Line Items]
Average Daily Production In Barrel	Greater than 600,000
Description Of Applicable Production Royalty Rate	25%

Commitments (Details 1)

Commitments (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 15, 2016
Disclosure Of Commitments [Line Items]
Minimum lease payments payable under non-cancellable operating lease	$ 40,750	$ 86,963	$ 23,900
Falling due within 1 year [member]
Disclosure Of Commitments [Line Items]
Minimum lease payments payable under non-cancellable operating lease	32,180	67,752	12,878
Falling due within 1 - 3 years [member]
Disclosure Of Commitments [Line Items]
Minimum lease payments payable under non-cancellable operating lease	5,777	14,031	8,257
Falling due within 3 - 5 years [member]
Disclosure Of Commitments [Line Items]
Minimum lease payments payable under non-cancellable operating lease	2,793	5,066	2,456
Falling due over 5 years [member]
Disclosure Of Commitments [Line Items]
Minimum lease payments payable under non-cancellable operating lease	$ 0	$ 114	$ 309

Commitments (Details Textual)

Commitments (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Commitments [Line Items]
Royalty Expense	$ 28,697,000	$ 11,497,000	$ 13,155,000
Investment Assumption Percentage	100.00%
Minimum operating lease payments recognised as expense	$ 46,195,000	47,871,000	16,731,000
Recognised finance lease as assets	34,160,000	32,058,000	7,102,000
CN-V Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	$ 10,000,000
Working Interest Percentage In Property	50.00%
Capital Commitments, Fulfilled	$ 5,455,000
Flamenco Block [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	5.00%
Capital commitments	$ 2,100,000
Investment Assumption Percentage	100.00%
Campanario Block [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	5.00%
Capital commitments	$ 4,758,000
Isla Norte Block [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	5.00%
Capital commitments	$ 2,855,000
SEALT268 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	230,000
RECT94 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	2,300,000
RECT93 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	50,000
RECT128 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	2,690,000
POTT747 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	1,840,000
POTT882 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	480,000
POTT619 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	700,000
VIM 3 Block [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	22,290,800
Llanos 34 Blocks [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	$ 6,255,000
Working Interest Percentage In Property	45.00%
Capital commitment, remaining commitment after deducting amounts awaits for approval	$ 3,008,000
Llanos 32 [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	$ 587,500
Working Interest Percentage In Property	12.00%
Winchester Stock Purchase Agreement [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	4.00%
Royalty Expense	$ 11,369,000	5,414,000	7,100,000
Payments For Royalty	$ 9,981,000	$ 3,772,000	$ 9,200,000
Brazilian National Petroleum, Natural Gas and Biofuels Agency [Member] | Gas [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	7.50%
Provinces of Mendoza [Member] | Crude Oil [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	12.00%
Pluspetrol [Member]
Disclosure Of Commitments [Line Items]
Working Interest Percentage In Property	72.00%
EMESA [Member]
Disclosure Of Commitments [Line Items]
Working Interest Percentage In Property	10.00%
GeoPark [Member]
Disclosure Of Commitments [Line Items]
Capital commitments	$ 1,200,000
Working Interest Percentage In Property	18.00%
Colombian National Hydrocarbons Agency [Member]
Disclosure Of Commitments [Line Items]
Additional Economic Right Percentage	1.00%
Chilean Government [Member] | Crude Oil [Member] | Fell Block [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	5.00%
Chilean Government [Member] | Gas And Oil [Member] | Fell Block [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	3.00%
Bottom of range [member] | Colombian Government [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	6.00%
Bottom of range [member] | Winchester Stock Purchase Agreement [Member]
Disclosure Of Commitments [Line Items]
Estimated Total Royalty Commitments	$ 80,000,000
Bottom of range [member] | Brazilian National Petroleum, Natural Gas and Biofuels Agency [Member] | Oil And Natural Gases [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	5.00%
Top of range [member] | Colombian Government [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	8.00%
Top of range [member] | Winchester Stock Purchase Agreement [Member]
Disclosure Of Commitments [Line Items]
Estimated Total Royalty Commitments	$ 90,000,000
Top of range [member] | Brazilian National Petroleum, Natural Gas and Biofuels Agency [Member] | Oil And Natural Gases [Member]
Disclosure Of Commitments [Line Items]
Royalties Percentage	10.00%

Related parties (Details)

Related parties (Details) - shares		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of classes of share capital [line items]
Number of shares issued		60,596,219	59,940,881
Percentage of voting equity interests acquired		100.00%		100.00%
James F. Park [Member]
Disclosure of classes of share capital [line items]
Number of shares issued	[1]	7,891,269
Percentage of voting equity interests acquired	[1]	13.02%
Gerald O’Shaughnessy [Member]
Disclosure of classes of share capital [line items]
Number of shares issued	[2]	7,193,316
Percentage of voting equity interests acquired	[2]	11.87%
Juan Cristobal Pavez [Member]
Disclosure of classes of share capital [line items]
Number of shares issued	[3]	2,961,520
Percentage of voting equity interests acquired	[3]	4.89%
Manchester Financial Group, LP [Member]
Disclosure of classes of share capital [line items]
Number of shares issued		5,103,439
Percentage of voting equity interests acquired		8.42%
IFC Equity Investments [Member]
Disclosure of classes of share capital [line items]
Number of shares issued	[4]	3,422,476
Percentage of voting equity interests acquired	[4]	5.65%
Other shareholders [Member]
Disclosure of classes of share capital [line items]
Number of shares issued		34,024,199
Percentage of voting equity interests acquired		56.15%
[1]	Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of our Board of Directors.
[2]	Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, and other investment vehicles.
[3]	Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 83,716 common shares held by him personally.
[4]	IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff.

Related parties (Details 1)

Related parties (Details 1) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Related parties [Line Items]
Finance costs		$ 53,511	$ 36,229	$ 36,924
Administrative expenses		42,054	34,170	37,471
Geological and geophysical expenses		7,694	10,282	13,831
Entities with joint control or significant influence over entity [member]
Disclosure Of Related parties [Line Items]
Amounts payable, related party transactions		(10,015)	(1,614)	(113)
Amounts receivable, related party transactions		$ 2,455	$ 3,311	$ 4,634
Description of nature of related party relationship		Joint Operations	Joint Operations	Joint Operations
Carlos Gulisano [Member]
Disclosure Of Related parties [Line Items]
Administrative expenses				$ 66
Geological and geophysical expenses		$ 170	$ 113	$ 101
Description of nature of related party relationship	[1]	Non-Executive Director	Non-Executive Director	Non-Executive Director
Pedro Aylwin [Member]
Disclosure Of Related parties [Line Items]
Administrative expenses		$ 411	$ 371	$ 377
Description of nature of related party relationship	[2]	Executive Director	Executive Director	Executive Director
LG International Corp [Member]
Disclosure Of Related parties [Line Items]
Finance costs		$ 2,224	$ 1,587	$ 1,560
Amounts payable, related party transactions		(31,184)	(27,801)	(21,045)
Amounts receivable, related party transactions		$ 56	$ 42	$ 38
Description of nature of related party relationship		Partner	Partner	Partner
[1]	Corresponding to consultancy services.
[2]	Corresponding to wages and salaries for US$ 271,000 (US$ 246,000 in 2016 and US$ 317,000 in 2015) and bonus for US$ 140,000 (US$ 125,000 in 2016 and US$ 60,000 in 2015).

Related parties (Details Textua

Related parties (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of classes of share capital held by him personally [Line Items]
Number of shares outstanding	60,600,000	59,900,000	59,500,000
Wages and salaries	$ 44,891,000	$ 36,059,000	$ 40,574,000
Pedro Aylwin [Member]
Disclosure of classes of share capital held by him personally [Line Items]
Wages and salaries	271,000	246,000	317,000
Other long-term employee benefits	$ 140,000	$ 125,000	$ 60,000
Juan Cristobal Pavez [Member]
Disclosure of classes of share capital held by him personally [Line Items]
Number of shares outstanding	83,716

Fees paid to Auditors (Details)

Fees paid to Auditors (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Fees paid to Auditors [Line Items]
Audit fees	$ 726	$ 487	$ 557
Audit related fees	137	0	0
Tax services fees	212	134	129
Non-audit services fees	39	0	0
Fees paid to auditors	$ 1,114	$ 621	$ 686

Business transactions (Details

Business transactions (Details Textual)	1 Months Ended		12 Months Ended
	Aug. 22, 2017	Nov. 19, 2015	Dec. 31, 2017USD ($)a	Dec. 31, 2015USD ($)	Jun. 30, 2018USD ($)	Dec. 18, 2017USD ($)
Disclosure of detailed information about business transactions [Line Items]
Percentage of voting equity interests acquired			100.00%	100.00%
Land area | a			1.9
Loss on business transactions				$ 296,000
Consideration owed			$ 10,684,000
Security Deposits			$ 15,600,000
Subsequent Events [Member] | Bottom of range [member]
Disclosure of detailed information about business transactions [Line Items]
Investments in subsidiaries					$ 7,000,000
Subsequent Events [Member] | Top of range [member]
Disclosure of detailed information about business transactions [Line Items]
Investments in subsidiaries					$ 8,000,000
Tiple Block [Member]
Disclosure of detailed information about business transactions [Line Items]
Land area | a			21,000
Percentage of working interest			45.00%
Llanos 32 Block [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest acquired	2.50%
Zamuro field [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest			12.50%
Percentage of working interest acquired			56.25%
Aguada Baguales, El Porvenir and Puesto Touquet blocks [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest acquired			100.00%
Consideration transferred, acquisition-date fair value						$ 52,000,000
Morona Block [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest			75.00%
Cerrito Block [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest exchanged		10.00%
Yamu Block [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest exchanged		10.00%
Carupana Field [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest				89.50%
Petroperu [Member]
Disclosure of detailed information about business transactions [Line Items]
Percentage of working interest			25.00%

Impairment test on Property,143

Impairment test on Property, plant and equipment (Details)	Dec. 31, 2017$ / bbl
2,018
Disclosure Of Impairment test on Property, plant and equipment [Line Items]
Low price (15%)	64.9
Middle price (60%)	64.9
High price (25%)	64.9
Weighted market price used for the impairment test	64.9
2,019
Disclosure Of Impairment test on Property, plant and equipment [Line Items]
Low price (15%)	53.2
Middle price (60%)	62.5
High price (25%)	71.7
Weighted market price used for the impairment test	63.4
2,020
Disclosure Of Impairment test on Property, plant and equipment [Line Items]
Low price (15%)	54.4
Middle price (60%)	63.9
High price (25%)	73.4
Weighted market price used for the impairment test	64.9
Over 2,021
Disclosure Of Impairment test on Property, plant and equipment [Line Items]
Low price (15%)	54.3
Middle price (60%)	63.7
High price (25%)	73.2
Weighted market price used for the impairment test	64.7

Impairment test on Property,144

Impairment test on Property, plant and equipment (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Impairment test on Property, plant and equipments [Line Items]
Impairment loss	$ 0		$ 149,574,000
Reversal of impairment loss		$ 5,664,000

Supplemental information on 145

Supplemental information on oil and gas activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	$ 0	$ 0	$ 0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	54,330	25,201	22,108
Development	74,950	17,257	31,903
Total costs incurred	129,280	42,458	54,011
Chile [Member]
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	0	0	0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	3,283	5,519	3,598
Development	10,231	4,566	13,315
Total costs incurred	13,514	10,085	16,913
Colombia [Member]
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	0	0	0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	37,017	15,233	14,845
Development	49,268	12,500	14,752
Total costs incurred	86,285	27,733	29,597
Argentina [Member]
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	0	0	0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	8,080	1,894	1,103
Development	167	0	56
Total costs incurred	8,247	1,894	1,159
Brazil [Member]
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	0	0	0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	5,207	2,555	2,562
Development	1,210	191	3,780
Total costs incurred	6,417	2,746	6,342
Peru [Member]
Costs incurred, acquisition of properties [Line Items]
Acquisition of properties, Proved	0	0	0
Acquisition of properties, Unproved	0	0	0
Total property acquisition	0	0	0
Exploration	743	0	0
Development	14,074	0	0
Total costs incurred	$ 14,817	$ 0	$ 0

Supplemental information on 146

Supplemental information on oil and gas activities (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved properties, Equipment, camps and other facilities	$ 157,396	[1]	$ 132,413	[2]	$ 124,832	[3]
Proved properties, Mineral interest and wells	776,504	[1]	692,241	[2]	648,992	[3]
Proved properties, Other uncompleted projects	23,916	[1],[4]	32,926	[2]	29,823	[3]
Unproved properties	64,368		61,773		87,000
Gross capitalised costs	1,022,184		919,353		890,647
Accumulated depreciation	(527,766)		(456,437)		(381,787)
Total net capitalised costs	494,418		462,916		508,860
Chile [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved properties, Equipment, camps and other facilities	80,611	[1]	80,611	[2]	79,040	[3]
Proved properties, Mineral interest and wells	397,031	[1]	380,037	[2]	367,722	[3]
Proved properties, Other uncompleted projects	12,508	[1],[4]	18,274	[2]	21,830	[3]
Unproved properties	49,702		48,908		70,062
Gross capitalised costs	539,852		527,830		538,654
Accumulated depreciation	(253,764)		(230,917)		(201,138)
Total net capitalised costs	286,088		296,913		337,516
Colombia [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved properties, Equipment, camps and other facilities	69,906	[1]	46,785	[2]	42,852	[3]
Proved properties, Mineral interest and wells	291,050	[1]	230,100	[2]	213,480	[3]
Proved properties, Other uncompleted projects	11,290	[1],[4]	12,534	[2]	7,703	[3]
Unproved properties	4,106		4,503		8,180
Gross capitalised costs	376,352		293,922		272,215
Accumulated depreciation	(228,793)		(190,025)		(160,759)
Total net capitalised costs	147,559		103,897		111,456
Argentina [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved properties, Equipment, camps and other facilities	843	[1]	843	[2]	843	[3]
Proved properties, Mineral interest and wells	11,159	[1]	4,849	[2]	4,849	[3]
Proved properties, Other uncompleted projects	48	[1],[4]	36	[2]	290	[3]
Unproved properties	2,975		1,894		0
Gross capitalised costs	15,025		7,622		5,982
Accumulated depreciation	(5,700)		(5,692)		(5,654)
Total net capitalised costs	9,325		1,930		328
Brazil [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved properties, Equipment, camps and other facilities	6,036	[1]	4,174	[2]	2,097	[3]
Proved properties, Mineral interest and wells	77,264	[1]	77,255	[2]	62,941	[3]
Proved properties, Other uncompleted projects	70	[1],[4]	2,082	[2]	0	[3]
Unproved properties	7,585		6,468		8,758
Gross capitalised costs	90,955		89,979		73,796
Accumulated depreciation	(39,509)		(29,803)		(14,236)
Total net capitalised costs	$ 51,446		$ 60,176		$ 59,560
[1]	Includes capitalised amounts related to asset retirement obligations.
[2]	Includes capitalised amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$ 5,664,000.
[3]	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.
[4]	Do not include Peru capitalised costs.

Supplemental information on 147

Supplemental information on oil and gas activities (Details 2) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Revenue		$ 330,122	$ 192,670	$ 209,690
Production costs, excluding depreciation
Operating costs		(70,290)	(55,738)	(73,587)
Royalties		(28,697)	(11,497)	(13,155)
Total production costs		(98,987)	(67,235)	(86,742)
Exploration expenses	[1]	(9,952)	(38,386)	(39,893)
Accretion expense	[2]	(2,607)	(2,554)	(2,575)
Impairment (loss)/loss reversal for non-financial assets		0	5,664	(149,574)
Depreciation, depletion and amortization		(72,093)	(72,114)	(101,831)
Results of operations before income tax		146,483	18,045	(170,925)
Income tax benefit (expense)		(61,507)	(16,443)	29,255
Results of oil and gas operations		84,976	1,602	(141,670)
Chile [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Revenue		32,738	36,723	44,808
Production costs, excluding depreciation
Operating costs		(19,685)	(20,674)	(26,731)
Royalties		(1,314)	(1,495)	(1,973)
Total production costs		(20,999)	(22,169)	(28,704)
Exploration expenses	[1]	(1,404)	(21,060)	(30,499)
Accretion expense	[2]	(994)	(897)	(789)
Impairment (loss)/loss reversal for non-financial assets		0	0	(104,515)
Depreciation, depletion and amortization		(22,705)	(29,890)	(37,664)
Results of operations before income tax		(13,364)	(37,293)	(157,363)
Income tax benefit (expense)		2,005	5,594	23,604
Results of oil and gas operations		(11,359)	(31,699)	(133,759)
Colombia [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Revenue		263,076	126,228	131,897
Production costs, excluding depreciation
Operating costs		(42,677)	(29,326)	(40,384)
Royalties		(24,236)	(7,281)	(8,150)
Total production costs		(66,913)	(36,607)	(48,534)
Exploration expenses	[1]	(3,856)	(11,690)	(7,132)
Accretion expense	[2]	(683)	(459)	(890)
Impairment (loss)/loss reversal for non-financial assets		0	5,664	(45,059)
Depreciation, depletion and amortization		(38,721)	(29,439)	(50,675)
Results of operations before income tax		152,903	53,697	(20,393)
Income tax benefit (expense)		(61,161)	(21,479)	7,953
Results of oil and gas operations		91,742	32,218	(12,440)
Argentina [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Revenue		70	0	597
Production costs, excluding depreciation
Operating costs		(325)	0	(1,414)
Royalties		(13)	0	(34)
Total production costs		(338)	0	(1,448)
Exploration expenses	[1]	(707)	0	(1,159)
Accretion expense	[2]	0	0	0
Impairment (loss)/loss reversal for non-financial assets		0	0	0
Depreciation, depletion and amortization		(8)	0	(91)
Results of operations before income tax		(983)	0	(2,101)
Income tax benefit (expense)		344	0	735
Results of oil and gas operations		(639)	0	(1,366)
Brazil [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Revenue		34,238	29,719	32,388
Production costs, excluding depreciation
Operating costs		(7,603)	(5,738)	(5,058)
Royalties		(3,134)	(2,721)	(2,998)
Total production costs		(10,737)	(8,459)	(8,056)
Exploration expenses	[1]	(3,985)	(5,636)	(1,103)
Accretion expense	[2]	(930)	(1,198)	(896)
Impairment (loss)/loss reversal for non-financial assets		0	0	0
Depreciation, depletion and amortization		(10,659)	(12,785)	(13,401)
Results of operations before income tax		7,927	1,641	8,932
Income tax benefit (expense)		(2,695)	(558)	(3,037)
Results of oil and gas operations		$ 5,232	$ 1,083	$ 5,895
[1]	Do not include Peru costs.
[2]	Represents accretion of ARO liability.

Supplemental information on 148

Supplemental information on oil and gas activities (Details 3)		Dec. 31, 2017MBblsMMcf	Dec. 31, 2016MBblsMMcf		Dec. 31, 2015MBblsMMcf	Dec. 31, 2014MBblsMMcf
Oil and condensate [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net		31,399	19,437		8,795.8
Undeveloped reserves for properties, net		57,036	43,195		27,701.3
Proved developed and undeveloped reserves for properties, net		88,435	62,632		36,497.1	36,497.1
Naturals gas [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net | MMcf		32,509	36,135	[1]	41,080
Undeveloped reserves for properties, net | MMcf		11,329	29,690		31,593
Proved developed and undeveloped reserves for properties, net | MMcf		43,838	65,825		72,673	74,434
Chile [Member] | Oil and condensate [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net	[2]	720	547		498
Undeveloped reserves for properties, net	[3]	3,423	6,052		5,455.8
Proved developed and undeveloped reserves for properties, net		4,143	6,599		5,953.8	6,441.9
Chile [Member] | Naturals gas [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net | MMcf	[2]	8,688	6,610		4,922
Undeveloped reserves for properties, net | MMcf	[3]	11,329	29,690		31,593
Proved developed and undeveloped reserves for properties, net | MMcf		20,017	36,300		36,515	33,970
Colombia [Member] | Oil and condensate [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net	[4]	21,101	9,502		8,177.8
Undeveloped reserves for properties, net	[5]	44,398	27,838		22,245.5
Proved developed and undeveloped reserves for properties, net		65,499	37,340		30,423.3	24,735.3
Brazil [Member] | Oil and condensate [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net	[1]	76	72		120
Proved developed and undeveloped reserves for properties, net		76	72		120	130
Brazil [Member] | Naturals gas [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net | MMcf	[1]	23,821	29,525		36,158
Proved developed and undeveloped reserves for properties, net | MMcf		23,821	29,525		36,158	40,464
Peru [Member] | Oil and condensate [Member]
Disclosure Of Supplemental informations on oil and gas activities [Line Items]
Proved Reserves For Properties Net	[6]	9,502	9,316
Undeveloped reserves for properties, net	[6]	9,215	9,305
Proved developed and undeveloped reserves for properties, net		18,717	18,621		0	0
[1]	BCAM-40 Block accounts for 100% of the reserves.
[2]	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).
[3]	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).
[4]	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).
[5]	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).
[6]	Morona Block accounts for 100% of the reserves.

Supplemental information on 149

Supplemental information on oil and gas activities (Details 4)		12 Months Ended
		Dec. 31, 2017bbl	Dec. 31, 2017MBbls		Dec. 31, 2017MMcf		Dec. 31, 2016bbl	Dec. 31, 2016MBbls		Dec. 31, 2016MMcf		Dec. 31, 2015bbl	Dec. 31, 2015MBbls		Dec. 31, 2015MMcf
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions | bbl												0.1
Oil and condensate [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning			62,632					36,497.1					36,497.1
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions		4.3	4,321	[1]			7	6,893	[2]				(98.4)	[3]
Extensions and discoveries			29,047	[4]				6,311	[5]				10,589	[6]
Purchases of minerals in place	[7]							18,621
Productions			7,565					5,690.1					5,300.7
Proved reserves of oil, condensate and natural gas, net at the end			88,435					62,632					36,497.1
Oil and condensate [Member] | Chile [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning			6,599					5,953.8					6,441.9
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions			(2,109)	[1]				1,148	[2]			1	119	[3]
Extensions and discoveries			0	[4]				0	[5]				100	[6]
Purchases of minerals in place	[7]							0
Productions			347					502.8					707.1
Proved reserves of oil, condensate and natural gas, net at the end			4,143					6,599					5,953.8
Oil and condensate [Member] | Colombia [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning			37,340					30,423.3					24,735.3
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions		0.4	6,315	[1]				5,779	[2]			2	(225)	[3]
Extensions and discoveries			29,047	[4]				6,311	[5]				10,489	[6]
Purchases of minerals in place	[7]							0
Productions			7,203					5,173.3					4,576
Proved reserves of oil, condensate and natural gas, net at the end			65,499					37,340					30,423.3
Oil and condensate [Member] | Brazil [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning			72					120					130
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions			19	[1]				(34)	[2]				7.6	[3]
Extensions and discoveries			0	[4]				0	[5]				0	[6]
Purchases of minerals in place	[7]							0
Productions			15					14					17.6
Proved reserves of oil, condensate and natural gas, net at the end			76					72					120
Oil and condensate [Member] | Peru [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning			18,621					0					0
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions			96	[1]				0	[2]				0	[3]
Extensions and discoveries			0	[4]				0	[5]				0	[6]
Purchases of minerals in place	[7]							18,621
Productions			0					0					0
Proved reserves of oil, condensate and natural gas, net at the end			18,717					18,621					0
Naturals gas [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning | MMcf					65,825					72,673					74,434
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions | MMcf					(13,666)	[8]				4,759	[9]				99.4
Extensions and discoveries | MMcf					1,187	[10]									9,378	[11]
Productions | MMcf					9,508					11,607					11,238.4
Proved reserves of oil, condensate and natural gas, net at the end | MMcf					43,838					65,825					72,673
Naturals gas [Member] | Chile [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning | MMcf					36,300					36,515					33,970
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions | MMcf					(13,725)	[8]				5,078	[2]				(2,807.6)	[12]
Extensions and discoveries | MMcf					1,187	[4]									9,378	[6]
Productions | MMcf					3,745					5,293					4,025.4
Proved reserves of oil, condensate and natural gas, net at the end | MMcf					20,017					36,300					36,515
Naturals gas [Member] | Brazil [Member]
Supplemental information on oil and gas activities [Line Items]
Proved reserves of oil, condensate and natural gas, net at the beginning | MMcf					29,525					36,158					40,464
Proved reserves of oil, condensate and natural gas, increase decrease attributable to [abstract]
Revisions | MMcf					59	[1]				(319)	[9]				2,907	[3]
Extensions and discoveries | MMcf					0	[10]									0	[11]
Productions | MMcf					5,763					6,314					7,213
Proved reserves of oil, condensate and natural gas, net at the end | MMcf					23,821					29,525					36,158
[1]	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.
[2]	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.
[3]	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.
[4]	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.
[5]	In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells in the Llanos 34 Block.
[6]	In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca field discoveries in the Llanos 34 Block.
[7]	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.
[8]	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.
[9]	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.
[10]	In Chile, the extensions and discoveries are primary due to the Uaken Field discovery in the Fell Block.
[11]	In Chile, the extensions and discoveries are primary due to the Ache Field discovery and from the extension well in the Fell Block.
[12]	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).

Supplemental information on 150

Supplemental information on oil and gas activities (Details 5) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental information on oil and gas activitie [Line Items]
Future cash inflows	$ 3,924,732	$ 2,410,940	$ 1,656,744
Future production costs	(1,185,960)	(987,596)	(596,159)
Future development costs	(488,548)	(470,461)	(227,977)
Future income taxes	(676,618)	(290,179)	(230,698)
Undiscounted future net cash flows	1,573,606	662,704	601,910
10% annual discount	(523,874)	(253,302)	(161,342)
Standardized measure of discounted future net cash flows	1,049,732	409,402	440,568	$ 923,874
Chile [Member]
Supplemental information on oil and gas activitie [Line Items]
Future cash inflows	284,711	394,993	403,199
Future production costs	(131,788)	(186,700)	(186,933)
Future development costs	(57,690)	(149,785)	(112,312)
Future income taxes	(656)	(8,344)	(17,904)
Undiscounted future net cash flows	94,577	50,164	86,050
10% annual discount	(19,338)	(14,709)	(17,895)
Standardized measure of discounted future net cash flows	75,239	35,455	68,155	227,658
Colombia [Member]
Supplemental information on oil and gas activitie [Line Items]
Future cash inflows	2,434,954	873,771	1,032,339
Future production costs	(531,751)	(229,593)	(309,394)
Future development costs	(187,414)	(69,996)	(99,305)
Future income taxes	(558,226)	(191,096)	(195,957)
Undiscounted future net cash flows	1,157,563	383,086	427,683
10% annual discount	(343,561)	(113,584)	(127,586)
Standardized measure of discounted future net cash flows	814,002	269,502	300,097	584,071
Brazil [Member]
Supplemental information on oil and gas activitie [Line Items]
Future cash inflows	157,527	200,713	221,206
Future production costs	(56,311)	(74,116)	(99,832)
Future development costs	(7,524)	(16,352)	(16,360)
Future income taxes	(10,442)	(21,041)	(16,837)
Undiscounted future net cash flows	83,250	89,204	88,177
10% annual discount	(13,293)	(15,688)	(15,861)
Standardized measure of discounted future net cash flows	69,957	73,516	72,316	112,145
Peru [Member]
Supplemental information on oil and gas activitie [Line Items]
Future cash inflows	1,047,540	941,463	0
Future production costs	(466,110)	(497,187)	0
Future development costs	(235,920)	(234,328)	0
Future income taxes	(107,294)	(69,698)	0
Undiscounted future net cash flows	238,216	140,250	0
10% annual discount	(147,682)	(109,321)	0
Standardized measure of discounted future net cash flows	$ 90,534	$ 30,929	$ 0	$ 0

Supplemental information on 151

Supplemental information on oil and gas activities (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Balance Beginning	$ 409,402	$ 440,568	$ 923,874
Sales of hydrocarbon, net of production costs	(239,861)	(127,235)	(155,528)
Net increase decrease in sales prices and production costs	383,089	(171,619)	(831,611)
Changes in estimated future development costs related to oil and gas reserves	(46,315)	(34,280)	8,646
Extensions and discoveries, less related costs	49,574	76,641	198,546
Development costs incurred	74,717	28,933	49,930
Revisions of previous quantity estimates	605,764	91,073	(15,146)
Net changes in income taxes	(256,597)	7,266	131,760
Purchase of Minerals in place		30,929
Accretion of discount	69,959	67,126	130,097
Balance Ending	1,049,732	409,402	440,568
Chile [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Balance Beginning	35,455	68,155	227,658
Sales of hydrocarbon, net of production costs	(14,251)	(15,127)	(20,948)
Net increase decrease in sales prices and production costs	26,928	(16,854)	(256,828)
Changes in estimated future development costs related to oil and gas reserves	79,078	(49,763)	28,227
Extensions and discoveries, less related costs	0	0	23,595
Development costs incurred	7,146	9,417	15,093
Revisions of previous quantity estimates	(69,594)	22,765	(5,463)
Net changes in income taxes	6,097	8,256	28,611
Purchase of Minerals in place		0
Accretion of discount	4,380	8,606	28,210
Balance Ending	75,239	35,455	68,155
Brazil [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Balance Beginning	73,516	72,316	112,145
Sales of hydrocarbon, net of production costs	(26,979)	(20,945)	(37,428)
Net increase decrease in sales prices and production costs	(3,000)	16,366	(27,404)
Changes in estimated future development costs related to oil and gas reserves	8,385	542	542
Extensions and discoveries, less related costs	0	0	0
Development costs incurred	0	2,214	4,872
Revisions of previous quantity estimates	603	(1,872)	4,845
Net changes in income taxes	7,976	(4,020)	1,573
Purchase of Minerals in place		0
Accretion of discount	9,456	8,915	13,171
Balance Ending	69,957	73,516	72,316
Colombia [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Balance Beginning	269,502	300,097	584,071
Sales of hydrocarbon, net of production costs	(198,631)	(91,163)	(97,152)
Net increase decrease in sales prices and production costs	289,199	(171,131)	(547,379)
Changes in estimated future development costs related to oil and gas reserves	(124,053)	14,941	(20,123)
Extensions and discoveries, less related costs	49,574	76,641	174,951
Development costs incurred	67,571	17,302	29,965
Revisions of previous quantity estimates	673,622	70,180	(14,528)
Net changes in income taxes	(258,842)	3,030	101,576
Purchase of Minerals in place		0
Accretion of discount	46,060	49,605	88,716
Balance Ending	814,002	269,502	300,097
Peru [Member]
Disclosure Of Supplemental information on oil and gas activitie [Line Items]
Balance Beginning	30,929	0	0
Sales of hydrocarbon, net of production costs	0	0	0
Net increase decrease in sales prices and production costs	69,962	0	0
Changes in estimated future development costs related to oil and gas reserves	(9,725)	0	0
Extensions and discoveries, less related costs	0	0	0
Development costs incurred	0	0	0
Revisions of previous quantity estimates	1,133	0	0
Net changes in income taxes	(11,828)	0	0
Purchase of Minerals in place		30,929
Accretion of discount	10,063	0	0
Balance Ending	$ 90,534	$ 30,929	$ 0

Supplemental information on 152

Supplemental information on oil and gas activities (Details Textual) ft³ in Billions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2017bbl	Dec. 31, 2017MBbls		Dec. 31, 2017ft³	Dec. 31, 2017Mcf	Dec. 31, 2017	Dec. 31, 2016USD ($)	Dec. 31, 2016bbl	Dec. 31, 2016MBbls		Dec. 31, 2016ft³	Dec. 31, 2016Mcf	Dec. 31, 2015USD ($)	Dec. 31, 2015bbl	Dec. 31, 2015MBbls		Dec. 31, 2015ft³	Dec. 31, 2015Mcf
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reversal of impairment loss | $								$ 5,664,000
Impairment loss | $	$ 0													$ 149,574,000
Standardized Measures Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves Attributable to Noncontrolling Interest | $	$ 178,100,000							61,400,000						73,900,000
Proved developed and undeveloped reserves, revisions | bbl															0.1
Crude Oil [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves Units Of Measurement Attributable to Noncontrolling Interest | MBbls			13,934.1							8,796.2						7,281.3
Natural Gas [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves Units Of Measurement Attributable to Noncontrolling Interest | Mcf						4,101.5							7,356						7,345.8
Chile [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Impairment loss | $														104,515,000
Colombia [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reversal of impairment loss | $								$ 5,664,000
Impairment loss | $														$ 45,059,000
Oil and gas assets [member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Exsting Wells Revisions																		13
Proved developed and undeveloped reserves, revisions					13.7							5						0.1
Oil and gas assets [member] | Chile [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries																		10
Oil and gas assets [member] | Brazil [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved developed and undeveloped reserves, revisions																		3
Oil and condensate [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Exsting Wells Revisions | bbl									1
Proved developed and undeveloped reserves, revisions		4.3	4,321	[1]					7	6,893	[2]					(98.4)	[3]
Proved developed and undeveloped reserves, extensions and discoveries | MBbls			29,047	[4]						6,311	[5]					10,589	[6]
Oil and condensate [Member] | Chile [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Exsting Wells Revisions | bbl									8
Proved developed and undeveloped reserves, revisions			(2,109)	[1]						1,148	[2]				1	119	[3]
Proved developed and undeveloped reserves, extensions and discoveries | MBbls			0	[4]						0	[5]					100	[6]
Oil and condensate [Member] | Colombia [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Exsting Wells Revisions | bbl		3.8							9
Proved developed and undeveloped reserves, revisions		0.4	6,315	[1]						5,779	[2]				2	(225)	[3]
Proved developed and undeveloped reserves, extensions and discoveries | MBbls			29,047	[4]						6,311	[5]					10,489	[6]
Oil and condensate [Member] | Colombia [Member] | Crude Oil [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved developed and undeveloped reserves, revisions | bbl		2.5
Oil and condensate [Member] | La Cuerva and Yamu blocks [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved developed and undeveloped reserves, revisions | bbl									2
Oil and condensate [Member] | Brazil [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved developed and undeveloped reserves, revisions | MBbls			19	[1]						(34)	[2]					7.6	[3]
Proved developed and undeveloped reserves, extensions and discoveries | MBbls			0	[4]						0	[5]					0	[6]
LG International Corp [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proportion of ownership interest in joint operation							20.00%
Fell Block [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	98.00%	98.00%	98.00%		98.00%	98.00%	98.00%	99.00%	99.00%	99.00%		99.00%	99.00%	91.00%	91.00%	91.00%		91.00%	91.00%
Reserves Proportional Interest Of Net Proved Undeveloped Reserve	97.00%	97.00%	97.00%		97.00%	97.00%	97.00%	99.00%	99.00%	99.00%		99.00%	99.00%	100.00%	100.00%	100.00%		100.00%	100.00%
Fell Block [Member] | Oil and condensate [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Change in Development Plan Revisions | bbl		2.4
Fell Block [Member] | LG International Corp [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proportion of ownership interest in joint operation							20.00%
Flamenco Block [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	2.00%	2.00%	2.00%		2.00%	2.00%	2.00%	1.00%	1.00%	1.00%		1.00%	1.00%	9.00%	9.00%	9.00%		9.00%	9.00%
Reserves Proportional Interest Of Net Proved Undeveloped Reserve	3.00%	3.00%	3.00%		3.00%	3.00%	3.00%	1.00%	1.00%	1.00%		1.00%	1.00%
Flamenco Block [Member] | LG International Corp [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proportion of ownership interest in joint operation							31.20%
Cuerva Block [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	1.00%	1.00%	1.00%		1.00%	1.00%	1.00%							3.00%	3.00%	3.00%		3.00%	3.00%
Reserves Proportional Interest Of Net Proved Undeveloped Reserve								2.00%	2.00%	2.00%		2.00%	2.00%	4.00%	4.00%	4.00%		4.00%	4.00%
Llanos 32 [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve								1.00%	1.00%	1.00%		1.00%	1.00%
Llanos 34 Blocks [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	98.00%	98.00%	98.00%		98.00%	98.00%	98.00%	99.00%	99.00%	99.00%		99.00%	99.00%	94.00%	94.00%	94.00%		94.00%	94.00%
Reserves Proportional Interest Of Net Proved Undeveloped Reserve	97.00%	97.00%	97.00%		97.00%	97.00%	97.00%	100.00%	100.00%	100.00%		100.00%	100.00%	95.00%	95.00%	95.00%		95.00%	95.00%
Llanos 34 Blocks [Member] | LG International Corp [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proportion of ownership interest in joint operation							20.00%
Morona Block [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	100.00%	100.00%	100.00%		100.00%	100.00%	100.00%
BCAM-40 Block
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	100.00%	100.00%	100.00%		100.00%	100.00%	100.00%
Fell Block in Chile [Member] | Oil and gas assets [member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proved Developed And Undeveloped Reserves from Exsting Wells Revisions												9
Proved Developed And Undeveloped Reserves from Change in Development Plan Revisions					21.3
Proved developed and undeveloped reserves, extensions and discoveries												4
Proved Developed And Undeveloped Reserves Due to Better Performance Revisions					6.8
Proved Developed And Undeveloped Reserves from Impact of Higher Average Prices Revisions					0.8
Yamu Block [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Reserves, proportional interest of net proved developed reserve	1.00%	1.00%	1.00%		1.00%	1.00%	1.00%
Reserves Proportional Interest Of Net Proved Undeveloped Reserve														1.00%	1.00%	1.00%		1.00%	1.00%
Fell Block One [Member] | LG International Corp [Member]
Disclosure Of Supplemental information on oil and gas activities [Line Items]
Proportion of ownership interest in joint operation							20.00%
[1]	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.
[2]	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.
[3]	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.
[4]	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.
[5]	In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells in the Llanos 34 Block.
[6]	In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca field discoveries in the Llanos 34 Block.