UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K/A

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of March 2020

__________________

Commission File Number: 001-36298

GeoPark Limited

(Exact name of registrant as specified in its charter)

Nuestra Señora de los Ángeles 179

Las Condes, Santiago, Chile

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F X Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes No X

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Yes No X

EXPLANATORY NOTE

Geopark Limited is filing this Amendment No. 1 (the “Form 6-K/A”) to its Form 6-K containing the Consolidated Financial Statements as of and for the year ended December 31, 2019 (the “Annual Financial Statements”), which was originally furnished to the Securities and Exchange Commission on March 4, 2020, solely to correct a typographical error in the name of the engagement partner included in the Report of Independent Registered Public Accounting Firm at December 31, 2019 and 2018, and for each of the three years in the period ended December 31, 2019 (the “Audit Report”). As noted in the new Audit Report furnished herewith, the name of the engagement partner included in the Audit Report is revised to state his full name, Hernan Pablo Rodriguez Cancelo Araujo, instead of only Hernan Rodriguez Cancelo.

Except as set forth above, this Form 6-K/A does not modify or update any of the disclosures in the Annual Financial Statements, which includes the Audit Report. No other changes were made to the previously filed Form 6-K. This Form 6-K/A does not reflect events that may have occurred subsequent to such filing, and does not modify or update information and disclosures made in the previously filed Form 6-K.

GEOPARK LIMITED

TABLE OF CONTENTS

ITEM
1.	GeoPark Limited Consolidated Financial Statements as of and for the year ended December 31, 2019

Item 1

GEOPARK LIMITED

CONSOLIDATED

FINANCIAL STATEMENTS

As of and for the year ended December 31, 2019

GEOPARK LIMITED

DECEMBER 31, 2019

Contents

2	Report of Independent Registered Public Accounting Firm
5	Consolidated Statement of Income
6	Consolidated Statement of Comprehensive Income
7	Consolidated Statement of Financial Position
8	Consolidated Statement of Changes in Equity
9	Consolidated Statement of Cash Flow
10	Notes to the Consolidated Financial Statements

GEOPARK LIMITED

DECEMBER 31, 2019

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of GeoPark Limited

Opinion on the Financial Statements

We have audited the accompanying consolidated statement of financial position of GeoPark Limited and its subsidiaries (the "Company") as of December 31, 2019 and 2018, and the related consolidated statements of income and of comprehensive income, changes in equity and cash flows, for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

2 

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of estimates of proven and probable Oil and Natural Gas Reserves on Property, Plant and Equipment, net

As described in Note 2, 4 and 20 to the consolidated financial statements, the Company’s consolidated property, plant & equipment, net was $567.8 million at December 31, 2019, depreciation expense and impairment loss for non-financial assets for the year ended December 31, 2019 was $102.9 million and $7.6 million, respectively. The Company follows the successful efforts method of accounting for its oil and gas activities. Under this method, all capitalized costs of proved oil and gas properties are amortized by the units-of-production method using proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Periodic revisions to the estimated oil and natural gas reserves and related future net cash flows may be necessary as a result of a number of factors, including expected reservoir characteristics based on geological, geophysical and engineering assessments; future production rates based on historical performance and expected future operating and investment activities; future oil and natural gas prices and quality differentials; assumed effects of regulation by governmental agencies; and future development and operating costs. The Company’s estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers, and certified by independent specialist engaged by the Company.

The principal considerations for our determination that performing procedures relating to the impact of estimates of proven and probable oil and natural gas reserves on property, plant and equipment, net is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proven and probable oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the significant assumptions used in developing those estimates, including future production rates, future oil and natural gas prices and quality differentials, and future development and operating costs. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.

3 

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proven and probable oil and natural gas reserves, the calculation of depreciation expense, and the impairment assessment of property, plant and equipment. These procedures also included, among others, evaluating the methods and significant assumptions used by management in developing these estimates, including future production rates, future oil and natural gas prices and quality differentials, and future development and operating costs, and testing the unit-of production rate used to calculate depreciation expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these estimates of proven and probable oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed also included tests of the data used by the specialists and an evaluation of their findings. Evaluating the significant assumptions relating to the estimates of proven and probable oil and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past and current performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit. In addition, for impairment tests, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained, comprising the Company’s discounted cash flow model and certain significant assumptions, including the discount.

/s/ PRICE WATERHOUSE & CO. S.R.L.

(Partner)

/s/ Hernan Pablo Rodriguez Cancelo Araujo

Autonomous City of Buenos Aires, Argentina
March 4, 2020

We have served as the Company's auditor since 2009.

4 

CONSOLIDATED STATEMENT OF INCOME
Amounts in US$ ´000	Note	2019	2018	2017
REVENUE	7	628,907	601,161	330,122
Commodity risk management contracts	8	(22,523)	16,173	(15,448)
Production and operating costs	9	(168,964)	(174,260)	(98,987)
Geological and geophysical expenses	12	(18,593)	(13,951)	(7,694)
Administrative expenses	13	(60,818)	(52,074)	(42,054)
Selling expenses	14	(14,113)	(4,023)	(1,136)
Depreciation		(105,532)	(92,240)	(74,885)
Write-off of unsuccessful exploration efforts	20	(18,290)	(26,389)	(5,834)
Impairment loss (recognized) reversed for non-financial assets	20-37	(7,559)	4,982	-
Other expenses		(1,840)	(2,887)	(5,088)
OPERATING PROFIT		210,675	256,492	78,996
Financial expenses	15	(41,070)	(39,321)	(53,511)
Financial income	15	2,360	3,059	2,016
Foreign exchange loss	15	(2,446)	(11,323)	(2,193)
PROFIT BEFORE INCOME TAX		169,519	208,907	25,308
Income tax expense	17	(111,762)	(106,240)	(43,145)
PROFIT (LOSS) FOR THE YEAR		57,757	102,667	(17,837)
Attributable to:
Owners of the Company		57,757	72,415	(24,228)
Non-controlling interest		-	30,252	6,391
Earnings (Losses) per share (in US$) for profit (loss) attributable to owners of the Company. Basic	19	0.96	1.19	(0.40)
Earnings (Losses) per share (in US$) for profit (loss) attributable to owners of the Company. Diluted	19	0.92	1.11	(0.40)

The notes on pages 10 to 89 are an integral part of these Consolidated Financial Statements.

5 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Amounts in US$ ´000	2019	2018	2017
Profit (Loss) for the year	57,757	102,667	(17,837)
Other comprehensive income:
Items that may be subsequently reclassified to profit or loss
Currency translation differences	(1,498)	(4,401)	(512)
Gains on cash flow hedges	6,770	-	-
Income tax relating to gains on cash flow hedges	(2,166)	-	-
Other comprehensive profit (loss) for the year	3,106	(4,401)	(512)
Total comprehensive profit (loss) for the year	60,863	98,266	(18,349)
Attributable to:
Owners of the Company	60,863	68,014	(24,740)
Non-controlling interest	-	30,252	6,391

The notes on pages 10 to 89 are an integral part of these Consolidated Financial Statements.

6 

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

Amounts in US$ ´000	Note	2019	2018
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment	20	567,788	557,170
Right-of-use assets	28	13,462	-
Prepayments and other receivables	22	7,031	3,494
Other financial assets	25	10,985	10,570
Deferred income tax asset	18	26,934	31,793
TOTAL NON-CURRENT ASSETS		626,200	603,027
CURRENT ASSETS
Inventories	23	11,447	9,309
Trade receivables	24	44,178	16,215
Prepayments and other receivables	22	51,016	54,659
Derivative financial instrument assets	25	8,097	27,539
Other financial assets	25	14	898
Cash and cash equivalents	25	111,180	127,727
Assets held for sale	36.2	-	23,286
TOTAL CURRENT ASSETS		225,932	259,633
TOTAL ASSETS		852,132	862,660
EQUITY
Equity attributable to owners of the Company
Share capital	26.1	59	60
Share premium		173,716	237,840
Reserves		112,471	111,809
Accumulated losses		(153,361)	(206,688)
Attributable to owners of the Company		132,885	143,021
TOTAL EQUITY		132,885	143,021
LIABILITIES
NON-CURRENT LIABILITIES
Borrowings	27	420,138	429,027
Lease liabilities	28	5,801	-
Provisions and other long-term liabilities	29	62,062	42,577
Deferred income tax liability	18	10,850	14,801
Trade and other payables	30	5,475	14,789
TOTAL NON-CURRENT LIABILITIES		504,326	501,194
CURRENT LIABILITIES
Borrowings	27	17,281	17,975
Lease liabilities	28	7,442	-
Derivative financial instrument liabilities	25	952	-
Current income tax liabilities		57,901	58,776
Trade and other payables	30	131,345	131,420
Liabilities associated with assets held for sale	36.2	-	10,274
TOTAL CURRENT LIABILITIES		214,921	218,445
TOTAL LIABILITIES		719,247	719,639
TOTAL EQUITY AND LIABILITIES		852,132	862,660

The notes on pages 10 to 89 are an integral part of these Consolidated Financial Statements.

7 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Attributable to owners of the Company
Amount in US$ '000	Share Capital	Share Premium	Other Reserve	Translation Reserve	(Accumulated Losses) Retained Earnings	Non-controlling Interest	Total
Equity at January 1, 2017	60	236,046	127,527	2,591	(260,459)	35,828	141,593
Comprehensive income:
(Loss) Profit for the year	-	-	-	-	(24,228)	6,391	(17,837)
Other comprehensive loss for the year	-	-	-	(512)	-	-	(512)
Total Comprehensive (loss) profit for the year 2017	-	-	-	(512)	(24,228)	6,391	(18,349)
Transactions with owners:
Share-based payment (Note 31)	1	3,145	-	-	754	175	4,075
Dividends distribution to non-controlling interest	-	-	-	-	-	(479)	(479)
Total 2017	1	3,145	-	-	754	(304)	3,596
Balances at December 31, 2017	61	239,191	127,527	2,079	(283,933)	41,915	126,840
Comprehensive income:
Profit for the year	-	-	-	-	72,415	30,252	102,667
Other comprehensive loss for the year	-	-	-	(4,401)	-	-	(4,401)
Total Comprehensive (loss) profit for the year 2018	-	-	-	(4,401)	72,415	30,252	98,266
Transactions with owners:
Share-based payment (Note 31)	-	449	-	-	4,830	167	5,446
Repurchase of shares (Note 26.1)	(1)	(1,800)	-	-	-	-	(1,801)
Dividends distribution to non-controlling interest	-	-	-	-	-	(8,089)	(8,089)
Transactions with non-controlling interest (Note 36.1)	-	-	(13,396)	-	-	(64,245)	(77,641)
Total 2018	(1)	(1,351)	(13,396)	-	4,830	(72,167)	(82,085)
Balances at December 31, 2018	60	237,840	114,131	(2,322)	(206,688)	-	143,021
Comprehensive income:
Profit for the year	-	-	-	-	57,757	-	57,757
Other comprehensive income (loss) for the year	-	-	4,604	(1,498)	-	-	3,106
Total Comprehensive profit (loss) for the year 2019	-	-	4,604	(1,498)	57,757	-	60,863
Transactions with owners:
Share-based payment (Note 31)	3	7,144	-	-	(4,430)	-	2,717
Repurchase of shares (Note 26.1)	(4)	(71,268)	-	-	-	-	(71,272)
Cash distribution (Note 26.2)	-	-	(2,444)	-	-	-	(2,444)
Total 2019	(1)	(64,124)	(2,444)	-	(4,430)	-	(70,999)
Balances at December 31, 2019	59	173,716	116,291	(3,820)	(153,361)	-	132,885

The notes on pages 10 to 89 are an integral part of these Consolidated Financial Statements.

8 

CONSOLIDATED STATEMENT OF CASH FLOW

Amounts in US$ '000	Note	2019	2018	2017
Cash flows from operating activities
Profit (Loss) for the year		57,757	102,667	(17,837)
Adjustments for:
Income tax expense	17	111,762	106,240	43,145
Depreciation		105,532	92,240	74,885
Loss on disposal of property, plant and equipment		143	272	190
Impairment loss for non-financial assets	20-37	7,559	(4,982)	-
Write-off of unsuccessful exploration efforts	20	18,290	26,389	5,834
Accrual of borrowing’s interests		29,573	30,444	28,879
Borrowings cancellation costs	15	-	-	17,575
Amortization of other long-term liabilities	29	(429)	(1,005)	(657)
Unwinding of long-term liabilities	15	4,560	3,505	2,779
Accrual of share-based payment		2,717	5,446	4,075
Foreign exchange loss	15	2,446	11,323	2,193
Unrealized loss (gain) on commodity risk management contracts	8	26,411	(42,271)	13,300
Income tax paid		(88,638)	(67,704)	(6,925)
Changes in working capital	5	(42,254)	(6,358)	(25,278)
Cash flows from operating activities – net		235,429	256,206	142,158
Cash flows from investing activities
Purchase of property, plant and equipment		(126,316)	(124,744)	(105,604)
Acquisition of business	36.4	-	(48,850)	-
Proceeds from disposal of long-term assets	36.2	7,066	9,000	-
Cash flows used in investing activities – net		(119,250)	(164,594)	(105,604)
Cash flows from financing activities
Proceeds from borrowings		-	36,017	425,000
Debt issuance costs paid		-	-	(6,683)
Principal paid		(9,790)	(15,073)	(355,022)
Interest paid		(29,099)	(27,695)	(27,688)
Borrowings cancellation costs paid		-	-	(12,315)
Lease payments		(4,855)	-	-
Repurchase of shares	26.1	(71,272)	(1,801)	-
Proceeds from cash calls from related parties		-	-	1,155
Dividends distribution to non-controlling interest		-	(8,089)	(479)
Cash distribution	26.2	(2,444)	-	-
Payments for transactions with non-controlling interest	36.1	(15,000)	(81,000)	-
Cash flows (used in) from financing activities - net		(132,460)	(97,641)	23,968
Net (decrease) increase in cash and cash equivalents		(16,281)	(6,029)	60,522
Cash and cash equivalents at January 1		127,727	134,755	73,563
Currency translation differences		(266)	(999)	670
Cash and cash equivalents at the end of the year		111,180	127,727	134,755
Ending Cash and cash equivalents are specified as follows:
Cash in bank and bank deposits		111,159	127,707	134,734
Cash in hand		21	20	21
Cash and cash equivalents		111,180	127,727	134,755

The notes on pages 10 to 89 are an integral part of these Consolidated Financial Statements.

9 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note

1 General Information

GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is Clarendon House, 2 Church 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 Colombia, Chile, Brazil, Argentina, Peru and Ecuador.

These Consolidated Financial Statements were authorized for issue by the Board of Directors on March 4, 2020.

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.

2.1 Basis of preparation

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 basis, except for the following: certain financial assets and liabilities (including derivative instruments) measured at fair value, and assets held for sale – measured at fair value less costs to sell.

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.

During the year ended December 31, 2019, the Group income tax expense included an out of period adjustment related to prior periods that increased the income tax expense for US$ 9,910,000. The adjustment is related to the increase in deferred tax liabilities as a result of computing as temporary differences originally considered permanent, generated between the tax and book basis of Property, plant and equipment. The Group concluded that this adjustment was not material to the current year or to any previously reported Consolidated Financial Statements.

10 

Note

2 Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure

New and amended standards adopted by the Group

The following standards have been adopted by the Group for the first time for the financial year beginning on or after January 1, 2019:

· IFRS 16 Leases

· Prepayment Features with Negative Compensation – Amendments to IFRS 9

· Long-term Interests in Associates and Joint Ventures – Amendments to IAS 28

· Annual Improvements to IFRS Standards 2015 – 2017 Cycle

· Plan Amendment, Curtailment or Settlement – Amendments to IAS 19

· Interpretation 23 Uncertainty over Income Tax Treatments.

The Group also elected to adopt the following amendments early:

· Definition of Material – Amendments to IAS 1 and IAS 8.

IFRS 16 - Leases

The Group has adopted IFRS 16 following the simplified approach, and has not restated comparative figures for previous reporting periods, as permitted under the specific transitional provisions in the standard. The impacts arising from the new leasing rules are therefore recognized in the opening balance sheet on January 1, 2019.

On adoption of IFRS 16, the Group recognized lease liabilities in relation to leases which had previously been classified as ‘operating leases’ under the principles of IAS 17 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate as of January 1, 2019. The weighted average lessee’s incremental borrowing rate applied to the lease liabilities on January 1, 2019 was 9.4%.

The table below summarizes the initial measurement of lease liabilities:

Amounts in US$ '000	Total
Operating lease commitments disclosed as at December 31, 2018 (Note 33.3)	69,938
(Less) Contracts reassessed as not being lease contracts in accordance with IFRS 16	(34,239)
(Less) Short-term leases not recognized as a liability	(17,537)
(Less) Low-value leases not recognized as a liability	(341)
Lease liabilities recognized as at January 1, 2019 (at nominal value)	17,821
Lease liabilities recognized as at January 1, 2019 (at present value)	14,610
Classified as follows:
Current	7,967
Non-current	6,643

11 

Note

2 Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure (continued)

The table below summarizes the recognition of assets related to the adoption of IFRS 16:

Amounts in US$ '000	Total
Right-of-use assets at January 1, 2019	14,610
Additions	2,496
Depreciation during the period	(3,644)
Right-of-use assets at December 31, 2019	13,462

Impact on segment information

As a result of the change in the accounting policy, segment assets as of December 31, 2019 increased for the amount of the Right-of-use assets. Nevertheless, there is no impact on Adjusted EBITDA as a consequence of the adoption of this new standard, as specified in the indenture governing the Notes issued by the Company which considers IFRS in effect as of September 21, 2017.

Practical expedients applied

In applying IFRS 16 for the first time, the Group has used the following practical expedients permitted by the standard:

· the use of a single discount rate to a portfolio of leases with reasonably similar characteristics,

· reliance on previous assessments on whether leases are onerous,

· the accounting for operating leases with a remaining lease term of less than 12 months as at January 1, 2019 as short-term leases,

· the exclusion of initial direct costs for the measurement of the right-of-use asset at the date of initial application, and

· the use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease.

Accounting for the Group’s leasing activities

The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of 1 to 7 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants, but leased assets may not be used as security for borrowing purposes.

Until the 2018 financial year, leases of property, plant and equipment were classified as either finance or operating leases. Payments made under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the period of the lease.

12 

Note

2 Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure (continued)

From January 1, 2019, leases are recognized as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. Each lease payment is allocated between the liability and finance expenses. The finance expense is charged to the Condensed Consolidated Statement of Income over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

· fixed payments, less any lease incentives receivable,

· variable lease payments that are based on an index or a rate,

· amounts expected to be payable by the lessee under residual value guarantees,

· the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and

· payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.

The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.

Right-of-use assets are measured at cost comprising the following:

· the amount of the initial measurement of lease liability,

· any lease payments made at or before the commencement date less any lease incentives received,

· any initial direct costs, and

· restoration costs.

Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense in the Condensed Consolidated Statement of Income. Short-term leases are leases with a lease term of 12 months or less. Low-value asses comprise IT equipment and small items of office furniture.

The adoption of the other amendments listed above did not have any impact on the amounts recognized in prior and current periods and are not expected to significantly affect future periods.

New standards, amendments and interpretations issued but not effective for the financial year beginning January 1, 2019 and not early adopted.

Certain new accounting standards and interpretations have been published that are not mandatory for December 31, 2019 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

13 

Note

2 Summary of significant accounting policies (continued)

2.2 Going concern

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 and US$ 350,000,000 debt fundraisings completed in September 2017 and January 2020, respectively (see Notes 27 and 38.2), the Group’s cash position, and the fact that over 96% of its total indebtedness as of December 31, 2019 matures in 2024, the Directors have formed a judgement, at the time of approving the financial statements, that there is a reasonable expectation that the Group has adequate resources to meet all its obligations for the foreseeable future. For this reason, the Directors have continued to adopt the going concern basis in preparing the Consolidated Financial Statements.

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 over the fair value of the identifiable net assets acquired is recorded as goodwill. If the total of consideration transferred is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognized directly in the income statement.

Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are eliminated. Unrealized 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.

14 

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2 Summary of significant accounting policies (continued)

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.

2.5 Foreign currency translation

2.5.1 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 Colombia, Chile, Argentina, Peru and Ecuador is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the Brazilian Real.

2.5.2 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 recognized in the Consolidated Statement of Income.

The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows: assets and liabilities are translated at the closing rate, and income and expenses are translated at average exchange rates. All resulting exchange differences are recognized in Other comprehensive income.

2.6 Joint arrangements

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.

15 

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2 Summary of significant accounting policies (continued)

2.7 Revenue recognition

Revenue from the sale of crude oil and gas is recognized in the Consolidated Statement of Income when control 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 33.1.

2.8 Production and operating costs

Production and operating costs are recognized in the Consolidated Statement of Income on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, and royalties are also included within this account.

2.9 Financial results

Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. The Group has capitalized the borrowing cost directly attributable to wells and facilities identified as qualifying assets. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Group’s general borrowings during the year, which was 6.90% at year-end 2019 (6.90% at year-end 2018 and 6.90% in 2017). Amounts capitalized during the year amounted to US$ 366,561 (US$ 257,507 in 2018 and US$ 610,841 in 2017).

2.10 Property, plant and equipment

Property, plant and equipment are stated at historical cost less depreciation and impairment charges, 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, capitalizing 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 amortization 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 discovered 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.

16 

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2 Summary of significant accounting policies (continued)

2.10 Property, plant and equipment (continued)

A charge of US$ 18,290,000 has been recognized in the Consolidated Statement of Income within Write-off of unsuccessful exploration efforts (US$ 26,389,000 in 2018 and US$ 5,834,000 in 2017). See Note 20.

All field development costs are considered construction in progress until they are finished and capitalized 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 capitalized as development costs. Maintenance costs are charged to the Consolidated Statement of Income when incurred.

Capitalized 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 recognized 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 and 10 years.

Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow 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).

2.11 Provisions and other long-term liabilities

Provisions for asset retirement obligations and other environmental liabilities, deferred income, restructuring obligations and legal claims are recognized 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, if any, 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 recognized as financial expense.

17 

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2 Summary of significant accounting policies (continued)

2.11 Provisions and other long-term liabilities (continued)

2.11.1 Asset Retirement Obligation

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 capitalizes 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 capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and the 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.

2.11.2 Deferred Income

Government grants relating to the purchase of property, plant and equipment and contributions received in cash from the Group’s clients to improve the project economics of gas wells are included in non-current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions.

2.12 Impairment of non-financial assets

Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

An impairment loss is recognized for the excess of the asset’s carrying amount over 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 2019, impairment loss was recognized for US$ 7,559,000 (impairment loss reversed for US$ 4,982,000 in 2018 and no impairment loss recognized or reversed in 2017). See Note 37. The write-offs are detailed in Note 20.

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2 Summary of significant accounting policies (continued)

2.13 Lease contracts

The Group has changed its accounting policy for leases where the Group is the lessee. The new policy and the impact of the change are described in Note 2.1.1.

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. Until December 31, 2018, payments related to operating leases and other rental agreements were recognized 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 33.3.

Leases in which substantially all of the risks and rewards of ownership are transferred to the lessee are classified as finance leases. Finance leases has to be recognized, at the lease’s inception, at the fair value of the leased property or, if lower, the present value of the minimum lease payments.

2.14 Inventories

Inventories comprise crude oil and materials.

Crude oil is measured at the lower of cost and net realizable 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.

2.15 Current and deferred income tax

The tax expense for the year comprises current and deferred tax. Tax is recognized 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 recognized, 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 realized, or the deferred income tax liability is settled.

In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions that are available to be offset against future taxable profit. However, deferred tax assets are recognized 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.

19 

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2 Summary of significant accounting policies (continued)

2.15 Current and deferred income tax (continued)

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 recognized 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 recognize amounts to approximately US$ 4,000,000.

Deferred tax balances are provided in full, with no discounting.

2.16 Non-current assets or disposal groups held for sale

Non-current assets or disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights under insurance contracts, which are specifically exempt from this requirement.

An impairment loss is recognized for any initial or subsequent write-down of the asset or disposal group to fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset or disposal group, but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the date of the sale of the non-current asset or disposal group is recognized at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized.

Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented separately from the other assets in the Consolidated Statement of Financial Position. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the Consolidated Statement of Financial Position.

20 

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2 Summary of significant accounting policies (continued)

2.17 Financial assets

Financial assets are divided into the following categories: amortized cost, financial assets at fair value through profit or loss and fair value through other comprehensive income. The classification depends on the Group’s business model for managing the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when its business model for managing those assets changes.

All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs. Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss.

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 recognized in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured.

Amortized cost 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. These financial assets comprise trade and other receivables and cash and cash equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, less provision for impairment, if applicable.

Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of Income. All of the Group’s financial assets are classified as amortized cost.

2.18 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 short-term investments with original maturities up to twelve months and over three months.

2.19 Impairment of financial assets

The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied depends on whether there has been a significant increase in credit risk. For trade receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial recognition of the receivables.

21 

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2 Summary of significant accounting policies (continued)

2.20 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 that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position.

2.21 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 recognized initially at fair value and subsequently measured at amortized cost using the effective interest method.

2.22 Derivatives and hedging activities

Derivative financial instruments are recognized in the statement of financial position as assets or liabilities and initially and subsequently measured at fair value. 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 mark-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.

2.22.1 Cash flow hedges that qualify for hedge accounting

The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in Other Reserve within Equity. The gain or loss relating to the ineffective portion is recognized immediately in the Consolidated Statement of Income.

When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the forward contracts are recognized in Other Reserve within Equity.

Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost of the asset.

22 

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2 Summary of significant accounting policies (continued)

2.22 Derivatives and hedging activities (continued)

2.22.1 Cash flow hedges that qualify for hedge accounting (continued)

When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately reclassified to the Consolidated Statement of Income.

For more information about derivatives designated as cash flow hedges please refer to Note 38.

2.22.2 Other Derivatives

Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that does not qualify for hedge accounting are recognized immediately in the Consolidated Statement of Income.

For more information about derivatives related to commodity risk management please refer to Note 8 and for more information about derivatives related to currency risk management please refer to Note 15.

2.23 Borrowings

Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument.

Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized 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 accrual basis using the effective interest method.

23 

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2 Summary of significant accounting policies (continued)

2.24 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 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, and

- the changes in the fair value of the effective portion of derivatives designated as cash flow hedges.

· "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries.

· "(Accumulated losses) Retained earnings" representing:

- accumulated earnings and losses, and

- the equity element attributable to shares granted according to IFRS 2 but not issued at year end.

2.25 Share-based payment

The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to 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 recognized 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 recognizes 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 to the market value of the shares and recognized 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.

24 

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 Colombia, Chile, Argentina, Peru and Ecuador the functional currency is the US Dollar. The fluctuation of the local currencies of these countries against the US Dollar, except for Ecuador where the local currency is 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 Colombian, Chilean, Argentinean and Peruvian 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 and income tax.

The Group minimises the local currency positions in Colombia, Chile, Argentina and Peru by seeking to balance 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, except for what it is described below.

Since December 2018, GeoPark decided to manage its future exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, the Group entered into derivative financial instruments with local banks in Colombia, for an amount equivalent to US$ 83,700,000 as of December 31, 2019 (US$ 92,050,000 as of December 31, 2018), in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. The Group’s derivatives are accounted for as non-hedge derivatives as of December 31, 2019 and 2018 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the results of the periods in which they occur. See the impact in the Consolidated Statement of Income in Note 15.

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 2019, the Colombian Peso devalued by 1% (devalued by 9% in 2018 and revalued by 1% in 2017) against the US Dollar, the Chilean Peso devalued by 8% (devalued by 13% in 2018 and revalued by 8% in 2017), the Argentine Peso devalued by 59% (102% and 17% in 2018 and 2017) and the Peruvian Peso revalued by 2% (devalued by 4% in 2018 and revalued by 4% in 2017).

25 

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3 Financial Instruments-risk management (continued)

Currency risk (continued)

If the Colombian Peso, the Chilean Peso, the Argentine Peso and the Peruvian Peso had each devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by US$ 644,543 (post-tax profit lower by US$ 57,000 in 2018 and post-tax loss higher by US$ 1,538,000 in 2017).

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 provision for asset retirement obligation and the lease liabilities. The intercompany loan that also used to be denominated in US Dollars was fully cancelled in October 2018, reducing significantly the exposure to foreign currency fluctuation. The exchange loss generated by the Brazilian subsidiary during 2019 amounted to US$ 664,000 (loss of US$ 5,862,000 in 2018 and loss of US$ 1,274,000 in 2017).

During 2019, the Brazilian Real devalued by 4% against the US Dollar (devalued by 17% in 2018 and devalued by 2% in 2017, respectively). If the Brazilian Real had devalued 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by US$ 927,000 (post-tax profit lower by US$ 515,000 in 2018 and post-tax loss higher by US$ 3,100,000 in 2017).

As currency rate changes between the US Dollar and the local currencies, the Group recognizes gains and losses in the Consolidated Statement of Income.

In relation to the cash consideration payable for the acquisition of Amerisur Resources Plc, GeoPark was exposed to fluctuations of the British Pound Sterling (“GBP”) at year end. Consequently, the Group decided to manage this exposure by entering into a “Deal Contingent Forward” (DCF) with a UK Bank, in order to anticipate any currency fluctuation. This forward contract was accounted for as a cash flow hedge as of December 31, 2019 and therefore the effective portion of the changes in its fair value was recognized in Other Reserve within Equity. See Note 38.1.

Price risk

The realized oil price for the Group is linked to US dollar denominated crude oil international benchmarks. The market price of this commodity is subject to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil, the geopolitical landscape, the economic conditions and a variety of additional factors. The main factors affecting realized prices for gas sales vary across countries with some closely linked to international references while others are more domestically driven.

In Colombia, the realized 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.

26 

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3 Financial Instruments-risk management (continued)

Price risk (continued)

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.

In Argentina, the realized oil prices for the production in the Neuquen Basin follows the “Medanito” blend oil price reference, which has traditionally been linked to ICE Brent adjusted by certain marketing and quality discounts based on API, delivery point and transport costs. Between August 16, 2019 and November 13, 2019, domestic crude oil prices were regulated industry-wide at a lower price than the international markets. After that, domestic prices have been deregulated and are agreed between sellers and buyers.

Gas sales in Argentina are carried out through annual contracts that go from May to April. The price of the gas sold under these contracts depends mainly on domestic supply and demand and regulation affecting the sector.

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 profit for the year would have been lower by US$ 38,339,661 (post-tax profit lower by US$ 13,709,000 in 2018 and post-tax loss higher by US$ 10,423,000 in 2017).

GeoPark manages 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 recognized values of commodities sold. GeoPark considers that there is no significant risk associated to the Group’s major customers and hedging counterparties.

27 

Note

3 Financial Instruments-risk management (continued)

Credit risk – concentration (continued)

In Colombia, during 2019, the Colombian subsidiaries made 52% of the oil sales to Trafigura (one of the world’s leading independent commodity trading and logistics houses) and 38% to Ecopetrol (the State-owned oil and gas company), with these two clients accounting for 78% of the consolidated revenue for the same period. With the expiration of the long-term contract with Trafigura in December 2018, GeoPark begun diversifying its client base in Colombia, allocating sales on a competitive basis to industry leading participants including traders and other producers. The contracts extend through 2019 with no longer term delivery commitments in place. Delivery points include wellhead and other locations on the Colombian pipeline system. GeoPark manages its counterparty credit risk associated to sales contracts by including, in certain contracts, early payment conditions to minimize the exposure.

All the oil produced in Chile as well as the gas produced by TdF blocks until 2018 (5% of the consolidated revenue, 3% in 2018 and 5% in 2017) is sold to ENAP, the State-owned oil and gas company. In Chile, most of gas production is sold to the local subsidiary of Methanex, a Canadian public company (3% of the consolidated revenue, 3% in 2018 and 5% in 2017).

In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the State-owned company, which is the operator of the Manati Field (4% of the consolidated revenue, 5% in 2018 and 10% in 2017). The crude oil production from the Reconcavo Basin since 2019 (representing less than a 1% of the consolidated revenue) is sold to local customers in the states of Bahia and Espirito Santo or also to Petrobras.

In Argentina, most of the gas produced is sold to Grupo Albanesi, a leading Argentine privately-held conglomerate focused on the energy market that offers natural gas, power supply and transport services to its customers. GeoPark has an annual agreement with this client in effect from May 2019 through April 2020. Gas sales in Argentina account for 1% of the consolidated revenues.

The oil sales in Argentina are diversified across clients and delivery points: i) 42% of the oil produced in Argentina (2% of the consolidated revenue) is sold locally in Neuquen, delivered at well-head; and ii) 58% of the oil produced in Argentina (3% of the consolidated revenue) is sold to major Argentinean refineries, delivered via pipeline. GeoPark manages the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure.

The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk.

GeoPark executes 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.

28 

Note

3 Financial Instruments-risk management (continued)

Funding and Liquidity risk

In the past, the Group has been able to raise capital through different sources of funding including equity, strategic partnerships and financial debt.

The Group is positioned at the end of 2019 with a cash balance of US$ 111,180,000 and over 96% of its total indebtedness matures in 2024. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 42,000 boepd in production at year end. This scale and positioning permit the Group to protect its financial condition and selectively allocate capital to the optimal projects subject to prevailing macroeconomic conditions.

The Indenture governing the Company Notes 2024 includes incurrence test covenants related to 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 during the last three years include:

In October 2018, the Brazilian subsidiary executed a loan agreement with Banco Santander for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of the loan execution) to repay an existing US$-denominated intercompany loan to GeoPark Latin America Limited - Agencia en Chile.

In April 2018, the Colombian subsidiary executed an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provided GeoPark with access to up to US$ 25,000,000 in the form of prepaid future oil sales. The availability period for the prepayment agreement expired on March 31, 2019. GeoPark did not withdrawn any amount from this prepayment agreement.

In September 2017, the Company successfully placed US$ 425,000,000 Notes. These Notes carry a coupon of 6.50% per annum and their final maturity will be September 21, 2024. The net proceeds from the Notes were used by the Group to fully repay the 7.50% senior secured Notes due 2020 and for general corporate purposes, including capital expenditures and to repay other existing indebtedness.

In addition to that, after the balance sheet date, the Company successfully placed US$ 350,000,000 Notes. These Notes were priced at 99.285% and carry a coupon of 5.50% per annum (yield 5.625% per annum). Final maturity of the Notes will be January 17, 2027. See more information in Note 38.2.

29 

Note

3 Financial Instruments-risk management (continued)

Interest rate risk

The Group’s interest rate risk arises from long-term borrowings issued at variable rates, which expose the Group to interest rate risk.

The Group does not face interest rate risk on its US$ 425,000,000 Notes which carry a fixed rate coupon of 6.50% per annum. Consequently, the accruals and interest payment are not substantially affected by the market interest rate changes.

At December 31, 2019, the outstanding borrowing affected by a variable rate amounted to US$ 9,607,000, representing 2% of total borrowings. It corresponds to a loan from Santander Bank taken by the Brazilian subsidiary that has a floating interest rate based on CDI (Interbank certificate of deposit), which represents the average rate of all inter-bank overnight transactions in Brazil.

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. For each simulation, the same interest rate is used for all currencies. The scenarios are run only for liabilities that represent the major interest-bearing positions.

At December 31, 2019, if 1% is added to interest rates on currency-denominated borrowings with all other variables held constant, post-tax profit for the year would have been lower by US$ 93,000 (post-tax profit lower by US$ 21,000 in 2018 and no exposure to fluctuations in the interest rate in 2017).

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, due to the market conditions prevailing during the last years and the growth strategy of the Group, is to keep the gearing ratio within a 60% to 80% range.

30 

Note

3 Financial Instruments-risk management (continued)

Capital risk management (continued)

The gearing ratios at December 31, 2019 and 2018 were as follows:

Amounts in US$ '000	2019	2018
Net Debt	326,239	319,275
Total Equity	132,885	143,021
Total Capital	459,124	462,296
Gearing Ratio	71%	69%

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. 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 internal 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 may differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 37).

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 December 31, 2019 prepared by DeGolyer and MacNaughton, an independent international consultancy to the oil and gas industry based in Dallas, Texas. It incorporates many factors and assumptions including:

31 

Note

4 Accounting estimates and assumptions (continued)

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 and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the 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 recognizing 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 recognized 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, social 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.

32 

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.

The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flow:

Amounts in US$ '000	2019	2018	2017
Increase (Decrease) in asset retirement obligation	13,299	(4,355)	5,943
Increase (Decrease) in provisions for other long-term liabilities	1,867	(60)	2,053
Purchase of property, plant and equipment	(733)	1,100	11,759

Changes in working capital shown in the Consolidated Statement of Cash Flow are disclosed as follows:

Amounts in US$ '000	2019	2018	2017
(Increase) Decrease in Inventories	(1,675)	511	(2,031)
(Increase) Decrease in Trade receivables	(27,839)	3,423	(1,344)
Increase in Prepayments and other receivables and Other assets	(27,547)	(36,061)	(23,425)
Customer advance repayments (a)	-	(10,000)	(10,000)
Security deposit utilised (granted) (Note 36.4)	-	15,600	(15,600)
Increase in Trade and other payables	14,807	20,169	27,122
	(42,254)	(6,358)	(25,278)

^(a) In December 2015, the Colombian subsidiary entered into a prepayment agreement with Trafigura under which GeoPark sells and deliver a portion of its Colombian crude oil production. Funds committed were repaid by the Group on a monthly basis through oil deliveries until December 2018.

33 

Note

5 Consolidated Statement of Cash Flow (continued)

The following chart shows the movements in the borrowings, lease liabilities and payables to related parties for each of the periods presented:

Amounts in US$ ‘000	Borrowings	Lease liabilities	Payables to related parties	Total
At January 1, 2017	358,672	-	27,801	386,473
Proceeds from borrowings	425,000	-	-	425,000
Debt issuance costs paid	(6,683)	-	-	(6,683)
Proceeds from cash calls from related parties	-	-	1,155	1,155
Accrual of borrowing’s interests	26,651	-	2,228	28,879
Borrowings cancellation costs	17,575	-	-	17,575
Exchange difference	(1,320)	-	1,742	422
Foreign currency translation	1,334	-	(1,742)	(408)
Principal paid	(355,022)	-	-	(355,022)
Interest paid	(27,688)	-	-	(27,688)
Borrowings cancellation costs paid	(12,315)	-	-	(12,315)
At December 31, 2017	426,204	-	31,184	457,388
Proceeds from borrowings	36,017	-	-	36,017
Accrual of borrowing’s interests	28,842	-	1,602	30,444
Exchange difference	(2)	-	4,333	4,331
Foreign currency translation	(1,291)	-	(4,333)	(5,624)
Principal paid	(15,073)	-	-	(15,073)
Interest paid	(27,695)	-	-	(27,695)
Payments to related parties	-	-	(32,786)	(32,786)
At December 31, 2018	447,002	-	-	447,002
Initial recognition of lease liabilities	-	14,610	-	14,610
Addition to lease liabilities	-	2,496	-	2,496
Accrual of borrowing’s interests	29,940	-	-	29,940
Exchange difference	5	566	-	571
Foreign currency translation	(639)	7	-	(632)
Unwinding of discount	-	419	-	419
Principal paid	(9,790)	-	-	(9,790)
Interest paid	(29,099)	-	-	(29,099)
Lease payments	-	(4,855)	-	(4,855)
At December 31, 2019	437,419	13,243	-	450,662

34 

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 to 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 (determined as if IFRS 16 Leases has not been adopted, as specified in the indenture governing the 2024 Notes), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration 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 to the Executive Committee is measured in a manner consistent with that in the financial statements.

Segment areas (geographical segments):

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Ecuador	Corporate	Total
2019
Revenue	538,917	32,336	23,049	34,605	-	-	-	628,907
Sale of crude oil	536,986	10,551	1,469	30,024	-	-	-	579,030
Sale of gas	1,931	21,785	21,580	4,581	-	-	-	49,877
Realized gain on commodity risk management contracts	3,888	-	-	-	-	-	-	3,888
Production and operating costs	(116,944)	(19,789)	(5,953)	(26,278)	-	-	-	(168,964)
Royalties	(56,399)	(1,181)	(1,855)	(5,141)	-	-	-	(64,576)
Share-based payment	(231)	(31)	(29)	(38)	-	-	-	(329)
Operating costs	(60,314)	(18,577)	(4,069)	(21,099)	-	-	-	(104,059)
Operating profit (loss)	297,783	(26,869)	1,750	(34,124)	(7,468)	(536)	(19,861)	210,675
Operating netback	413,120	12,218	15,055	6,691	-	-	-	447,084
Adjusted EBITDA	367,058	8,310	11,750	868	(6,540)	(535)	(17,576)	363,335
Depreciation	(46,917)	(34,826)	(7,445)	(15,618)	(576)	(1)	(149)	(105,532)
Recognition of impairment losses	-	-	-	(7,559)	-	-	-	(7,559)
Write-off	-	-	(5,120)	(13,170)	-	-	-	(18,290)
Total assets	357,125	249,207	68,480	79,062	53,993	1,119	43,146	852,132
Employees (average) (a)	195	89	13	133	26	2	3	461
Employees at year end (a)	202	77	13	128	14	2	3	439

^(a) Unaudited.

35 

Note

6 Segment information (continued)

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Corporate	Total
2018
Revenue	497,870	37,359	30,053	35,879	-	-	601,161
Sale of crude oil	496,341	17,402	1,198	30,549	-	-	545,490
Sale of gas	1,529	19,957	28,855	5,330	-	-	55,671
Realized loss on commodity risk management contracts	(26,098)	-	-	-	-	-	(26,098)
Production and operating costs	(118,533)	(21,899)	(8,785)	(25,043)	-	-	(174,260)
Royalties	(62,710)	(1,473)	(2,820)	(4,833)	-	-	(71,836)
Share-based payment	(461)	(226)	(37)	(154)	-	-	(878)
Operating costs	(55,362)	(20,200)	(5,928)	(20,056)	-	-	(101,546)
Operating profit (loss)	309,357	(29,139)	4,370	(6,739)	(4,529)	(16,828)	256,492
Operating netback	352,672	15,153	21,306	8,527	-	-	397,658
Adjusted EBITDA	319,447	8,784	17,908	4,576	(7,077)	(13,082)	330,556
Depreciation	(42,721)	(28,203)	(10,395)	(10,640)	(245)	(36)	(92,240)
Reversal (recognition) of impairment losses	11,531	(6,549)	-	-	-	-	4,982
Write-off	(17,665)	(6,121)	(2,020)	(583)	-	-	(26,389)
Total assets	383,450	276,449	70,424	87,259	35,817	9,261	862,660
Employees (average) (a)	182	101	12	121	27	2	445
Employees at year end (a)	178	100	12	137	28	2	457

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Corporate	Total
2017
Revenue	263,076	32,738	34,238	70	-	-	330,122
Sale of crude oil	262,309	15,873	910	70	-	-	279,162
Sale of gas	767	16,865	33,328	-	-	-	50,960
Realized loss on commodity risk management contracts	(2,148)	-	-	-	-	-	(2,148)
Production and operating costs	(66,913)	(20,999)	(10,737)	(338)	-	-	(98,987)
Royalties	(24,236)	(1,314)	(3,134)	(13)	-	-	(28,697)
Share-based payment	(248)	(170)	(39)	-	-	-	(457)
Operating costs	(42,429)	(19,515)	(7,564)	(325)	-	-	(69,833)
Operating profit (loss)	116,290	(19,675)	4,434	(3,430)	(3,850)	(14,773)	78,996
Operating netback	194,013	11,222	23,540	(467)	-	-	228,308
Adjusted EBITDA	168,303	4,070	20,166	(2,183)	(3,505)	(11,075)	175,776
Depreciation	(40,010)	(23,730)	(10,809)	(159)	(139)	(38)	(74,885)
Write-off	(1,625)	(546)	(2,978)	(685)	-	-	(5,834)
Total assets	288,429	301,931	91,604	30,924	22,099	51,176	786,163
Employees (average) (a)	164	102	12	88	13	-	379
Employees at year end (a)	180	102	12	92	19	-	405

^(a) Unaudited.

Approximately 61% of capital expenditure was incurred by Colombia (78% in 2018 and 76% in 2017), 8% was incurred by Chile (6% in 2018 and 10% in 2017), 4% was incurred by Brazil (2% in 2018 and 3% in 2017), 15% was incurred by Argentina (7% in 2018 and 8% in 2017) and 12% was incurred by Peru (7% in 2018 and 3% in 2017).

36 

Note

6 Segment information (continued)

A reconciliation of total Operating netback to total profit before income tax is provided as follows:

Amounts in US$ '000	2019	2018	2017
Operating netback	447,084	397,658	228,308
Administrative expenses	(60,130)	(48,028)	(38,937)
Geological and geophysical expenses	(23,619)	(19,074)	(13,595)
Adjusted EBITDA for reportable segments	363,335	330,556	175,776
Unrealized (loss) gain on commodity risk management contracts	(26,411)	42,271	(13,300)
Depreciation (a)	(105,532)	(92,240)	(74,885)
Share-based payment	(2,717)	(5,446)	(4,075)
Impairment and write-off of unsuccessful exploration efforts	(25,849)	(21,407)	(5,834)
Lease accounting - IFRS 16	4,855	-	-
Others (b)	2,994	2,758	1,314
Operating profit	210,675	256,492	78,996
Financial expenses	(41,070)	(39,321)	(53,511)
Financial income	2,360	3,059	2,016
Foreign exchange loss	(2,446)	(11,323)	(2,193)
Profit before tax	169,519	208,907	25,308

^(a) Net of capitalized costs for oil stock included in Inventories.

^(b) Includes allocation to capitalized projects.

Note

7 Revenue

Amounts in US$ '000	2019	2018	2017
Sale of crude oil	579,030	545,490	279,162
Sale of gas	49,877	55,671	50,960
	628,907	601,161	330,122

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 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the results of the periods in which they occur.

37 

Note

8 Commodity risk management contracts (continued)

The following table presents the Group’s derivative contracts in force as of December 31, 2019:

Period	Reference	Type	Volume bbl/d	Price US$/bbl
April 1, 2019 – March 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 79.02 Call
April 1, 2019 – March 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 79.00 Call
July 1, 2019 – March 31, 2020	ICE BRENT	Zero Premium 3 Way	4,000	45.00-55.00 Put 81.50 Call
October 1, 2019 – December 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 71.00 Call
October 1, 2019 – December 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 73.80 Call
November 1, 2019 - December 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 65.20 Call
January 1, 2020 – December 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 69.00 Call
January 1, 2020 – December 31, 2020	ICE BRENT	Zero Premium 3 Way	2,000	45.00-55.00 Put 70.00 Call

The table below summarizes the gain (loss) on the commodity risk management contracts:

	2019	2018	2017
Realized gain (loss) on commodity risk management contracts	3,888	(26,098)	(2,148)
Unrealized (loss) gain on commodity risk management contracts	(26,411)	42,271	(13,300)
Total	(22,523)	16,173	(15,448)

During the year ending December 31, 2019, the Group hedged between 13,000 and 15,000 bbl/d via zero premium collars and three-way hedges (US$10/bbl wide put spread and call), with a minimum average Brent price of US$55/bbl and a maximum average price of US$85/bbl.

The following table presents the Group’s derivative contracts agreed after the balance sheet date:

Period	Reference	Type	Volume bbl/d	Price US$/bbl
April 1, 2020 – December 31, 2020	ICE BRENT	Zero Premium 3 Way	1,000	45.00-55.00 Put 71.95 Call

Note

9 Production and operating costs

Amounts in US$ '000	2019	2018	2017
Staff costs (Note 11)	14,213	17,725	11,901
Share-based payment (Note 11)	329	878	457
Royalties	64,576	71,836	28,697
Well and facilities maintenance	27,660	20,262	14,722
Operation and maintenance	7,743	7,756	3,116
Consumables	17,625	17,444	11,902
Equipment rental	10,476	9,317	5,818
Safety and Insurance costs	4,107	3,878	2,591
Gas plant costs	3,414	5,967	6,069
Transportation costs	2,941	2,628	2,969
Field camp	2,583	2,959	2,377
Non-operated blocks costs	1,353	1,327	1,213
Other costs	11,944	12,283	7,155
	168,964	174,260	98,987

38 

Note

10 Depreciation

Amounts in US$ '000	2019	2018	2017
Oil and gas properties	83,276	72,130	57,725
Production facilities and machinery	16,708	17,958	14,558
Furniture, equipment and vehicles	2,096	1,579	1,948
Buildings and improvements	804	996	844
Depreciation of property, plant and equipment (a)	102,884	92,663	75,075

Related to:

Productive assets	99,984	90,088	72,283
Administrative assets	2,900	2,575	2,792
Depreciation total (a)	102,884	92,663	75,075

^(a) Depreciation without considering capitalized costs for oil stock included in Inventories nor depreciation of right-of-use assets.

Note

11 Staff costs and Directors Remuneration

	2019	2018	2017
Number of employees at year end	439	457	405
Amounts in US$ '000
Wages and salaries	55,325	52,644	41,775
Share-based payments (Note 31)	2,717	5,446	4,075
Social security charges	6,888	7,464	5,364
Director’s fees and allowance	3,266	2,876	3,458
	68,196	68,430	54,672

Recognized as follows:

Production and operating costs	14,542	18,603	12,358
Geological and geophysical expenses	18,448	15,527	11,026
Administrative expenses	35,206	34,300	31,288
	68,196	68,430	54,672

Board of Directors’ and key managers’ remuneration
Salaries and fees	13,483	12,452	9,674
Share-based payments	2,251	2,918	2,322
Other benefits in kind	262	272	287
	15,996	15,642	12,283

39 

Note

11 Staff costs and Directors Remuneration (continued)

Directors’ Remuneration

	Executive Directors’ Fees (in US$)	Executive Directors’ Bonus (in US$)	Non-Executive Directors’ Fees (in US$)	Director Fees Paid in Shares (No. of Shares)	Cash Equivalent Total Remuneration (in US$)
Gerald O’Shaughnessy	400,000	-	-	-	400,000
James F. Park	800,000	909,352	-	-	1,709,352
Pedro E. Aylwin (a)	14,625	-	-	-	14,625
Juan Cristóbal Pavez (b)	-	-	110,000	5,844	210,000
Carlos Gulisano (c)	-	-	108,750	5,844	208,750
Robert Bedingfield (d)	-	-	110,000	5,844	210,000
Jamie Coulter	-	-	90,000	5,844	190,000
Constantine Papadimitriou	-	-	88,750	5,844	188,750

^a Pedro E. Aylwin has a service contract that provides for him to act as Director of Legal and Governance.

^b Compensation Committee Chairman.

^c Technical Committee Chairman.

^d Audit Committee Chairman.

In January 2020, 439,075 shares were issued to Directors as a consequence of the vesting of the 2016 Value Creation Plan (”VCP”). See Note 31.

Note

12 Geological and geophysical expenses

Amounts in US$ '000	2019	2018	2017
Staff costs (Note 11)	18,312	15,005	10,525
Share-based payment (Note 11)	136	522	501
Allocation to capitalized project	(4,834)	(5,645)	(6,402)
Other services	4,979	4,069	3,070
	18,593	13,951	7,694

Note

13 Administrative expenses

Amounts in US$ '000	2019	2018	2017
Staff costs (Note 11)	29,688	27,378	24,713
Share-based payment (Note 11)	2,252	4,046	3,117
Consultant fees (a)	18,685	7,427	5,120
Office expenses	1,386	3,021	2,506
Travel expenses	4,867	4,519	2,772
Director’s fees and allowance (Note 11)	3,266	2,876	3,458
Communication and IT costs	2,928	2,395	2,109
Allocation to joint operations	(8,008)	(7,774)	(7,646)
Other administrative expenses	5,754	8,186	5,905
	60,818	52,074	42,054

^(a) The increase in consultant fees in 2019 is explained mainly by legal and other advisory services related to new business efforts.

40 

Note

14 Selling expenses

Amounts in US$ '000	2019	2018	2017
Transportation (a)	12,985	2,638	864
Selling taxes and other	1,128	1,385	272
	14,113	4,023	1,136

^(b) The increase in transportation costs in 2019 is explained primarily due to the difference in accounting for different points of sale in Colombia and costs associated with the operation of the flowline connecting Llanos 34 block to the ODL regional pipeline. Sales at the wellhead have no selling costs associated but generate lower revenue whereas transportation costs for sales to other delivery points are accounted for as selling expenses.

Note

15 Financial results

Amounts in US$ '000	2019	2018	2017
Financial expenses
Interest and amortization of debt issue costs	(29,977)	(28,955)	(27,823)
Interest with related parties	-	(1,606)	(2,224)
Less: amounts capitalized on qualifying assets	367	258	611
Borrowings cancellation costs	-	-	(17,575)
Bank charges and other financial results	(6,900)	(5,513)	(3,721)
Unwinding of long-term liabilities	(4,560)	(3,505)	(2,779)
	(41,070)	(39,321)	(53,511)
Financial income
Interest received	2,360	3,059	2,016
	2,360	3,059	2,016
Foreign exchange gains and losses
Foreign exchange loss	(6,163)	(11,323)	(2,193)
Realized gain on currency risk management contracts	2,843	-	-
Unrealized gain on currency risk management contracts	874	-	-
	(2,446)	(11,323)	(2,193)
Total Financial results	(41,156)	(47,585)	(53,688)

41 

Note

16 Tax reforms

Colombia

In December 2019, a tax reform was enacted in Colombia. The approved legislation included significant changes in the corporate income tax but also in other taxes and in tax related matters (as procedural rules and special regimes). This tax reform is effective 1 January 2020.

The new legislation includes a progressive reduction of the general corporate income tax rate, previously established at 40% for 2017, 37% for 2018 and 33% for 2019, as follows:

· 32% in 2020

· 31% in 2021

· 30% in 2022 and onwards.

Other changes that could affect the Group are the following:

· The withholding tax rate on dividends for non-resident shareholders was increased from 7.5% to 10%.

· The presumptive taxable income tax rate was reduced from 1.5% to 0.5% in 2020 and 0% in 2021.

· Regarding thin capitalization for income tax purposes, the maximum amount of intragroup debt which interest can be deducted was reduced from 3 to 2 times the net equity of the taxpayer as of 31 December of the previous year.

· Transfers of participations in foreign entities that represent indirect disposals of assets in Colombia remain subject to income tax or to the capital gains tax, depending on certain circumstances. New law allows a step up in basis for an indirect purchaser.

· Former restriction on the discount of VAT paid against corporate income tax for acquisition of productive fixed assets was ratified.

· An audit benefit was granted by the reform, establishing that tax returns of FY 2020 and 2021 showing a net income tax 30% or 20% higher, respectively, than the one declared in the previous year would be considered definitive 6 months or 12 months after became due, also respectively, if there were no objections or requests from the tax authority.

42 

Note

16 Tax reforms (continued)

Argentina

In December 2019, driven by a change of government, a tax reform was enacted in Argentina. The most relevant tax changes are the following:

· Corporate income tax rate of 30% in 2020, as stated for 2018 and 2019. The preceding law established a rate reduction to 25% from 2020, but it was now postponed for 2021.

· Dividend withholding tax rate of 7% in 2020, as stated for 2018 and 2019. The preceding law established a rate increase to 13%, but it was now postponed for 2021.

· The amount determined as tax inflation adjustment for 2019 and 2020 is allocated equally over six years. For tax years beginning on or after 1 January 2021, taxpayers may deduct or tax 100% of the negative or positive inflation adjustment in the year in which the adjustment is calculated.

· Indirect transfer of assets or shares located in Argentina between related parties is not treated as a taxable event.

· The deductibility of foreign exchange differences is restricted up to 30% of taxable profit before interests and depreciation.

· The tax rate on cash withdrawals from local bank accounts was increased from 0.6% to 1.2% for Argentine entities not considered as micro and small enterprises.

· A new tax named “Tax for an inclusive and supportive Argentina” was created. This tax levies, for a five-years period, the following transactions:

o Purchases of foreign currency (i.e., “constitution of foreign assets”) without a specific purpose by Argentine residents.

o Purchases of goods or services from abroad or purchases by Argentine residents abroad through credit, debit or purchase cards, including cash withdrawals made outside Argentina.

o Purchases made online through portals or virtual websites in foreign currency.

o Purchases of services rendered abroad through Argentine travel agencies.

o Purchases of ground, air and water passenger services with destinations outside Argentina.

The tax rate is 30% and applies to the amount of the taxable purchases. Argentine financial institutions, credit card issuers, travel agencies and transport companies act as collection agents of the tax.

Ecuador

In December 2019, a tax reform was enacted in Ecuador. The main aspects are the following:

· Dividends are taxed at a 25% tax rate. Dividend tax basis is 40% of the amount distributed. Benefits and reduction of tax rates provided in Tax Treaties signed by Ecuador are applicable.

· Interest deductibility is limited up to 20% of the corporate profit before taxes, interest and depletion.

· Advanced payment of income tax is eliminated.

43 

Note

17 Income tax

Amounts in US$ '000	2019	2018	2017
Current tax	(111,371)	(101,456)	(48,449)
Deferred income tax (Note 18)	(391)	(4,784)	5,304
	(111,762)	(106,240)	(43,145)

The tax on the Group’s profit 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	2019	2018	2017
Profit before tax	169,519	208,907	25,308
Tax losses from non-taxable jurisdictions	49,360	42,808	22,708
Taxable profit	218,879	251,715	48,016
Income tax calculated at domestic tax rates applicable to Profit in the respective countries	(79,395)	(102,211)	(31,107)
Tax losses where no deferred tax benefit is recognized	(2,563)	(7,344)	(8,111)
Effect of currency translation on tax base	(16,795)	3,336	(2,330)
Effect of inflation adjustment for tax purposes	541	-	-
Changes in the income tax rate (Note 16)	1,279	(1,874)	542
Previously unrecognized tax losses	1,820	4,882	-
Out of period adjustment (a)	(9,910)	-	-
Non-taxable results (b)	(6,739)	(3,029)	(2,139)
Income tax	(111,762)	(106,240)	(43,145)

^(a) See Note 2.1.

^(b) Includes non-deductible expenses in each jurisdiction.

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 (Colombia, Chile, Brazil, Argentina, Peru and Ecuador) ranges from 15% to 33%.

44 

Note

17 Income tax (continued)

The Group has tax losses available which can be utilised against future taxable profit in the following countries:

Amounts in US$ '000	2019	2018	2017
Chile (a)	317,644	315,733	345,104
Brazil (a)	37,848	38,011	33,721
Argentina (b)	22,930	5,490	4,849
Total tax losses at December 31	378,422	359,234	383,674

^(a) Taxable losses have no expiration date.

^(b) Expiring dates for tax losses accumulated at December 31, 2019 are:

Expiring date	Amounts in US$ '000
2021	447
2022	1,109
2023	2,946
2024	18,428

At the balance sheet date deferred tax assets in respect of tax losses in certain companies in Chile have not been recognized as there is insufficient evidence of future taxable profits to offset them.

Note

18 Deferred income tax

The gross movement on the deferred income tax account is as follows:

Amounts in US$ '000	2019	2018
Deferred tax at January 1	16,992	25,350
Currency translation differences	(517)	(3,574)
Income statement credit (charge)	(391)	(4,784)
Deferred tax at December 31	16,084	16,992

The breakdown and movement of deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:

Amounts in US$ '000	At the beginning of year	(Charged) Credited to net profit	Currency translation differences	Reclassification	At the end of year
Deferred tax assets
Difference in depreciation rates and other	(3,077)	(10,947)	(14)	21,918	7,880
Taxable losses	34,870	3,462	(503)	(18,775)	19,054
Total 2019	31,793	(7,485)	(517)	3,143	26,934
Total 2018	27,636	(11,514)	(3,574)	19,245	31,793

45 

Note

18 Deferred income tax (continued)

Amounts in US$ '000	At the beginning of year	Credited (Charged) to net profit	Reclassification	At the end of year
Deferred tax liabilities
Difference in depreciation rates and other	(14,801)	7,094	(21,918)	(29,625)
Taxable losses	-	-	18,775	18,775
Total 2019	(14,801)	7,094	(3,143)	(10,850)
Total 2018	(2,286)	6,730	(19,245)	(14,801)

Note

19 Earnings per share

Amounts in US$ '000 except for shares	2019	2018	2017
Numerator: Profit (Loss) for the year attributable to owners	57,757	72,415	(24,228)
Denominator: Weighted average number of shares used in basic EPS	60,217,523	60,612,230	60,093,191
Earnings (Losses) after tax per share (US$) – basic	0.96	1.19	(0.40)

Amounts in US$ '000 except for shares	2019	2018	2017 (a)
Weighted average number of shares used in basic EPS	60,217,523	60,612,230	60,093,191
Effect of dilutive potential common shares (a)
Stock awards at US$ 0.001	2,433,126	4,758,552	-
Weighted average number of common shares for the purposes of diluted earnings per shares	62,650,649	65,370,782	60,093,191
Earnings (Losses) after tax per share (US$) – diluted	0.92	1.11	(0.40)

^(a) For the year ended December 31, 2017, there were 4,564,777 of potential shares that could have a dilutive impact. They were considered antidilutive due to negative earnings.

46 

Note

20 Property, plant and equipment

Amounts in US$'000	Oil & gas properties	Furniture, equipment and vehicles	Production facilities and machinery	Buildings and improvements	Construction in progress (a)	Exploration and evaluation assets (b)	Total
Cost at January 1, 2017	692,241	14,357	132,413	10,553	32,926	61,773	944,263
Additions	7,997 (c)	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	-	-	-	-	-	(5,834) (d)	(5,834)
Transfers	77,408	211	25,130	-	(61,827)	(40,922)	-
Cost at December 31, 2017	776,504	15,398	157,396	10,361	37,990	64,368	1,062,017
Additions	(5,753) (c)	1,706	-	-	81,961	43,515	121,429
Acquisitions (Note 36.4)	52,925	254	1,616	134	-	-	54,929
Currency translation differences	(11,525)	(130)	(884)	(30)	(15)	(882)	(13,466)
Disposals	-	(46)	(417)	-	-	-	(463)
Write-off / Impairment reversal	5,109 (g)	-	(120) (g)	-	(7) (g)	(26,389) (e)	(21,407)
Transfers	63,794	566	14,503	1,089	(59,332)	(20,620)	-
Assets held for sale (Note 36.2)	(163,544)	-	-	-	-	-	(163,544)
Cost at December 31, 2018	717,510	17,748	172,094	11,554	60,597	59,992	1,039,495
Additions	14,696 (c)	2,052	381	159	96,012	27,449	140,749
Currency translation differences	(3,022)	(414)	(561)	(8)	(106)	(449)	(4,560)
Disposals	-	(102)	(101)	-	-	(59)	(262)
Write-off / Impairment	(7,559) (g)	-	-	-	-	(18,290) (f)	(25,849)
Transfers	83,010	265	24,183	65	(86,916)	(20,607)	-
Reclassification (h)	26,302	-	(23,489)	-	-	-	2,813
Cost at December 31, 2019	830,937	19,549	172,507	11,770	69,587	48,036	1,152,386
Depreciation and write-down at January 1, 2017	(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 December 31, 2017	(441,534)	(11,916)	(86,232)	(4,932)	-	-	(544,614)
Depreciation	(72,130)	(1,579)	(17,958)	(996)	-	-	(92,663)
Disposals	-	42	149	-	-	-	191
Currency translation differences	6,292	92	337	26	-	-	6,747
Assets held for sale (Note 36.2)	148,014	-	-	-	-	-	148,014
Depreciation and write-down at December 31, 2018	(359,358)	(13,361)	(103,704)	(5,902)	-	-	(482,325)
Depreciation	(83,276)	(2,096)	(16,708)	(804)	-	-	(102,884)
Disposals	-	85	34	-	-	-	119
Currency translation differences	2,492	223	480	110	-	-	3,305
Reclassification (h)	(27,664)	-	24,851	-	-	-	(2,813)
Depreciation and write-down at December 31, 2019	(467,806)	(15,149)	(95,047)	(6,596)	-	-	(584,598)
Carrying amount at December 31, 2017	334,970	3,482	71,164	5,429	37,990	64,368	517,403
Carrying amount at December 31, 2018	358,152	4,387	68,390	5,652	60,597	59,992	557,170
Carrying amount at December 31, 2019	363,131	4,400	77,460	5,174	69,587	48,036	567,788

47 

Note

20 Property, plant and equipment (continued)

^(a) Construction in progress includes US$ 36,874,000 as of December 31, 2019 (US$ 22,467,000 and US$ 14,073,000 as of December 31, 2018 and 2017, respectively) of costs incurred in the Morona Block in Peru. In June 2019, GeoPark withdrew the Environmental Impact Assessment (EIA), due to a lack of definition from the Peruvian Government about whether a prior consultation process was needed for the deforestation. This decision has caused a delay in the original development progress of this project. On January 10, 2020, given such lack of definition, Perupetro granted GeoPark a new Force Majeure since June 15, 2019, until the Government pronounces a definite statement regarding the need (or not) of performing prior consultation for the reforestation works included in the corresponding environmental instrument.

^(b) Exploration wells movement and balances are shown in the table below; seismic and other exploratory assets amount to US$ 44,047,000 (US$ 48,779,000 in 2018 and US$ 53,764,000 in 2017).

Amounts in US$ '000	Total
Exploration wells at December 31, 2017	10,604
Additions	43,103
Write-offs	(23,733)
Transfers	(18,761)
Exploration wells at December 31, 2018	11,213
Additions	23,082
Write-offs	(12,941)
Transfers	(17,365)
Exploration wells at December 31, 2019	3,989

As of December 31, 2019, there was an exploratory well that has been capitalized for a period less than a year amounting to US$ 3,989,000.

^(c) Corresponds to the effect of change in estimate of assets retirement obligations.

^(d) 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.

^(e) Corresponds to nine unsuccessful exploratory wells, four wells drilled in Colombia (Tiple, Llanos 34 and Llanos 32 Blocks), two wells drilled in Brazil (POT-T-747 and POT-T-619 Blocks) and three wells drilled in Argentina (Puelen Block). The charge also includes the write-off of a well and other exploration costs incurred in the Fell Block (Chile) in previous years and other exploration costs incurred in the VIM-3 Block (Colombia), and POT-T-882 and REC-T-93 Blocks (Brazil), for which no additional work would be performed.

^(f) Corresponds to five unsuccessful exploratory wells, four wells drilled in Argentina (Sierra del Nevado, Puelen and Aguada Baguales Blocks) and a well drilled in Brazil (POT-T-747 Block). The charge also includes the write-off of wells and other exploration costs incurred in previous years in the Argentinean Blocks for which no additional work would be performed. In addition due to the results from REC-T-94, SEAL-T-268 and POT-T-747 Blocks (Brazil), during December 2019 the Group decided to relinquish these blocks so the associated investment was written off.

^(g) See Note 37.

^(h) Corresponds to the final closing of the sale of the La Cuerva and Yamu Blocks described in Note 36.2.

48 

Note

21 Subsidiary undertakings

The following chart illustrates main companies of the Group structure as of December 31, 2019:

Non-controlling interest that used to be held by LG International until November 28, 2018:

· Consolidated Statement of Comprehensive Income: Total comprehensive income for the years 2018 and 2017 included a profit of US$ 35,284,000 and US$ 13,536,000, a loss of US$ 4,273,000 and US$ 6,200,000 and a loss of US$ 758,000 and US$ 945,000 corresponding to non-controlling interest that used to be held by LGI in GeoPark Colombia S.L.U., GeoPark Chile S.p.A. and GeoPark TdF S.p.A., respectively.

· Consolidated Statement of Changes in Equity: Dividends distributed to non-controlling interest of US$ 8,089,000 in 2018 and US$ 479,000 in 2017 correspond to non-controlling interest that used to be held by LGI in GeoPark Colombia S.L.U.

Corporate structure reorganization

During 2019, the following changes to the Group structure have taken place as part of the corporate structure reorganization started in 2017:

· GeoPark Perú S.A.C. incorporated a branch in Ecuador to attend the activity in that country.

· The subsidiary that used to be named GeoPark Argentina Limited was redomiciled from Bermuda to Argentina.

· The subsidiary GeoPark Colombia Coop U.A. was redomiciled from the Netherlands to Spain.

· The Group finalized a merger process by which GeoPark Latin America S.L.U. continued the operations related to GeoPark Brasil S.L.U. and GeoPark Peru S.L.U.

· The subsidiaries GeoPark S.A and GeoPark Colombia S.A were dissolved.

49 

Note

21 Subsidiary undertakings (continued)

Details of the subsidiaries and joint operations of the Group are set out below:

	Name and registered office	Ownership interest
	GeoPark Argentina S.A.U. (Argentina)	100%
	GeoPark Latin America Limited (Bermuda)	100%
	GeoPark Latin America Limited – Agencia en Chile (Chile)	100% (a)
	GeoPark Brasil Exploração y Produção de Petróleo e Gás Ltda. (Brazil)	100% (a)
	GeoPark Chile S.p.A. (Chile)	100% (a)
	GeoPark Fell S.p.A. (Chile)	100% (a)
	GeoPark Magallanes Limitada (Chile)	100% (a)
	GeoPark TdF S.p.A. (Chile)	100% (a)
	GeoPark Colombia S.A.S. (Colombia)	100% (a)
	GeoPark Latin America S.L.U. (Spain)	100% (a)
	GeoPark Colombia S.L.U. (Spain)	100% (a)
	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 Colombia E&P S.A. (Panama)	100% (a)
	GeoPark Colombia E&P Sucursal Colombia (Colombia)	100% (a)
	GeoPark Mexico S.A.P.I. de C.V. (Mexico)	100% (a) (b)
	GeoPark E&P S.A.P.I. de C.V. (Mexico)	100% (a) (b)
	GeoPark Perú S.A.C. Sucursal Ecuador (Ecuador)	100% (a)
	GeoPark (UK) Limited (United Kingdom)	100%
Joint operations	Flamenco Block (Chile)	50% (c)
	Campanario Block (Chile)	50% (c)
	Isla Norte Block (Chile)	60% (c)
	Llanos 34 Block (Colombia)	45% (c)
	Llanos 32 Block (Colombia)	12.5%
	Puelen Block (Argentina)	18% (d)
	Sierra del Nevado Block (Argentina)	18% (d)
	CN-V Block (Argentina)	50%
	Los Parlamentos Block (Argentina)	50%
	Manati Field (Brazil)	10%
	POT-T-747 Block (Brazil)	70% (c) (d)
	REC-T-128 Block (Brazil)	70% (c)
	POT-T-785 Block (Brazil)	70% (c)
	Morona Block (Peru)	75% (c)
	Espejo Block (Ecuador)	50% (c)
	Perico Block (Ecuador)	50%
	Llanos 86 Block (Colombia)	50% (c)
	Llanos 87 Block (Colombia)	50% (c)
	Llanos 104 Block (Colombia)	50% (c)
	Llanos 123 Block (Colombia)	50% (c)
	Llanos 124 Block (Colombia)	50% (c)

(a) Indirectly owned.

(b) Dormant companies.

(c) GeoPark is the operator.

(d) In process of relinquishment.

On July 2, 2019, GeoPark obtained regulatory approval to increase its working interest in the Tranquilo Block (Chile) to 100%.

50 

Note

22 Prepayments and other receivables

Amounts in US$ '000	2019	2018
V.A.T.	27,052	37,811
Income tax payments in advance	20,609	9,668
Other prepaid taxes	1,069	966
To be recovered from co-venturers (Note 34)	1,035	1,819
Prepayments and other receivables	8,282	7,889
Total	58,047	58,153
Classified as follows:
Current	51,016	54,659
Non-current	7,031	3,494
Total	58,047	58,153

Movements on the Group provision for impairment are as follows:

Amounts in US$ '000	2019	2018
At January 1	546	594
Foreign exchange income	4	(48)
	550	546

Note

23 Inventories

Amounts in US$ '000	2019	2018
Crude oil	4,285	3,369
Materials and spares	7,162	5,940
	11,447	9,309

Note

24 Trade receivables

Amounts in US$ '000	2019	2018
Trade receivables	44,178	16,215
Total	44,178	16,215

As of December 31, 2019 and 2018, there are no balances that were aged by more than 3 months . Trade receivables that are aged by less than three months are not considered impaired.

51 

Note

24 Trade receivables (continued)

The credit period for trade receivables is 30 days. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable. The Group does not hold any collateral as security related to trade receivables.

The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature.

Note

25 Financial instruments by category

Amounts in US$ '000	Assets as per statement of financial position
	2019	2018
Financial assets at fair value through profit or loss
Derivative financial instrument assets	8,097	27,539
Cash and cash equivalents	42,212	53,794
	50,309	81,333
Other financial assets at amortized cost
Trade receivables	44,178	16,215
To be recovered from co-venturers (Note 34)	1,035	1,819
Other financial assets (a)	10,999	11,468
Cash and cash equivalents	68,968	73,933
	125,180	103,435
Total financial assets	175,489	184,768

^(a) Non-current other financial assets relate to contributions made for environmental obligations according to Brazilian government regulations. Current other financial assets corresponds to short-term investments with original maturities up to twelve months and over three months.

52 

Note

25 Financial instruments by category (continued)

	Liabilities as per statement of financial position
Amounts in US$ '000	2019	2018
Liabilities at fair value through profit and loss
Derivative financial instrument liabilities	952	-
	952	-
Other financial liabilities at amortized cost
Trade payables	83,991	69,142
Payables to LGI (Note 36.1)	15,000	29,509
To be paid to co-venturers (Note 34)	4,803	8,449
Lease liabilities	13,243	-
Borrowings	437,419	447,002
	554,456	554,102
Total financial liabilities	555,408	554,102

25.1 Credit quality of financial assets

The credit quality of financial assets that are neither past due nor impaired can be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates:

Amounts in US$ '000	2019	2018
Trade receivables
Counterparties with an external credit rating (Moody’s)
Ba1	1,037	-
B2	780	1,196
Ba2	6,156	5,511
Ba3	-	3,734
Baa3	25,447	-
Caa2	933	-
Counterparties without an external credit rating
Group1 (a)	9,825	5,774
Total trade receivables	44,178	16,215

^(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.

53 

Note

25 Financial instruments by category (continued)

25.1 Credit quality of financial assets (continued)

Cash at bank and other financial assets (a)
Amounts in US$ '000	2019	2018
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services)
A1	6,924	1,315
A2	33,633	595
A3	13,105	765
Aaa-mf	41,219	52,563
Aa1	-	4,732
Aa3	-	17,431
AAA	3,894	14,307
Ba1	1,854	4,033
Ba2	1	1
Baa1	580	13,903
Baa1+	-	4,138
Baa2	5,408	6,534
Ba3	1,262	212
BBB	-	3,199
Counterparties without an external credit rating	14,278	15,448
Total	122,158	139,176

^(a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21,000 (US$ 20,000 in 2018).

25.2 Financial liabilities - contractual undiscounted cash flows

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.

Amounts in US$ '000	Less than 1 year	Between 1 and 2 years	Between 2 and 5 years	Over 5 years
At December 31, 2019
Borrowings	37,621	27,625	507,875	-
Lease liabilities	7,442	2,494	4,479	1,053
Trade payables	83,291	700	-	-
To be paid to co-venturers	28	-	4,775	-
Payables to LGI (Note 36.1)	15,000	-	-	-
	143,382	30,819	517,129	1,053
At December 31, 2018
Borrowings	39,545	38,648	82,875	452,625
Trade payables	68,862	280	-	-
To be paid to co-venturers	8,449	-	-	-
Payables to LGI (Note 36.1)	15,000	15,000	-	-
	131,856	53,928	82,875	452,625

54 

Note

25 Financial instruments by category (continued)

25.3 Fair value measurement of financial instruments

Accounting policies for financial instruments have been applied to classify as either: amortized cost, financial assets at fair value through profit or loss and fair value through other comprehensive income. 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.

25.3.1 Fair value hierarchy

The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value at December 31, 2019 and 2018 on a recurring basis:

Amounts in US$ '000	Level 1	Level 2	At December 31, 2019
Assets
Cash and cash equivalents
Money market funds	42,212	-	42,212
Derivative financial instrument liabilities
Commodity risk management contracts	-	444	444
Currency risk management contracts	-	874	874
Forward contracts relating to forecast transactions	-	6,779	6,779
Total Assets	42,212	8,097	50,309
Liabilities
Derivative financial instrument liabilities
Commodity risk management contracts	-	952	952
Total Liabilities	-	952	952

Amounts in US$ '000	Level 1	Level 2	At December 31, 2018
Assets
Cash and cash equivalents
Money market funds	53,794	-	53,794
Derivative financial instrument liabilities
Commodity risk management contracts	-	27,539	27,539
Total Assets	53,794	27,539	81,333

There were no transfers between Level 2 and 3 during the period.

55 

Note

25 Financial instruments by category (continued)

25.3 Fair value measurement of financial instruments (continued)

25.3.1 Fair value hierarchy (continued)

The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as at December 31, 2019.

25.3.2 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 mark-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.

25.3.3 Fair values of other financial instruments (unrecognized)

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 December 31, 2019 amounts to US$ 453,956,000 (US$ 445,582,000 in 2018). The fair values are based on market price for the Notes and cash flows discounted for other borrowings using a rate based on the borrowing rate and are within level 1 and level 2 of the fair value hierarchy, respectively.

56 

Note

26 Equity

26.1 Share capital and Share premium

Issued share capital	2019	2018
Common stock (amounts in US$ ‘000)	59	60
The share capital is distributed as follows:
Common shares, of nominal US$ 0.001	59,167,584	60,483,447
Total common shares in issue	59,167,584	60,483,447
Authorized 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:

26.1.1 Common shares

As of December 31, 2019, the outstanding common shares confer the following rights on the holder:

· the right to one vote per share;

· ranking pari passu, the right to any dividend declared and payable on common shares;

GeoPark common shares history	Date	Shares issued (millions)	Shares closing (millions)	US$(`000) Closing
Shares outstanding at the end of 2017			60.6	61
Stock awards	Dec 2018	0.1	60.7	61
Stock awards	Dec 2018	(0.2)	60.5	60
Shares outstanding at the end of 2018			60.5	60
Stock awards	Jan 2019	1.5	62.0	62
Buyback program	Mar 2019	(0.7)	61.3	61
Buyback program	Jun 2019	(2.3)	59.0	59
Stock awards	Jul 2019	1.5	60.5	60
Buyback program	Sep 2019	(1.2)	59.3	59
Buyback program	Dec 2019	(0.1)	59.2	59
Shares outstanding at the end of 2019			59.2	59

57 

Note

26 Equity (continued)

26.1 Share capital and Share premium (continued)

26.1.2 Stock Award Program and Other Share Based Payments

Non-Executive Directors Fees

During 2019, the Company issued 29,220 (33,145 in 2018 and 70,485 in 2017) shares to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 499,000 (US$ 449,000 in 2018 and US$ 257,000 in 2017). The amount of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period.

Stock Award Program and Other Share Based Payments

On July 8, 2019, 1,484,847 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 4,311,000.

On January 2, 2019, 50% of the vested Value Creation Plan (“VCP”) awards, representing 1,488,391 common shares, was issued to key management (including 439,075 issued to Directors involved in the performance of the Company), generating a share premium of US$ 2,334,000.

On December 14, 2017, 490,000 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 2,513,000.

On September 13, 2017, 12,546 shares were issued pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 43,000.

In January 2017, 82,306 shares were issued to key management as bonus compensation, generating a share premium of US$ 332,000. 

26.1.3 Buyback Program

On December 20, 2018, the Company’s Board of Directors approved a program to repurchase up to 10% of its shares outstanding or approximately 6,063,000 shares. The repurchase program begun on December 21, 2018 and expired on December 31, 2019. During 2019, the Company purchased 4,318,320 common shares (145,917 in 2018) for a total amount of US$ 71,272,000 (US$ 1,801,000 in 2018). These transactions had no impact on the Group’s results.

26.2 Cash distribution

On November 6, 2019, the Company announced that its Board of Directors declared the initiation of a quarterly cash distribution of US$ 0.0413 per share. Consequently, on December 10, 2019, US$ 2,444,000 were distributed to shareholders of record at the close of business on November 22, 2019. This distribution is deducted from Other Reserve.

58 

Note

27 Borrowings

Amounts in US$ '000	2019	2018
Outstanding amounts as of December 31
2024 Notes (a)	427,812	426,993
Banco Santander (b)	9,607	20,006
Banco de Crédito e Inversiones (c)	-	3
	437,419	447,002
Classified as follows:
Current	17,281	17,975
Non-current	420,138	429,027

(a) 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 September 21, 2024. The Notes are secured with a guarantee granted by GeoPark Colombia S.L.U. and GeoPark Chile S.p.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 provide, among other things, that during the two-years period between September 22, 2019 and September 21, 2021, the Net Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.25 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. As of the date of these Consolidated Financial Statements, the Company is in compliance of all the indenture’s provisions and covenants.

(b) During October 2018, GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. executed a loan agreement with Banco Santander for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of the loan execution) to repay an existing US$-denominated intercompany loan to GeoPark Latin America Limited - Agencia en Chile. The interest rate applicable to this loan is CDI plus 2.25% per annum. “CDI” (Interbank certificate of deposit) represents the average rate of all inter-bank overnight transactions in Brazil. The principal and the interest are paid semi-annually, with final maturity in October 2020.

(c) During February 2016, GeoPark Fell S.p.A. 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 was 4.14% per annum. The interest and the principal were fully repaid in February 2019.

As of the date of these Consolidated Financial Statements, the Group has available credit lines for US$ 168,175,000.

59 

Note

28 Leases

The Consolidated Statement of Financial Position shows the following amounts relating to leases:

Amounts in US$ '000	December 31, 2019	January 1, 2019 (a)
Right of use assets
Production, facilities and machinery	8,785	9,398
Buildings and improvements	4,677	5,212
	13,462	14,610
Lease liabilities
Current	7,442	7,967
Non-current	5,801	6,643
	13,243	14,610

(a) In the previous year, the Group only recognized lease assets and lease liabilities in relation to leases that were classified as ‘finance leases’ under IAS 17 Leases. For adjustments recognized on adoption of IFRS 16 on January 1, 2019, please refer to Note 2.1.1.

The Consolidated Statement of Income shows the following amounts relating to leases:

Amounts in US$ '000	2019
Depreciation charge of Right-of-use assets
Production, facilities and machinery	(1,834)
Buildings and improvements	(1,810)
	(3,644)
Unwinding of long-term liabilities (included in Financial results)	(419)
Expenses related to short-term leases (included in Production and operating cost and Administrative expenses)	(13,463)
Expenses related to low-value leases (included in Administrative expenses)	(314)

60 

Note

29 Provisions and other long-term liabilities

Amounts in US$ ‘000	Asset retirement obligation	Deferred Income	Other	Total
At January 1, 2018	38,075	1,452	6,757	46,284
Addition to provision	462	-	1,039	1,501
Recovery of abandonment costs and other	(4,817)	-	(1,099)	(5,916)
Acquisitions	9,738	-	-	9,738
Exchange difference	1,823	-	(46)	1,777
Foreign currency translation	(1,648)	-	-	(1,648)
Amortization	-	(1,005)	-	(1,005)
Unwinding of discount	3,250	-	173	3,423
Unused amounts reversed	-	-	(2,093)	(2,093)
Amounts used during the year	(750)	-	(124)	(874)
Liabilities associated with assets held for sale	(5,816)	-	(2,794)	(8,610)
At December 31, 2018	40,317	447	1,813	42,577
Addition to provision	13,299	2,267	1,867	17,433
Exchange difference	375	(18)	(48)	309
Foreign currency translation	(334)	-	-	(334)
Amortization	-	(429)	-	(429)
Unwinding of discount	3,573	-	77	3,650
Amounts used during the year	(1,117)	-	(27)	(1,144)
At December 31, 2019	56,113	2,267	3,682	62,062

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 and government grants relating to the purchase of property, plant and equipment in Colombia. The amortization is in line with the related assets.

61 

Note

30 Trade and other payables

Amounts in US$ '000	2019	2018
V.A.T	6,718	852
Trade payables	83,991	69,142
Payables to LGI (Note 36.1)	15,000	29,509
Customer advance payments	-	6,300
Other short-term advance payments (a)	-	9,000
Staff costs to be paid	13,219	12,049
Royalties to be paid	6,294	6,238
Taxes and other debts to be paid	6,795	4,670
To be paid to co-venturers (Note 34)	4,803	8,449
	136,820	146,209
Classified as follows:
Current	131,345	131,420
Non-current	5,475	14,789

^(a) Advance payment collected in relation with the sale of La Cuerva and Yamu Blocks (see Note 36.2).

The average credit period (expressed as creditor days) during the year ended December 31, 2019 was 94 days (2018: 83 days).

The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value.

Note

31 Share-based payment

The Group has established different stock awards programs and other share-based payment plans to incentivize the Directors, senior management and employees, enabling them to benefit from the increased market capitalization of the Company.

During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs that the Company decides to implement throughout such term. The maximum number of Shares available for issuance under the Plan is 5,000,000 Shares.

62 

Note

31 Share-based payment (continued)

During 2019, the Group approved a plan named Value Creation Plan (“VCP”) oriented to key Management. Main characteristics of the VCP are:

· Awards payables in a variable number of shares which shall not exceed the quantity of 3,024,172 shares.

· Subject to certain market conditions, among others, reaching a stock market price for the Company shares of above US$ 19.42 at vesting date.

· Vesting date: December 31, 2021 and 2022 (50% each year).

VCP has been classified as an equity-settled plan. 20% of this plan was awarded to Directors involved in the performance of the Company.

During 2018, the Group approved a share-based compensation program for approximately 200,000 shares. Main characteristics of the Stock Awards Programs are:

· Employees hired since July 2016 are eligible.

· Exercise price is equal to the nominal value of shares.

· Vesting date was June 30, 2019.

· Each employee could receive up to three salaries (to be pro-rated between the hiring date and the vesting date divided by 3 years) by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should be higher than the share price at the date of grant and obtain the Group minimum production, adjusted EBITDA and reserves target for the year of vesting.

During 2016, the Group approved a share-based compensation program for 1,619,105 shares. Main characteristics of the Stock Awards Programs are:

· All employees are eligible.

· Exercise price is equal to the nominal value of shares.

· Vesting date was June 30, 2019.

· 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 and obtain the Group minimum production, adjusted EBITDA and reserves target for the year of vesting.

63 

Note

31 Share-based payment (continued)

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:

Year of issuance	Awards at the beginning	Awards granted in the year	Awards forfeited	Awards exercised	Awards at year end	Charged to net loss / profit
						2019	2018	2017
2018	200,000	-	(68,670)	(131,330)	-	416	1,662	-
2016	1,582,426	-	(228,909)	(1,353,517)	-	50	866	865
2014	-	-	-	-	-	-	-	838
Subtotal	1,782,426	-	(297,579)	(1,484,847)	-	466	2,528	1,703
Shares granted to Non-Executive Directors	-	29,220	-	(29,220)	-	500	450	454
VCP 2019	-	378,053	-	-	378,053	951	-	-
Executive Directors Bonus	104,439	52,058	-	-	156,497	800	600	-
VCP 2016 (a)	2,976,781	-	-	(1,488,391)	1,488,390	-	1,868	1,868
Stock awards for service contracts	-	-	-	-	-	-	-	50
	4,863,646	459,331	(297,579)	(3,002,458)	2,022,940	2,717	5,446	4,075

^(a) The awards at year end were issued in January 2020, as set up in the plan.

The awards that are forfeited correspond to employees that had left the Group before vesting date.

In November 2019, the Group approved a share-based compensation program for approximately 800,000 shares. Main characteristics of the Stock Awards Programs are:

· Grant Date: January 1, 2020 for existing employees or hiring date for new employees

· Employees not included in the VCP and new hiring are eligible.

· Exercise price is equal to the nominal value of shares.

· Vesting date: January 2, 2023.

· Each employee could receive between three and six salaries (to be pro-rated between the hiring date and the vesting date for new hiring) by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should be higher than the share price at the date of grant and obtain the Group minimum production, adjusted EBITDA and reserves target for the year of vesting.

As the abovementioned program was granted in 2020, it has no impact on these Consolidated Financial Statements.

64 

Note

32 Interests in Joint operations

The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Chile, Brazil, Argentina, Peru and Ecuador.

GeoPark is the operator in the Llanos 34, Llanos 32, Llanos 86, Llanos 87 and Llanos 104 Blocks in Colombia, in the Flamenco, Campanario and Isla Norte Blocks in Chile, in the POT-T-747 and REC-T-128 Blocks in Brazil, in the Morona Block in Peru, and in the Espejo Block in Ecuador. Additionally, GeoPark used to be the operator in the CN-V Block in Argentina until October 2018.

The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been recognized in the Consolidated Statement of Financial Position and Statement of Income:

Subsidiary / Joint operation	Interest	PP&E	Other Assets	Total Assets	Total Liabilities	Net Assets/ (Liabilities)	Revenue	Operating profit (loss)
2019
Colombia S.A.S.
Llanos 34 Block	45%	208,156	3,128	211,284	(6,267)	205,017	513,378	398,953
Llanos 32 Block	12.5%	1,136	-	1,136	(519)	617	6,053	2,791
Llanos 86 Block	50%	21	-	21	-	21	-	-
Llanos 87 Block	50%	40	-	40	-	40	-	-
Llanos 104 Block	50%	26	-	26	-	26	-	-
GeoPark TdF S.p.A.
Flamenco Block	50%	4,623	-	4,623	(1,382)	3,241	-	(313)
Campanario Block	50%	16,445	-	16,445	(331)	16,114	-	(156)
Isla Norte Block	60%	8,896	-	8,896	(101)	8,795	-	(189)
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field	10%	18,537	18,066	36,603	(15,980)	20,623	22,376	9,263
POT-T-747	70%	-	-	-	-	-	-	(1,516)
REC-T-128	70%	3,886	919	4,805	(143)	4,662	674	57
POT-T-785	70%	125	-	125	-	125	-	-
GeoPark Argentina S.A.U.
CN-V Block	50%	-	274	274	(237)	37	-	(15,451)
Puelen Block	18%	-	47	47	(41)	6	-	(1.959)
Sierra del Nevado Block	18%	-	63	63	(79)	(16)	-	(1,705)
GeoPark Perú S.A.C.
Morona	75%	8,921	6,862	15,783	(10,161)	5,622	-	(4,976)
GeoPark Perú S.A.C. - Sucursal Ecuador
Espejo	50%	199	321	520	(610)	(90)	-	(272)
Perico	50%	304	61	365	(541)	(176)	-	(176)

65 

Note

32 Interests in Joint operations (continued)

Subsidiary / Joint operation	Interest	PP&E	Other Assets	Total Assets	Total Liabilities	Net Assets/ (Liabilities)	Revenue	Operating profit (loss)
2018
Colombia SAS
Llanos 34 Block	45%	174,895	3,133	178,028	(2,296)	175,732	469,404	347,772
Llanos 32 Block	12.5%	2,011	-	2,011	(449)	1,562	5,764	623
GeoPark Magallanes Ltda.
Tranquilo Block	50%	-	55	55	(428)	(373)	-	(46)
GeoPark TdF S.A.
Flamenco Block	50%	4,803	-	4,803	(1,173)	3,630	263	(5,647)
Campanario Block	50%	16,477	-	16,477	(278)	16,199	40	(1,008)
Isla Norte Block	60%	8,920	-	8,920	(72)	8,848	7	(778)
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field	10%	25,741	6,364	32,105	(839)	31,266	30,053	17,963
POT-T-747	70%	202	-	202	-	202	-	-
REC-T-128	70%	1,398	-	1,398	(648)	750	-	-
GeoPark Argentina Limited – Argentinean Branch
CN-V Block	50%	8,577	328	8,905	(577)	8,328	-	(922)
Puelen Block	18%	1,881	13	1,894	(246)	1,648	-	(159)
Sierra del Nevado Block	18%	995	10	1,005	(91)	914	-	(134)
GeoPark Perú S.A.C.
Morona	75%	6,446	-	6,446	(7,016)	(570)	-	-

Subsidiary / Joint operation	Interest	PP&E	Other Assets	Total Assets	Total Liabilities	Net Assets/ (Liabilities)	Revenue	Operating profit (loss)
2017
Colombia SAS
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)
Yamu/Carupana Block	89.5%	4,741	1	4,742	(2,993)	1,749	3,072	(2,721)
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)
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)

Capital commitments are disclosed in Note 33.2.

66 

Note

33 Commitments

33.1 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%. The Colombian National Hydrocarbons Agency (“ANH”) also has an additional economic right equivalent to 1% of production, net of royalties.

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:

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 October 25, 2011. These payments involve an overriding royalty equal to an estimated 4% carried interest on the part of the vendor. As at the balance sheet date and based on preliminary internal estimates of additions of 2P reserves since acquisition, the Group’s best estimate of the total commitment over the remaining life of the concession is in a range between US$ 200,000,000 and US$ 210,000,000. During 2019, the Group has accrued US$ 24,700,000 (US$ 20,551,000 in 2018 and US$ 11,369,000 in 2017) and paid US$ 18,200,000 (US$ 19,128,000 in 2018 and US$ 9,981,000 in 2017).

67 

Note

33 Commitments (continued)

33.1 Royalty commitments (continued)

In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties are calculated at 5% of crude oil production and 3% of gas production. In the Flamenco Block, Campanario Block and Isla Norte Block, royalties are calculated at 5% of gas and oil production.

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% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Manati Block, royalties are calculated at 7.5% of gas production.

In Argentina, crude oil and gas production accrues royalties payable to the Provinces of Mendoza and Neuquen equivalent to 15% on estimated value at well head of those products. This value is equivalent to final sales price less transport, storage and treatment costs.

33.2 Capital commitments

33.2.1 Colombia

The VIM 3 Block minimum investment program consists of 125 km of 3D seismic, seismic reprocessing and drilling one exploratory well, with a total estimated investment of US$ 22,290,800 during the exploratory period ending November 12, 2019. Since 2018, GeoPark has requested ANH to terminate the E&P Contract due to environmental restrictions in the block. These restrictions became apparent once the National Authority of Environmental Licenses (ANLA) issued the environmental license. As of the date of these consolidated financial statements, GeoPark’s termination request is under review.

The Llanos 87 Block (50% working interest) has committed to reprocess 3D seismic and to drill four exploratory wells, which amount to US$ 12,290,000 at GeoPark’s working interest, before November 24, 2022.

The Llanos 86, Llanos 104, Llanos 123 and Llanos 124 Blocks are in Preliminary Phase as of the date of these consolidated financial statements. During this Preliminary Phase, GeoPark must request the Ministry of Interior for the certificate that indicates presence or no presence of indigenous communities and develop previous consultation, if applicable. Only when this process has been completed and the corresponding regulatory approvals has been obtained, the blocks will enter into Phase 1, where the exploratory commitments are mandatory. The investment commitments for the blocks over three-years term of Phase 1 would be the following:

· Llanos 86 Block: 3D seismic, 2D seismic reprocessing and 1 exploratory well (US$ 8,860,000)

· Llanos 104 Block: 3D seismic, 2D seismic reprocessing and 1 exploratory well (US$ 7,873,000)

· Llanos 123 Block: 3D seismic reprocessing, geochemistry and 2 exploratory wells (US$ 6,334,000)

· Llanos 124 Block: 3D seismic, 3D seismic reprocessing, geochemistry and 3 exploratory wells (US$ 9,375,000)

68 

Note

33 Commitments (continued)

33.2 Capital commitments (continued)

33.2.2 Chile

The remaining investment commitment to be assumed 100% by GeoPark for the second exploratory phase in the Flamenco, Campanario and Isla Norte Blocks are up to:

· Flamenco Block: 1 exploratory well before November 7, 2020 (US$ 2,100,000)

· Campanario Block: 3 exploratory wells before January 11, 2020 (US$ 4,758,000)

· Isla Norte Block: 2 exploratory wells before November 7, 2020 (US$ 2,855,000)

As of December 31, 2019, the Group has established guarantees for its total commitments.

The drilling campaign relating to the committed wells detailed above has already started in February 2020.

33.2.3 Brazil

The future investment commitments assumed by GeoPark are up to:

· REC-T-128 Block: 3D seismic reprocessing and interpretation before March 26, 2020 (US$ 1,300,000).

· POT-T-785 Block: 3D seismic and electromagnetic survey before January 29, 2023 (US$ 90,000).

· REC-T-58 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000).

· REC-T-67 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000).

· REC-T-77 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000).

· POT-T-834 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 140,000).

33.2.4 Argentina

The investment commitment in the Los Parlamentos Block (50% working interest) for the first exploratory period, ending on October 30, 2021, which includes 2 exploratory wells and additional 3D seismic, amounts to US$ 6,000,000, at GeoPark’s working interest.

33.2.5 Ecuador

The investment commitments assumed by GeoPark, at its 50% working interest, in the Espejo and Perico Blocks during the first exploratory period are up to:

· Espejo Block: 3D seismic and 4 exploratory wells before June 17, 2023 (US$ 17,648,000).

· Perico Block: 4 exploratory wells before June 16, 2023 (US$ 12,109,000).

33.3 Operating lease commitments – Group company as lessee

The Group leases offices and various plant and machinery under non-cancellable operating lease agreements. The lease terms are between 1 and 7 years, and most of lease agreements are renewable at the end of the lease period at market rate.

69 

Note

33 Commitments (continued)

33.3 Operating lease commitments – Group company as lessee (continued)

From January 1, 2019, the Group has recognized right-of-use assets for these leases, except for short-term and low-value leases. See Note 2.1.1.

Until December 31, 2018, operating leases related to offices, facilities, machinery and equipment were charged to the Consolidated Statement of Income for US$ 12,485,000 in 2018 and US$ 46,195,000 in 2017, and were capitalized as Property, plant and equipment for US$ 38,229,000 in 2018 and US$ 34,160,000 in 2017.

The future aggregate minimum lease payments under non-cancellable operating leases were as follows:

Amounts in US$ ’000	2018	2017
Falling due within 1 year	47,450	32,180
Falling due within 1 – 3 years	18,032	5,777
Falling due within 3 – 5 years	2,500	2,793
Falling due over 5 years	1,956	-
Total minimum lease payments	69,938	40,750

Note

34 Related parties

Controlling interest

The main shareholders of GeoPark Limited, a company registered in Bermuda, as of December 31, 2019, are:

Shareholder	Common shares	Percentage of outstanding common shares
James F. Park (a)	8,278,251	13.99%
Gerald E. O’Shaughnessy (b)	7,309,002	12.35%
Compass Group LLC (c)	4,733,824	8.00%
Renaissance Technologies Holdings Corporation (d)	4,509,096	7.62%
Manchester Financial Group, LP	4,246,296	7.18%
Juan Cristóbal Pavez (e)	2,974,960	5.03%
Other shareholders	27,116,155	45.83%
	59,167,584	100.00%

^(a) Held by Energy Holdings, LLC, which is controlled by James F. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 7, 2020.

^(b) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, The Globe Resources Group, Inc., and other investment vehicles. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. O´Shaughnessy’s most recent Schedule 13G filed with the SEC on February 6, 2020.

^(c) The information set forth above and listed in the table is based solely on the disclosure set forth in Compass Group LLC’s most recent Schedule 13G filed with the SEC on February 12, 2020.

^(d) Beneficially owned by Renaissance Technologies Holdings Corporation and Renaissance Technologies LLC (jointly “Renaissance”). The in-formation set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13G filed with the SEC on February 13, 2020.

^(e) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 97,156 common shares held by him personally. This information is based solely on the disclosure set forth in Mr. Pavez’s most recent Schedule 13G filed with the SEC on February 5, 2020.

70 

Note

34 Related parties (continued)

Balances outstanding and transactions with related parties

Account (Amounts in ´000)	Transaction in the year	Balances at year end	Related Party	Relationship
2019
To be recovered from co-venturers	-	1,035	Joint Operations	Joint Operations
To be paid to co-venturers	-	(4,803)	Joint Operations	Joint Operations
Geological and geophysical expenses	160	-	Carlos Gulisano	Non-Executive Director (a)
Administrative expenses	581	-	Pedro E. Aylwin	Executive Director (b)
2018
To be recovered from co-venturers	-	1,819	Joint Operations	Joint Operations
To be paid to co-venturers	-	(8,449)	Joint Operations	Joint Operations
Financial results	1,606	-	LGI	Partner
Geological and geophysical expenses	170	-	Carlos Gulisano	Non-Executive Director (a)
Administrative expenses	547	-	Pedro E. Aylwin	Executive Director (b)
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 E. Aylwin	Executive Director (b)

^(a) Corresponding to consultancy services.

^(b) Corresponding to wages and salaries for US$ 390,000 (US$ 417,000 in 2018 and US$ 271,000 in 2017) and bonus for US$ 191,000 (US$ 130,000 in 2018 and US$ 140,000 in 2017).

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.

71 

Note

35 Auditors fees

Amounts in US$ '000	2019	2018	2017
Audit fees	763	797	726
Audit related fees	510	-	137
Tax services fees	165	209	212
Non-audit services fees	5	-	39
Fees paid to auditors	1,443	1,006	1,114

Non-audit services fees relate to consultancy and other services.

Note

36 Business transactions

36.1 General

Non-controlling interest in Colombia and Chile’s business from LG International

On November 28, 2018, GeoPark executed an agreement to acquire the LG International Corporation (“LGI”) interest in GeoPark’s Colombian and Chilean operations and subsidiaries.

The acquisition price included a fixed payment of US$ 81,000,000 paid at closing, plus two equal installments of US$ 15,000,000 each, to be paid in June 2019 and June 2020. Additionally, three contingent payments of US$ 5,000,000 each could be payable over the next three years, subject to certain production thresholds being exceeded. As of the date of these Consolidated Financial Statements, the first installment of US$ 15,000,000 was already paid, and the production threshold corresponding to the first contingent payment of US$ 5,000,000 was not exceeded.

Through this transaction, GeoPark acquired the shares that used to be held by LGI representing 20% equity interest in GeoPark Colombia Coöperatie U.A., 20% equity interest in GeoPark Chile S.A. and 14% equity interest in GeoPark TdF S.A. In addition to that, the outstanding amount corresponding to advanced cash call payments granted in the past by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks were considered as part of the transaction.

The transaction mentioned above has been accounted for as a transaction with non-controlling interest in accordance with IFRS 10. Consequently, the difference between the amount by which the non-controlling interest was stated and the fair value of the consideration paid was recognized directly in Equity and attributed to the owners of the Company.

The following table summarizes the result of this transaction:

Amounts in US$ '000	Total
Cash	81,000
Additional installments to be paid	29,427
Total consideration	110,427
Equity attributable to non-controlling interest	64,245
Trade and other payables	32,786
Total book value of the transaction	97,031
Result of the transaction recognized in Equity	13,396

72 

Note

36 Business transactions (continued)

36.2 Colombia

La Cuerva and Yamu Blocks

On November 2, 2018, GeoPark executed a purchase and sale agreement to sell its 100% working interest in the La Cuerva and Yamu Blocks, in Colombia. The total consideration is US$ 18,000,000, less a working capital adjustment of US$ 1,934,000, plus a contingent payment of US$ 2,000,000. Closing of the transaction took place in July 2019, after the corresponding customary regulatory approvals.

As a consequence of this transaction, GeoPark collected an advance payment of US$ 9,000,000 in November 2018 and the final payment (which includes the working capital adjustment) of US$ 7,066,000 in July 2019.

The following table summarizes the assets and liabilities related to these blocks and the result of the transaction at its closing date:

Amounts in US$ '000	Total
Advance payment	9,000
Final payment (including working capital adjustment)	7,066
Total consideration	16,066
Assets held for sale	23,211
Liabilities associated with assets held for sale	(9,447)
Other net current assets	2,416
Total identifiable net assets	16,180
Result of the transaction recognized in the Condensed Consolidated Statement of Income	(114)

Llanos 123 and Llanos 124 Blocks

On December 20, 2019, GeoPark signed final contracts for the 50% working interest and operationship in the Llanos 123 and Llanos 124 Blocks, in partnership with Hocol (a 100% subsidiary of Ecopetrol). The blocks represent attractive, low-risk, high potential exploration acreage in the Llanos basin in proximity to the Llanos 34 Block, and surrounded by multiple producing oil and gas fields and existing infrastructure. GeoPark assumed commitments to acquire and reprocess existing 3D seismic and to drill five exploration wells for US$ 15,709,000, at GeoPark’s working interest, during the first exploration phase over the next three years.

Llanos 94 Block

In December 2019, GeoPark executed an agreement to acquire a 50% working interest in the Llanos 94 Block, subject to regulatory approval. GeoPark assumed commitments to acquire and reprocess existing 3D seismic and to drill three exploration wells for US$ 10,150,000, at GeoPark’s working interest, during the first exploration phase over the next three years.

73 

Note

36 Business transactions (continued)

36.2 Colombia (continued)

Llanos 86, Llanos 87 and Llanos 104 Blocks

On July 11, 2019, GeoPark signed final contracts for the 50% working interest and operationship in the Llanos 86, Llanos 87 and Llanos 104 Blocks, in partnership with Hocol (a 100% subsidiary of Ecopetrol). The blocks represent significant and attractive, low-risk, high potential exploration acreage in the Llanos basin in proximity to the Llanos 34 Block. GeoPark assumed commitments to register 3D seismic and to drill six exploration wells for US$ 29,023,000, at GeoPark’s working interest, during the first exploration phase over the next three years.

Llanos 32 Block

During the fourth quarter of 2019, GeoPark discovered the Azogue oil field where the Group’s working interest is 25% as per an additional agreement to the Llanos 32 Block Joint Operating Agreement (GeoPark non-operated, 12.5% working interest), by which GeoPark acquired a beneficial interest in a defined area within the block.

35.3 Brazil

REC-T-58, REC-T-67, REC-T-77 and POT-T-834 Blocks

In September 2019, GeoPark was preliminarily awarded the 100% working interest and operationship of the REC-T-58, REC-T-67, REC-T-77 and POT-T-834 Blocks. GeoPark assumed commitments of US$ 1,300,000 during the first exploration period of five years. Final contracts were signed on 14 February 2020.

36.4 Argentina

Aguada Baguales, El Porvenir and Puesto Touquet Blocks

On March 27, 2018, GeoPark acquired a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks, which are located in the Neuquen Basin, for a total consideration of US$ 52,000,000, less a working capital adjustment of US$ 3,150,000. The Group has estimated that there are no any future contingent payments at the acquisition date and as of the date of these consolidated financial statements either.

In accordance with the acquisition method of accounting, the acquisition cost was allocated to the underlying assets acquired and liabilities assumed based primarily upon their estimated fair values at the date of acquisition. An income approach (being the net present value of expected future cash flows) was adopted to determine the fair values of the mineral interest. Estimates of expected future cash flows reflect estimates of projected future revenues, production costs and capital expenditures based on our business model.

74 

Note

36 Business transactions (continued)

36.4 Argentina (continued)

Aguada Baguales, El Porvenir and Puesto Touquet Blocks (continued)

The following table summarizes the combined consideration paid for the acquired blocks and the final allocation of fair value of the assets acquired and liabilities assumed for the abovementioned transaction:

Amounts in US$ '000	Total
Cash (a)	48,850
Total consideration	48,850
Property, plant and equipment (including mineral interest)	54,929
Inventories	3,659
Provision for other long-term liabilities	(9,738)
Total identifiable net assets	48,850

^(a) In December 2017, GeoPark granted a security deposit of US$ 15,600,000. In March 2018, the Group completed the total consideration with an additional payment of US$ 36,400,000. In September 2018, Geo-Park collected a working capital adjustment of US$ 3,150,000.

In accordance with disclosure requirements for business combinations, the Group has calculated its consolidated revenue and profit, considering as if the mentioned acquisition had occurred at the beginning of the reporting period.

The following table summarizes both results:

Amounts in US$ '000	2018
Revenue	612,401
Profit for the period	102,873

The revenue included in the 2018 consolidated statement of comprehensive income since acquisition date contributed by the acquired business is US$ 35,879,000. The acquired business has also contributed profit of US$ 124,000 over the same period.

As a consequence of this transaction, the Group considers that there is sufficient evidence of future taxable profits to offset tax losses and recognize a deferred tax asset for US$ 1,346,000 in respect of tax losses from previous years which can be utilised against future taxable profit.

Los Parlamentos Block

In June 2018, GeoPark acquired a 50% working interest in the Los Parlamentos exploratory block in partnership with YPF S.A. (YPF), the largest oil and gas producer in Argentina. In accordance with the partnership agreement, YPF assumed the operationship of the block and GeoPark assumed a commitment to fund its 50% working interest of one exploratory well and additional 3D seismic, which amounts to US$ 6,000,000 at GeoPark’s working interest, over the next three years.

75 

Note

36 Business transactions (continued)

36.5 Ecuador

Espejo and Perico Blocks

On May 22, 2019, GeoPark signed final participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico (GeoPark non-operated, 50% working interest) Blocks in Ecuador, which were awarded to GeoPark in the Intracampos Bid Round held in Quito, Ecuador in March 2019. GeoPark assumed a commitment of carrying out 3D seismic in the Espejo Block and drilling four exploration wells in each block, which amounts to US$ 29,757,000 at GeoPark’s working interest, over the next four years.

Note

37 Impairment test on Property, plant and equipment

The Management of the Group considers as Cash Generating Unit (CGU) each of the blocks or group of 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 the impairment test.

As a result of the oil price crisis which started in the second half of 2014, the Group recognized an impairment loss of US$ 149,574,000 in 2015 after evaluating the recoverability of its fixed assets affected by oil price drop. In the following years the impairment tests were reviewed. Based on the analysis performed, the Group concluded that the impairment recognized should not be reversed in the current year.

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 price curves available in the market, provided by international advisory companies, weighted through internal estimations in accordance with price curves used by D&M;

- Three oil price scenarios were projected and weighted in order to minimize misleading estimations: 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 market 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 the 2020 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).

76 

Note

37 Impairment test on Property, plant and equipment (continued)

Table Oil price scenarios ^(a):

	Amounts in US$ per Bbl.
Year	Low price (15%)	Middle price (60%)	High price (25%)	Weighted market price used for the impairment test
2020	66.0	66.0	66.0	66.0
2021	51.8	69.0	75.9	68.1
2022	53.7	71.6	78.8	70.7
Over 2023	54.8	73.1	80.4	72.2

^(a) The percentages indicated between brackets represent the Group estimation regarding each price scenario.

As a consequence of the evaluation, the following amounts of impairment loss were (recognized) reversed:

Amounts in US$ '000	2019	2018	2017
Colombia (a)	-	11,531	-
Chile (b)	-	(6,549)	-
Argentina (c)	(7,559)	-	-
Total	(7,559)	4,982	-

^(a) Reversal of impairment losses due to increases in estimated market prices and improvements in cost structure, and also the known fair value less costs of disposal of the La Cuerva and Yamu Blocks (see Note 36.2).

^(b) Recognition of impairment loss due to the termination of the sales agreement for the TdF’s blocks, with no renovation in place as of the date of these consolidated financial statements.

^(c) Recognition of impairment loss for the total amount capitalized in the CN-V Block due to a negative revision of reserves at year-end.

When evaluating Aguada Baguales and El Porvenir Blocks, although no impairment loss was recognized, if the weighted market price used for the impairment test had been 5% lower in each of the future years, with all other variables held constant, the Group would have had to recognize an impairment against the carrying amount of property, plant and equipment of US$ 3,974,000. If the risk associated to reserves applied to the cash flow projections of this CGU had been 5% higher than management’s estimates, the Group would have had to recognize an impairment against property, plant and equipment of US$ 3,254,000. In the prior year, there were no reasonably possible changes in any of the key assumptions that would have resulted in an impairment loss in this CGU.

77 

Note

38 Subsequent events

38.1 Business transactions

Acquisition of Amerisur Resources Plc.

On January 16, 2020, GeoPark acquired the 100% share capital of Amerisur Resources Plc, a company listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. The principal activities of Amerisur Resources Plc and its subsidiaries (“Amerisur”) are exploration, development and production for oil and gas reserves in Latin America. Amerisur owns thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo basin and one non-operated block in the Llanos basin) and an export oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“OBA”).

GeoPark paid a cash consideration of GBP 241,682,496 (equivalent to US$ 314,163,077) at closing date.

Before closing the transaction, the Group decided to manage its exposure to British Pound Sterling (“GBP”) fluctuation with respect to the abovementioned cash consideration. Consequently, on November 25, 2019, GeoPark entered into a “Deal Contingent Forward” (DCF) with a UK Bank, in order to anticipate any currency fluctuation in respect to the cash consideration payable in GBP. This forward contract used was accounted for as a cash flow hedge as of December 31, 2019 and therefore all changes in its fair value were recognized in Other Reserve within Equity.

In accordance with the acquisition method of accounting, the acquisition cost will be allocated to the underlying assets acquired and liabilities assumed based primarily upon their estimated fair values at the date of acquisition. An income approach (being the net present value of expected future cash flows) will be adopted to determine the fair values of the mineral interest. Estimates of expected future cash flows reflect estimates of projected future revenues, production costs and capital expenditures based on our business model. The excess of acquisition cost, if any, over the net identifiable assets acquired represents goodwill.

The following table summarises the combined consideration paid for the acquired blocks, and a preliminary allocation of fair value of the assets acquired and liabilities assumed for these transactions:

Amounts in US$ '000	Total
Cash	314,163
Total consideration	314,163
Cash and cash equivalents	36,633
Trade and other receivables	47,238
Property, plant and equipment (including mineral interest)	289,532
Other assets	25,585
Provision for other long-term liabilities	(6,640)
Deferred income tax liability	(19,111)
Lease liabilities	(18,821)
Trade and other payables	(40,253)
Total identifiable net assets	314,163

The purchase price allocation detailed above is preliminary, since the valuation process is ongoing. This process will be completed during 2020. Estimated acquisition related transaction costs amounted to US$ 5,758,000.

78 

Note

38 Subsequent events (continued)

38.2 Borrowings

Notes issuance

On January 17, 2020, the Company successfully placed US$ 350,000,000 Notes which were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and outside the United States to non U.S. persons in accordance with Regulation S under the Securities Act. The Notes will be fully and unconditionally guaranteed jointly and severally by GeoPark Chile S.p.A. and GeoPark Colombia S.L.U..

The Notes were priced at 99.285% and carry a coupon of 5.50% per annum (yield 5.625% per annum). Final maturity of the Notes will be January 17, 2027. The indenture governing the Notes due 2027 includes incurrence test covenants that provides among other things, that, the Net Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 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.

The net proceeds from the Notes were used by the Company (i) to make an intercompany loan to its wholly-owned subsidiary, GeoPark Colombia S.A.S., providing it with sufficient funds to pay the total consideration for the acquisition of Amerisur (see Note 38.1) and to pay any related fees and expenses, and (ii) for general corporate purposes.

38.3 Equity

Buyback Program

On February 10, 2020, the Company approved a program to repurchase up to 10% of its shares outstanding or approximately 5,930,000 shares. The repurchase program begun on February 11, 2020 and will expire on December 31, 2020. These transactions have no impact on the Group’s results.

Stock distribution

On February 10, 2020, the Company announced that its Board of Directors declared a special stock distribution of 0.004 shares per share to be paid on March 11, 2020 to the shareholders of record at the close of business on February 25, 2020.

79 

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39 Supplemental information on oil and gas activities (unaudited)

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

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

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as of December 31, 2019, 2018 and 2017. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Total
Year ended December 31, 2019
Acquisition of properties
Proved	-	-	-	-	-	-
Unproved	-	-	-	-	-	-
Total property acquisition	-	-	-	-	-	-
Exploration	22,008	8,483	5,219	4,116	-	39,826
Development	68,818	2,611	143	25,109	14,408	111,089
Total costs incurred	90,826	11,094	5,362	29,225	14,408	150,915
Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Total
Year ended December 31, 2018
Acquisition of properties
Proved	-	-	-	54,541	-	54,541
Unproved	-	-	-	-	-	-
Total property acquisition	-	-	-	54,541	-	54,541
Exploration	34,242	6,221	3,217	9,383	1,269	54,332
Development	65,174	3,033	(2,220)	1,836	8,385	76,208
Total costs incurred	99,416	9,254	997	11,219	9,654	130,540
Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Total
Year ended December 31, 2017
Acquisition of properties
Proved	-	-	-	-	-	-
Unproved	-	-	-	-	-	-
Total property acquisition	-	-	-	-	-	-
Exploration	37,017	3,283	5,207	8,080	743	54,330
Development	49,268	10,231	1,210	167	14,074	74,950
Total costs incurred	86,285	13,514	6,417	8,247	14,817	129,280

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39 Supplemental information on oil and gas activities (unaudited – continued)

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

The following table presents the capitalized costs as at December 31, 2019, 2018 and 2017, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

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

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

^(b) Do not include Peru capitalized costs.

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Total
At December 31, 2018
Proved properties (a)
Equipment, camps and other facilities	83,023	81,459	5,154	2,458	172,094
Mineral interest and wells	189,514	400,338	63,574	64,084	717,510
Other uncompleted projects (b)	24,061	12,233	-	1,836	38,130
Unproved properties	1,676	41,162	7,073	10,081	59,992
Gross capitalized costs	298,274	535,192	75,801	78,459	987,726
Accumulated depreciation	(122,479)	(281,062)	(43,158)	(16,363)	(463,062)
Total net capitalized costs	175,795	254,130	32,643	62,096	524,664

^(a) Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile for US$ 6,549,000 and impairment loss reversal in Colombia for US$ 11,531,000.

^(b) Do not include Peru capitalized costs.

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

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

^(b) Do not include Peru capitalized costs.

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39 Supplemental information on oil and gas activities (unaudited – continued)

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

The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2019, 2018 and 2017. Income tax for the years presented was calculated utilizing the statutory tax rates.

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2019
Revenue	538,917	32,336	23,049	34,605	628,907
Production costs, excluding depreciation
Operating costs	(60,545)	(18,608)	(4,098)	(21,137)	(104,388)
Royalties	(56,399)	(1,181)	(1,855)	(5,141)	(64,576)
Total production costs	(116,944)	(19,789)	(5,953)	(26,278)	(168,964)
Exploration expenses (a)	(10,921)	(126)	(6,152)	(13,947)	(31,146)
Accretion expense (b)	(813)	(1,283)	(832)	(722)	(3,650)
Impairment loss for non-financial assets	-	-	-	(7,559)	(7,559)
Depreciation, depletion and amortization	(44,906)	(34,344)	(6,200)	(14,534)	(99,984)
Results of operations before income tax	365,333	(23,206)	3,912	(28,435)	317,604
Income tax benefit (expense)	(120,585)	3,481	(1,330)	8,530	(109,904)
Results of oil and gas operations	244,748	(19,725)	2,582	(19,905)	207,700

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2018
Revenue	497,870	37,359	30,053	35,879	601,161
Production costs, excluding depreciation
Operating costs	(55,823)	(20,426)	(5,965)	(20,210)	(102,424)
Royalties	(62,710)	(1,473)	(2,820)	(4,833)	(71,836)
Total production costs	(118,533)	(21,899)	(8,785)	(25,043)	(174,260)
Exploration expenses (a)	(23,953)	(6,855)	(2,846)	(2,277)	(35,931)
Accretion expense (b)	(892)	(1,105)	(918)	(508)	(3,423)
Impairment (loss) reversal for non-financial assets	11,531	(6,549)	-	-	4,982
Depreciation, depletion and amortization	(41,850)	(27,298)	(10,278)	(10,662)	(90,088)
Results of operations before income tax	324,173	(26,347)	7,226	(2,611)	302,441
Income tax benefit (expense)	(119,944)	3,952	(2,457)	783	(117,666)
Results of oil and gas operations	204,229	(22,395)	4,769	(1,828)	184,775

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39 Supplemental information on oil and gas activities (unaudited – continued)

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

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Total
Year ended December 31, 2017
Revenue	263,076	32,738	34,238	70	330,122
Production costs, excluding depreciation
Operating costs	(42,677)	(19,685)	(7,603)	(325)	(70,290)
Royalties	(24,236)	(1,314)	(3,134)	(13)	(28,697)
Total production costs	(66,913)	(20,999)	(10,737)	(338)	(98,987)
Exploration expenses (a)	(3,856)	(1,404)	(3,985)	(707)	(9,952)
Accretion expense (b)	(855)	(994)	(930)	-	(2,779)
Depreciation, depletion and amortization	(38,721)	(22,705)	(10,659)	(8)	(72,093)
Results of operations before income tax	152,731	(13,364)	7,927	(983)	146,311
Income tax benefit (expense)	(61,161)	2,005	(2,695)	344	(61,507)
Results of oil and gas operations	91,570	(11,359)	5,232	(639)	84,804

^(a) Do not include Peru costs.

^(b) Represents accretion of ARO and other environmental liabilities.

Table 4 - Reserve quantity information

Estimated oil and gas reserves

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

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

The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, 2019, 2018 and 2017 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).

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39 Supplemental information on oil and gas activities (unaudited – continued)

Table 4 - Reserve quantity information (continued)

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

The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2019, 2018 and 2017 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	As of December 31, 2019		As of December 31, 2018		As of December 31, 2017
	Oil and condensate (Mbbl)	Natural gas (MMcf)	Oil and condensate (Mbbl)	Natural gas  (MMcf)	Oil and condensate (Mbbl)	Natural gas  (MMcf)
Net proved developed
Colombia (a)	39,397.0	2,319.0	32,326.0	1,763.0	21,101.0	-
Chile (b)	898.0	14,406.0	696.0	11,944.0	720.0	8,688.0
Brazil (c)	48.0	14,872.0	55.0	17,339.0	76.0	23,821.0
Argentina (d)	1,658.0	5,785.0	2,058.0	6,207.0	-	-
Peru (e)	-	-	-	-	9,502.0	-
Total consolidated	42,001.0	37,382.0	35,135.0	37,253	31,399.0	32,509.0
Net proved undeveloped
Colombia (f)	51,212.0	-	42,449.0	359.0	44,398.0	-
Chile (g)	2,809.0	6,413.0	2,622.0	8,823.0	3,423.0	11,329.0
Argentina (h)	1,370.0	450.0	1,440.0	3,174.0	-	-
Peru (e)	19,210.0	-	18,460.0	-	9,215.0	-
Total consolidated	74,601.0	6,863.0	64,971.0	12,356.0	57,036.0	11,329.0
Total proved reserves	116,602.0	44,245.0	100,106.0	49,609.0	88,435.0	43,838.0

^(a) Llanos 34 Block and Llanos 32 Block account for 93% and 7% (Llanos 34 Block, La Cuerva Block, Yamu Block and Llanos 32 Block account for 96%, 1.5%, 1.5% and 1% in 2018, and Llanos 34 Block, La Cuerva Block and Yamu Block account for 98%, 1% and 1% in 2017) of the proved developed reserves, respectively.

^(b) Fell Block accounts for 100% (Fell Block accounts for 100% in 2018, and Fell Block and Flamenco Block account for 98% and 2% in 2017) of the proved developed reserves, respectively.

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

^(d) Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 17%, 64% and 19% (Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 48%, 33% and 19% in 2018) of the proved developed reserves, respectively.

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

^(f) Llanos 34 Block and Llanos 32 Block account 96% and 4% (Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and 1 in 2018, and Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and 1% in 2017) of the proved undeveloped reserves, respectively.

^(g) Fell Block accounts for 100% (Fell Block accounts for 100% in 2018, and Fell Block and Flamenco Block account for 97% and 3% in 2017) of the proved undeveloped reserves, respectively.

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

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39 Supplemental information on oil and gas activities (unaudited – continued)

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

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

Thousands of barrels	Colombia	Chile	Brazil	Argentina	Peru	Total
Reserves as of December 31, 2016	37,340.0	6,599.0	72.0	-	18,621.0	62,632.0
Increase (decrease) attributable to:
Revisions (a)	6,315.0	(2,109.0)	19.0	-	96.0	4,321.0
Extensions and discoveries (b)	29,047.0	-	-	-	-	29,047.0
Production	(7,203.0)	(347.0)	(15.0)	-	-	(7,565.0)
Reserves as of December 31, 2017	65,499.0	4,143.0	76.0	-	18,717.0	88,435.0
Increase (decrease) attributable to:
Revisions (c)	9,826.0	(586.0)	(6.0)	-	(257.0)	8,977.0
Extensions and discoveries (d)	8,839.0	41.0	-	-	-	8,880.0
Purchase of Minerals in place (e)	-	-	-	3,968.0	-	3,968.0
Production	(9,389.0)	(280.0)	(15.0)	(470.0)	-	(10,154.0)
Reserves as of December 31, 2018	74,775.0	3,318.0	55.0	3,498.0	18,460.0	100,106.0
Increase (decrease) attributable to:
Revisions (f)	18,341.0	541.0	4.0	95.0	750.0	19,731.0
Extensions and discoveries (g)	8,071.0	36.0	-	-	-	8,107.0
Production	(10,578)	(188)	(11)	(565)	-	(11,342)
Reserves as of December 31, 2019	90,609.0	3,707.0	48.0	3,028.0	19,210.0	116,602.0

^(a) For the year ended December 31, 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.

^(b) 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 extensions in the Llanos 34 Block.

^(c) For the year ended December 31, 2018, the Group’s oil and condensate proved reserves were revised upward by 9.0 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 15.4 mmbbl.

- The impact of higher average oil prices resulting in a 0.7 mmbbl, 1.0 mmbbl and 0.3 mmbbl increase in reserves from the blocks in Colombia, Peru 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 Max, Tua, Chachalaca Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a 6.3 mmbbl decrease. Also, lower than expected performance from existing wells in Fell Block, resulted in a 0.8 mmbbl decrease. Finally, revisions in Peru resulted in a 1.3 mmbbl decrease.

^(d) In Colombia, the extensions and discoveries are primary due to the Tigana and Jacana fields appraisal wells and the Tigui field discovery in the Llanos 34 Block.

^(e) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir, and Puesto Touquet fields acquisition during 2018. See Note 36.4 for further details.

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

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

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

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

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

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

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

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39 Supplemental information on oil and gas activities (unaudited – continued)

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

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

Millions of cubic feet	Colombia	Chile	Brazil	Argentina	Total
Reserves as of December 31, 2016	-	36,300.0	29,525.0	-	65,825.0
Increase (decrease) attributable to:
Revisions (a)	-	(13,725.0)	59.0	-	(13,666.0)
Extensions and discoveries (b)	-	1,187.0	-	-	1,187.0
Production	-	(3,745.0)	(5,763.0)	-	(9,508.0)
Reserves as of December 31, 2017	-	20,017.0	23,821.0	-	43,838.0
Increase (decrease) attributable to:
Revisions (c)	-	544.0	(679.0)	-	(135.0)
Extensions and discoveries (d)	2,122.0	3,909.0	-	-	6,031.0
Purchase of Minerals in place (e)	-	-	-	10,452.0	10,452.0
Production	-	(3,703.0)	(5,803.0)	(1,071.0)	(10,577.0)
Reserves as of December 31, 2018	2,122.0	20,767.0	17,339.0	9,381.0	49,609.0
Increase (decrease) attributable to:
Revisions (f)	621.0	(167.0)	1,812.0	(1,791.0)	475.0
Extensions and discoveries (g)	295.0	5,386.0	-	-	5,681.0
Production	(719.0)	(5,167.0)	(4,279)	(1,355)	(11,520)
Reserves as of December 31, 2019	2,319.0	20,819.0	14,872.0	6,235.0	44,245.0

^(a) For the year ended December 31, 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.

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

^(c) For the year ended December 31, 2018, the Group’s proved natural gas reserves were revised downwards by 0.1 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 lower than expected performance from existing wells in the Fell Block in Chile (totalling 2.0 billion cubic feet).

- Lower than expected performance from existing wells in BCAM-40 Block, resulting in a decrease of 0.7 billion cubic feet.

- The above was partially offset by higher average prices that resulted in an increase of 2.5 billion cubic feet in the Fell Block in Chile.

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

^(e) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir, and Puesto Touquet fields acquisition during 2018. See Note 36.4 for further details.

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

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

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

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

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

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.

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39 Supplemental information on oil and gas activities (unaudited – continued)

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 2019, 2018 and 2017 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.

87 

Note

39 Supplemental information on oil and gas activities (unaudited – continued)

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

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Total
At December 31, 2019
Future cash inflows	4,323,914	294,202	86,191	187,064	1,255,239	6,146,610
Future production costs	(1,159,621)	(104,688)	(32,608)	(118,797)	(512,607)	(1,928,321)
Future development costs	(276,804)	(35,420)	(2,166)	(49,595)	(278,388)	(642,373)
Future income taxes	(858,700)	(5,594)	(1,409)	(2,251)	(143,416)	(1,011,370)
Undiscounted future net cash flows	2,028,789	148,500	50,008	16,421	320,828	2,564,546
10% annual discount	(715,217)	(44,277)	(6,626)	(5,080)	(199,611)	(970,811)
Standardized measure of discounted future net cash flows	1,313,572	104,223	43,382	11,341	121,217	1,593,735
At December 31, 2018
Future cash inflows	4,059,619	317,437	102,104	277,429	1,352,159	6,108,748
Future production costs	(983,782)	(156,724)	(49,255)	(173,053)	(441,801)	(1,804,615)
Future development costs	(207,630)	(39,360)	(3,752)	(54,400)	(293,468)	(598,610)
Future income taxes	(848,519)	(2,515)	(2,231)	(6,610)	(189,922)	(1,049,797)
Undiscounted future net cash flows	2,019,688	118,838	46,866	43,366	426,968	2,655,726
10% annual discount	(640,625)	(29,008)	(5,317)	(8,499)	(188,435)	(871,884)
Standardized measure of discounted future net cash flows	1,379,063	89,830	41,549	34,867	238,533	1,783,842
At December 31, 2017
Future cash inflows	2,434,954	284,711	157,527	-	1,047,540	3,924,732
Future production costs	(531,751)	(131,788)	(56,311)	-	(466,110)	(1,185,960)
Future development costs	(187,414)	(57,690)	(7,524)	-	(235,920)	(488,548)
Future income taxes	(558,226)	(656)	(10,442)	-	(107,294)	(676,618)
Undiscounted future net cash flows	1,157,563	94,577	83,250	-	238,216	1,573,606
10% annual discount	(343,561)	(19,338)	(13,293)	-	(147,682)	(523,874)
Standardized measure of discounted future net cash flows	814,002	75,239	69,957	-	90,534	1,049,732

88 

Note

39 Supplemental information on oil and gas activities (unaudited – continued)

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

Amounts in US$ '000	Colombia	Chile	Brazil	Argentina	Peru	Total
Present value at December 31, 2016	269,502	35,455	73,516	-	30,929	409,402
Sales of hydrocarbon, net of production costs	(198,631)	(14,251)	(26,979)	-	-	(239,861)
Net changes in sales price and production costs	289,199	26,928	(3,000)	-	69,962	383,089
Changes in estimated future development costs	(124,053)	79,078	8,385	-	(9,725)	(46,315)
Extensions and discoveries less related costs	49,574	-	-	-	-	49,574
Development costs incurred	67,571	7,146	-	-	-	74,717
Revisions of previous quantity estimates	673,622	(69,594)	603	-	1,133	605,764
Purchase of Minerals in place
Net changes in income taxes	(258,842)	6,097	7,976	-	(11,828)	(256,597)
Accretion of discount	46,060	4,380	9,456	-	10,063	69,959
Present value at December 31, 2017	814,002	75,239	69,957	-	90,534	1,049,732
Sales of hydrocarbon, net of production costs	(380,829)	(18,923)	(24,781)	(21,243)	-	(445,776)
Net changes in sales price and production costs	397,064	16,093	(15,170)	-	191,288	589,275
Changes in estimated future development costs	(18,632)	413	(1,426)	-	9,611	(10,034)
Extensions and discoveries less related costs	271,933	12,323	-	-	-	284,256
Development costs incurred	85,880	2,980	-	737	-	89,597
Revisions of previous quantity estimates	257,540	(4,517)	(1,879)	-	(7,098)	244,046
Purchase of Minerals in place	-	-	-	55,373	-	55,373
Net changes in income taxes	(185,118)	(1,368)	6,808	-	(65,585)	(245,263)
Accretion of discount	137,223	7,590	8,040	-	19,783	172,636
Present value at December 31, 2018	1,379,063	89,830	41,549	34,867	238,533	1,783,842
Sales of hydrocarbon, net of production costs	(411,528)	(14,284)	(17,289)	(13,280)	-	(456,381)
Net changes in sales price and production costs	(299,642)	12,799	6,923	(20,694)	(48,823)	(349,437)
Changes in estimated future development costs	(268,377)	(22,163)	1,165	573	(175,248)	(464,050)
Extensions and discoveries less related costs	182,857	17,300	-	-	-	200,157
Development costs incurred	69,694	4,023	445	4,325	-	78,487
Revisions of previous quantity estimates	415,349	9,508	5,482	(2,358)	11,992	439,973
Purchase of Minerals in place
Net changes in income taxes	23,398	(2,025)	729	3,760	51,917	77,779
Accretion of discount	222,758	9,235	4,378	4,148	42,846	283,365
Present value at December 31, 2019	1,313,572	104,223	43,382	11,341	121,217	1,593,735

89 

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

GeoPark Limited
By:	/s/ Andrés Ocampo
	Name:	Andrés Ocampo
	Title:	Chief Financial Officer

Date: March 24, 2020