6-K 1 dp64163_6k.htm FORM 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

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 2016

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

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

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

GEOPARK LIMITED

TABLE OF CONTENTS

ITEM
1.	GeoPark Limited Consolidated Financial Statements as of and for the year ended 31 December 2015

GEOPARK LIMITED

CONSOLIDATED

FINANCIAL STATEMENTS

As of and for the year ended 31 December 2015

GEOPARK LIMITED

31 DECEMBER 2015

Contents

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

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of
GeoPark Limited

In our opinion, the accompanying consolidated statement of financial position and the related consolidated statements of income, comprehensive income, changes in equity, and cash flow present fairly, in all material respects, the financial position of GeoPark Limited and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

By /s/ Carlos Martín Barbafina (Partner)

Carlos Martín Barbafina

Autonomous City of Buenos Aires, Argentina
March 9, 2016

CONSOLIDATED STATEMENT OF INCOME
Amounts in US$ ´000	Note	2015	2014	2013
NET REVENUE	7	209,690	428,734	338,353
Production and operating costs	8	(86,742)	(131,419)	(111,296)
Geological and geophysical expenses	11	(13,831)	(13,002)	(5,292)
Administrative expenses	12	(37,471)	(45,867)	(44,962)
Selling expenses	13	(5,211)	(24,428)	(17,252)
Depreciation		(105,557)	(100,528)	(69,968)
Write-off of unsuccessful efforts	19	(30,084)	(30,367)	(10,962)
Impairment loss for non-financial assets	19-36	(149,574)	(9,430)	-
Other (expenses) income		(13,711)	(1,849)	5,343
OPERATING (LOSS) PROFIT		(232,491)	71,844	83,964
Financial costs	14	(35,655)	(27,622)	(33,115)
Foreign exchange loss		(33,474)	(23,097)	(761)
(LOSS) PROFIT BEFORE INCOME TAX		(301,620)	21,125	50,088
Income tax benefit (expense)	16	17,054	(5,195)	(15,154)
(LOSS) PROFIT FOR THE YEAR		(284,566)	15,930	34,934
Attributable to: Owners of the Company		(234,031)	8,085	22,521
Non-controlling interest		(50,535)	7,845	12,413
(Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Basic	18	(4.05)	0.14	0.52
(Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Diluted	18	(4.05)	0.14	0.48

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Amounts in US$ ´000	2015	2014	2013
(Loss) Profit for the year	(284,566)	15,930	34,934
Other comprehensive income:
Items that may be subsequently reclassified to (loss) profit
Currency translation difference	(1,001)	(2,448)	(1,956)
Total comprehensive (Loss) Income for the year	(285,567)	13,482	32,978
Attributable to: Owners of the Company	(235,032)	5,637	20,565
Non-controlling interest	(50,535)	7,845	12,413

The notes on pages 7 to 82 are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

Amounts in US$ ´000	Note	2015	2014
ASSETS
NON CURRENT ASSETS
Property, plant and equipment	19	522,611	790,767
Prepaid taxes	21	1,172	1,253
Other financial assets	24	13,306	12,979
Deferred income tax asset	17	34,646	33,195
Prepayments and other receivables	23	220	349
TOTAL NON CURRENT ASSETS		571,955	838,543
CURRENT ASSETS
Inventories	22	4,264	8,532
Trade receivables	23	13,480	36,917
Prepayments and other receivables	23	11,057	13,993
Prepaid taxes	21	19,195	13,459
Other financial assets	24	1,118	-
Cash at bank and in hand	24	82,730	127,672
TOTAL CURRENT ASSETS		131,844	200,573
TOTAL ASSETS		703,799	1,039,116
TOTAL EQUITY
Equity attributable to owners of the Company
Share capital	25	59	58
Share premium		232,005	210,886
Reserves		123,016	124,017
(Accumulated losses) Retained earnings		(208,428)	40,596
Attributable to owners of the Company		146,652	375,557
Non-controlling interest		53,515	103,569
TOTAL EQUITY		200,167	479,126
LIABILITIES
NON CURRENT LIABILITIES
Borrowings	26	343,248	342,440
Provisions and other long-term liabilities	27	42,450	46,910
Deferred income tax liability	17	16,955	30,065
Trade and other payables	28	19,556	16,583
TOTAL NON CURRENT LIABILITIES		422,209	435,998
CURRENT LIABILITIES
Borrowings	26	35,425	27,153
Current income tax liabilities		208	7,935
Trade and other payables	28	45,790	88,904
TOTAL CURRENT LIABILITIES		81,423	123,992
TOTAL LIABILITIES		503,632	559,990

TOTAL EQUITY AND LIABILITIES		703,799	1,039,116

The financial statements were approved by the Board of Directors on 9 March 2016.

The notes on pages 7 to 82 are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Attributable to owners of the Company
Amount in US$ '000	Share Capital ⁽¹⁾	Share Premium	Other Reserve	Translation Reserve	(Accumulated losses) Retained earnings	Non-controlling Interest	Total
Equity at 1 January 2013	43	116,817	127,527	894	(5,860)	72,665	312,086
Comprehensive income:
Profit for the year	-	-	-	-	22,521	12,413	34,934
Currency translation differences	-	-	-	(1,956)	-	-	(1,956)
Total Comprehensive Income for the Year 2013	-	-	-	(1,956)	22,521	12,413	32,978
Transactions with owners:
Proceeds from transaction with Non-controlling interest (Notes 25 and 34)	-	-	-	-	-	9,529	9,529
Share-based payment (Note 29)	1	4,049	-	-	7,245	509	11,804
Repurchase of shares (Note 25)	-	(440)	-	-	-	-	(440)
Total 2013	1	3,609	-	-	7,245	10,038	20,893
Balances at 31 December 2013	44	120,426	127,527	(1,062)	23,906	95,116	365,957
Comprehensive income:
Profit for the year	-	-	-	-	8,085	7,845	15,930
Currency translation differences	-	-	-	(2,448)	-	-	(2,448)
Total Comprehensive Income for the Year 2014	-	-	-	(2,448)	8,085	7,845	13,482
Transactions with owners:
Proceeds from issue of shares	14	90,848	-	-	-	-	90,862
Proceeds from transaction with Non-controlling interest (Notes 25 and 34)	-	-	-	-	-	35	35
Share-based payment (Note 29)	-	-	-	-	8,605	573	9,178
Repurchase of shares (Note 25)	-	(388)	-	-	-	-	(388)
Total 2014	14	90,460	-	-	8,605	608	99,687
Balances at 31 December 2014	58	210,886	127,527	(3,510)	40,596	103,569	479,126
Comprehensive income:
Loss for the year	-	-	-	-	(234,031)	(50,535)	(284,566)
Currency translation differences	-	-	-	(1,001)	-	-	(1,001)
Total Comprehensive Loss for the Year 2015	-	-	-	(1,001)	(234,031)	(50,535)	(285,567)
Transactions with owners:
Share-based payment (Note 29)	1	22,734	-	-	(14,993)	481	8,223
Repurchase of shares (Note 25)	-	(1,615)	-	-	-	-	(1,615)
Total 2015	1	21,119	-	-	(14,993)	481	6,608
Balances at 31 December 2015	59	232,005	127,527	(4,511)	(208,428)	53,515	200,167

⁽¹⁾

See Note 1.

The notes on pages 7 to 82 are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENT OF CASH FLOW

Amounts in US$ ’000	Note	2015	2014	2013
Cash flows from operating activities
(Loss) Profit for the year		(284,566)	15,930	34,934
Adjustments for:
Income tax (benefit) expense	16	(17,054)	5,195	15,154
Depreciation		105,557	100,528	69,968
Allowance for doubtful accounts	13-23	-	741	-
Loss on disposal of property, plant and equipment		2,000	590	575
Impairment loss for non-financial assets	19-36	149,574	9,430	-
Write-off of unsuccessful efforts	19	30,084	30,367	10,962
Accrual of borrowing’s interests		28,460	25,754	22,085
Amortisation of other long-term liabilities	27	(703)	(468)	(1,165)
Unwinding of long-term liabilities	27	2,575	1,972	1,523
Accrual of share-based payment		8,223	8,373	9,167
Foreign exchange loss		33,474	23,097	761
Income tax paid		(7,625)	(1,306)	(4,040)
Changes in working capital	5	(24,104)	10,543	(32,629)
Cash flows from operating activities – net		25,895	230,746	127,295
Cash flows from investing activities
Purchase of property, plant and equipment		(48,842)	(238,047)	(215,234)
Acquisitions of companies, net of cash acquired		-	(114,967)	-
Collections related to financial leases		-	8,973	6,734
Cash flows used in investing activities – net		(48,842)	(344,041)	(208,500)
Cash flows from financing activities
Proceeds from borrowings		7,036	67,633	307,259
Proceeds from transaction with non-controlling interest ⁽¹⁾		-	35	40,667
Proceeds from loans from related parties		2,400	16,563	8,344
Proceeds from issuance of shares		-	90,862	3,442
Repurchase of shares		(1,615)	(388)	(440)
Principal paid to related parties		-	(8,344)	-
Principal paid		(89)	(17,087)	(179,360)
Interest paid		(25,754)	(24,558)	(15,894)
Cash flows (used in) / from financing activities - net		(18,022)	124,716	164,018

Net (decrease) increase in cash and cash equivalents		(40,969)	11,421	82,813

Cash and cash equivalents at 1 January		127,672	121,105	38,292
Currency translation differences		(3,973)	(4,854)	-
Cash and cash equivalents at the end of the year		82,730	127,672	121,105

Ending Cash and cash equivalents are specified as follows:
Cash in bank		82,720	127,560	121,113
Cash in hand		10	112	22
Bank overdrafts		-	-	(30)
Cash and cash equivalents		82,730	127,672	121,105

The notes on pages 7 to 82 are an integral part of these consolidated financial statements.

⁽¹⁾

Proceeds from transaction with Non-controlling interest for the year ended 31 December 2013 includes: US$ 9,529,000 from capital contributions received in the period; and US$ 31,138,000 as result of collection of receivables included in Prepayment and other receivables as of 31 December 2012, relating to equity transactions made in 2012 and 2011.

NOTES

Note

General Information

GeoPark Limited (the Company) is a company incorporated under the law of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM11, Bermuda.

The principal activity of the Company and its subsidiaries (“the Group”) are exploration, development and production for oil and gas reserves in Chile, Colombia, Brazil, Peru and Argentina. The Group has working interests and/or economic interests in 35 hydrocarbon blocks.

These consolidated financial statements were authorised for issue by the Board of Directors on 9 March 2016.

Note

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”).

The consolidated financial statements are presented in thousands (US$'000) of United States Dollars and all values are rounded to the nearest thousand (US$'000), except in the footnotes and where otherwise indicated.

The consolidated financial statements have been prepared on a historical cost basis.

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.

Note

Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure

During 2015, the Management of the Company has changed the presentation of the Consolidated Statement of Income re-ordering the profit and loss line items, eliminating gross profit and showing the depreciation and write off of unsuccessful efforts lines separately. This change is intended to provide the financial statements users with more relevant information and a better explanation of the elements of performance. This change has been applied to 2014 and 2013, for comparative purposes.

If previous year’s disclosure had not changed, the Consolidated Statement of Income would have been as follows:

CONSOLIDATED STATEMENT OF INCOME
Amounts in US$ ´000	2015	2014	2013
NET REVENUE	209,690	428,734	338,353
Production costs	(188,575)	(229,650)	(179,643)
GROSS PROFIT	21,115	199,084	158,710
Exploration costs	(43,915)	(43,369)	(16,254)
Administrative costs	(41,195)	(48,164)	(46,584)
Selling expenses	(5,211)	(24,428)	(17,252)
Impairment loss for non-financial assets	(149,574)	(9,430)	-
Other operating (loss) / income	(13,711)	(1,849)	5,344
OPERATING (LOSS) PROFIT	(232,491)	71,844	83,964
Financial results	(69,129)	(50,719)	(33,876)
(LOSS) PROFIT BEFORE INCOME TAX	(301,620)	21,125	50,088
Income tax benefit (expense)	17,054	(5,195)	(15,154)
(LOSS) PROFIT FOR THE YEAR	(284,566)	15,930	34,934

The Company has also revised its consolidated statement of income and the consolidated statement of changes in equity for the years ended 31 December 2014 and 2013, to properly record the accrual of its share-based payments costs recognized during 2014 and 2013, originally allocated in full to the Company’s owners for a total amount of US$ 573,000 and US$ 509,000, respectively. These adjustments had no change in total profit for 2014 and 2013 or to total equity originally reported. The Company concluded that the adjustments were not material to the consolidated statement of income and the consolidated statement of changes in equity for the years ended 31 December 2014 and 2013.

Note

Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure (continued)

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 1 January 2015:

Annual Improvements to IFRSs – 2010-2012 Cycle and 2011 – 2013 Cycle

Defined Benefit Plans: Employee Contributions – Amendments to IAS 19

The adoption of these amendments did not have any impact on the current period or any prior period and is not likely to affect future periods.

New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2015 and not early adopted.

Amendment to IFRS 9 ‘Financial Instruments’ addresses the classification, measurement and derecognition of financial assets and financial liabilities and introduces new rules for hedge accounting.

In July 2014, the IASB made further changes to the classification and measurement rules and also introduced a new impairment model. These latest amendments now complete the new financial instruments standard. Following the changes approved by the IASB in July 2014, the group no longer expects any impact from the new classification, measurement and derecognition rules on the group’s financial assets and financial liabilities. There will also be no impact on the Group’s accounting for financial liabilities, as the new requirements only affect the accounting for financial liabilities that are designated at fair value through profit or loss and the Group does not have any such liabilities.

The Group is yet to assess amendment to IFRS 9’s full impact and intends to adopt it no later than the accounting period beginning on or after 1 January 2018.

IFRS 15 ‘Revenue from Contracts with Customers’: the IASB has issued a new standard for the recognition of revenue. This will replace IAS 18 which covers contracts for goods and services and IAS 11 which covers construction contracts. The new standard is based on the principle that revenue is recognized when control of a good or service transfers to a customer – so the notion of control replaces the existing notion of risks and rewards. The standard permits a modified retrospective approach for the adoption. Under this approach entities will recognize transitional adjustments in retained earnings on the date of initial application (e.g. 1 January 2017), i.e. without restating the comparative period. They will only need to apply the new rules to contracts that are not completed as of the date of initial application. The Group is yet to assess amendment to IFRS 15’s full impact and intends to adopt it no later than the accounting period beginning on or after 1 January 2017.

Note

Summary of significant accounting policies (continued)

2.1 Basis of preparation (continued)

2.1.1 Changes in accounting policy and disclosure (continued)

IFRS 16 ‘Leases’: the IASB has issued in January 2016 a new standard that sets out the principles for the recognition, measurement, presentation and disclosure of leases for both parties to a contract, i.e. the customer (‘lessee’) and the supplier (‘lessor’). IFRS 16 replaces the previous leases Standard, IAS 17 Leases, and related Interpretations. IFRS 16 eliminates the classification of leases as either operating leases or finance leases for a lessee. Instead all leases are treated in a similar way to finance leases applying IAS 17. Leases are ‘capitalized’ by recognizing the present value of the lease payments and showing them either as lease assets (right-of-use assets) or together with property, plant and equipment.

If lease payments are made over time, a company also recognizes a financial liability representing its obligation to make future lease payments. The most significant effect will be an increase in lease assets and financial liabilities. The Group is yet to assess IFRS 16’s full impact and intends to adopt it no later than the accounting period beginning on or after 1 January 2019.

There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

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 (see Note 35), the performance of the operations, Group’s cash position, the offtake and the prepayment agreement signed with Trafigura (see Note 3) and over 80% of its total indebtedness maturing in 2020, 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.

Note

Summary of significant accounting policies (continued)

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 values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.

Acquisition-related costs are expensed as incurred.

The excess of the consideration transferred the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the identifiable net assets acquired is recorded as goodwill. If the total of consideration transferred, non-controlling interest recognized and previously held interest measured is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognized directly in the income statement.

Intercompany transactions, balances and unrealised gains on transactions between the Group and its subsidiaries are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group.

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.

Note

Summary of significant accounting policies (continued)

2.5 Foreign currency translation

Functional and presentation currency

The consolidated financial statements are presented in US Dollars, which is the Group’s presentation currency.

Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Chile, Colombia, Peru and Argentina is the US Dollar, meanwhile for the Group Brazilian company the functional currency is the local currency, which is the Brazilian Real.

Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Consolidated Statement of Income.

2.6 Joint arrangements

The company has applied IFRS 11 to all joint arrangements as of 1 January 2013. Under IFRS 11 investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations each investor.

The Company has assessed the nature of its joint arrangements and determined them to be joint operations. The company 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.

2.7 Revenue recognition

Revenue from the sale of crude oil and gas is recognised in the Statement of Income when risk 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.

Note

Summary of significant accounting policies (continued)

2.8 Production and operating costs

Production costs include wages and salaries incurred to achieve the net revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, leasing and royalties are also included within this account.

2.9 Financial costs

Financial costs include interest expenses, realised and unrealised gains and losses arising from transactions in foreign currencies and the amortisation of financial assets and liabilities. The Company has capitalised borrowing cost for wells and facilities that were initiated after 1 January 2009. Amounts capitalised during the year totalled US$ 637,390 (US$ 3,112,317 in 2014 and US$ 1,312,953 in 2013).

2.10 Property, plant and equipment

Property, plant and equipment are stated at historical cost less depreciation and impairment charge, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation.

Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, 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 amortisation are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which the determination is made depending whether they have found reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable.

A charge of US$ 30,084,000 has been recognised in the Consolidated Statement of Income (US$ 30,367,000 in 2014 and US$ 10,962,000 in 2013) for write-offs (see Note 19).

Note

Summary of significant accounting policies (continued)

2.10 Property, plant and equipment (continued)

All field development costs are considered construction in progress until they are finished and capitalised within oil and gas properties, and are subject to depreciation once complete. 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 income when incurred.

Capitalised costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs and is based on current year end unescalated price levels. Changes in reserves and cost estimates are recognised prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.

Depreciation of the remaining property, plant and equipment assets (i.e. furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between 3 years and 10 years.

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

An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.12).

2.11 Provisions and other long-term liabilities

Provisions for asset retirement obligations, deferred income, restructuring obligations and legal claims are recognised when the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments.

Note

Summary of significant accounting policies (continued)

2.11 Provisions and other long-term liabilities (continued)

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 passage of time is recognised as interest expense.

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 capitalises the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and application of current legislation and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are included in the financial statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset.

2.11.2 Deferred Income

Relates to contributions received in cash from the Group’s clients to improve the project economics of gas wells. The amounts collected are reflected as a deferred income in the balance sheet and recognised in the Consolidated Statement of Income over the productive life of the associated wells. The depreciation of the gas wells that generated the deferred income is charged to the Consolidated Statement of Income simultaneously with the amortisation of the deferred income.

2.12 Impairment of non-financial assets

Assets that are not subject to depreciation and/or amortisation (i.e.: exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation and/or amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

Note

Summary of significant accounting policies (continued)

2.12 Impairment of non-financial assets (continued)

An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable.

The impairment loss recognised in 2015 amounted to US$ 149,574,000 (US$ 9,430,000 in 2014, nil in 2013) See Note 36. The write-offs are detailed in Note 19.

2.13 Lease contracts

All current lease contracts are considered to be operating leases on the basis that the lessor retains substantially all the risks and rewards related to the ownership of the leased asset. Payments related to operating leases and other rental agreements are recognised in the Consolidated Income Statement on a straight line basis over the term of the contract. The Group's total commitment relating to operating leases and rental agreements is disclosed in Note 31.

Leases in which substantially all of the risks and rewards of ownership are transferred to the lessee are classified as finance leases. Under a finance lease, the Company as lessor has to recognize an amount receivable equal to the aggregate of the minimum lease payments plus any unguaranteed residual value accruing to the lessor, discounted at the interest rate implicit in the lease.

2.14 Inventories

Inventories comprise crude oil and materials.

Crude oil is measured at the lower of cost and net realisable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method.

Note

Summary of significant accounting policies (continued)

2.15 Current and deferred income tax

The tax expense for the year comprises current and deferred tax. Tax is recognised in the Consolidated Statement of Income.

The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the balance sheet date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome.

Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

In addition, the Group has tax-loss carry-forwards in certain taxing jurisdictions that are available to 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.

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 Company 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 Company would have to recognize amounts to approximately US$ 8,300,000.

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

Note

Summary of significant accounting policies (continued)

2.16 Financial assets

Financial assets are divided into the following categories: loans and receivables; financial assets at fair value through the profit or loss; available-for-sale financial assets; and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial recognition, depending on the purpose for which the investments were acquired. The designation of financial assets is re-evaluated at every reporting date at which a choice of classification or accounting treatment is available.

All financial assets are recognised when the Group becomes a party to the contractual provisions of the instrument. All financial assets are initially recognised at fair value, plus transaction costs.

Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date.

Interest and other cash flows resulting from holding financial assets are recognised in the Consolidated Income Statement when receivable, regardless of how the related carrying amount of financial assets is measured.

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. The Group’s loans and receivables comprise trade receivables, prepayments and other receivables and cash at bank and in hand in the balance sheet. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. Loans and receivables are subsequently measured at amortised cost using the effective interest method, less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Statement of Income. All of the Group’s financial assets are classified as loan and receivables.

2.17 Other financial assets

Non current other financial assets include contributions made for environmental obligations according to a Colombian government request. Current financial assets corresponds to short term investments with original maturities up to twelve months and over three months.

Note

Summary of significant accounting policies (continued)

2.18 Impairment of financial assets

Provision against trade receivables is made when objective evidence is received that the Group will not be able to collect all amounts due to it in accordance with the original terms of those receivables. The amount of the write-down is determined as the difference between the asset's carrying amount and the present value of estimated future cash flows.

2.19 Cash and cash equivalents

Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position.

2.20 Trade and other payables

Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities.

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

2.21 Borrowings

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

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the Consolidated Statement of Income over the period of the borrowings using the effective interest method.

Direct issue costs are charged to the Consolidated Statement of Income on an accruals basis using the effective interest method.

Note

Summary of significant accounting policies (continued)

2.22 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 issue.

"Other reserve" representing:

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

the difference between the proceeds from the transaction with non-controlling interests received against the book value of the shares acquired in the Chilean and Colombian subsidiaries.

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

"(Accumulated losses) Retained earnings" representing accumulated earnings and losses.

2.23 Share-based payment

The Group operates a number of equity-settled and cash-settled share-based compensation plans comprising share awards payments and stock options plans to certain employees and other third party contractors.

Share-based payment transactions are measured in accordance with IFRS 2.

Fair value of the stock option plan for employee or contractors services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted calculated using the Black-Scholes model.

Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At each balance sheet date, the entity revises its estimates of the number of options that are expected to vest. It recognises the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment to equity.

The fair value of the share awards payments is determined at the grant date by reference of the market value of the shares and recognised as an expense over the vesting period.

Note

Summary of significant accounting policies (continued)

2.23 Share-based payment (continued)

When the options are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised.

For cash-settled share-based payment transactions, the Company measures the services acquired for amounts that are based on the price of the Company’s shares. The fair value of the liability incurred is measured using Geometric Brownian Motion method. Until the liability is settled, the Company is required to remeasure the fair value of the liability at each reporting date and at the date of settlement, with any changes in value recognized in profit or loss for the period.

Note

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. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate office. The policy for each of the above risks is described in more detail below.

Currency risk

In Argentina, Colombia, Chile and Peru the functional currency is the US Dollar. The fluctuation of the local currencies of these countries against the US Dollar does not impact the loans, costs and revenues held in US Dollars; but it does impact the balances denominated in local currencies. Such is the case of the prepaid taxes.

In Chile, Colombia and Argentina subsidiaries most of the balances are denominated in US Dollars, and since it is the functional currency of the subsidiaries, there is no exposure to currency fluctuation except from receivables or payables originated in local currency mainly corresponding to VAT. The balances as of 31 December 2015 of VAT were credits for US$ 111,000 (US$ 73,000 in 2014) in Argentina, credits for US$ 9,077,000 (US$ 5,107,000 in 2014) in Chile, and credits for US$ 4,001,000 (payable US$ 1,358,000 in 2014) in Colombia.

Note

Financial Instruments-risk management (continued)

Currency risk (continued)

The Group minimises the local currency positions in Argentina, Colombia and Chile by seeking to equilibrate local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore the Group maintains a net exposure to them.

Most of the Group's assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally settled in US Dollar equivalents.

During 2015, the Argentine Peso devaluated by 52% (31% and 33% in 2014 and 2013, respectively) against the US Dollar, the Chilean Peso devaluated by 16% (16% and 10% in 2014 and 2013 respectively) and the Colombian Peso devaluated by 32% (24% and 9% in 2014 and 2013, respectively).

If the Argentine Peso, the Chilean Peso and the Colombian Peso had each devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 1,003,300 (post – tax profit lower by US$ 621,400 in 2014 and higher by US$ 279,000 in 2013).

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 cash at bank and Itaú and intercompany loans. Most of the balances are denominated in Brazilian Real, and since it is the functional currency of the Brazilian subsidiary, there is no exposure to currency fluctuation except from cash at bank held in US Dollars and for the intercompany loan and Itaú loan described in Note 26. The exchange loss generated by the Brazilian subsidiary during 2015 amounted to US$ 35,605,000 (US$ 17,573,000 in 2014 and nil in 2013).

During 2015, the Brazilian Real devaluated by 47% against the US Dollar (13% and 15% in 2014 and 2013, respectively). If the Brazilian Real had devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 7,400,000 (post – tax profit lower by US$ 5,660,000 in 2014 and higher by US$ 3,652,000 in 2013).

As of 31 December 2015, the balances denominated in the Peruvian local currency (Peruvian Soles) are not material.

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

Note

Financial Instruments-risk management (continued)

Price risk

The price realised for the oil produced by the Group is linked to WTI (West Texas Intermediate) and Brent, US dollar denominated international benchmarks. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors.

Between October 2014 and February 2016, WTI and Brent have fallen more than 60%, affecting both the Company’s results in 2015 and the Company’s expectations for 2016 (see Note 35).

In Colombia, the price of oil is based on Vasconia, a marker broadly used in the Llanos basin, adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur, delivery point and water content.

In Chile, the oil price is based on Brent minus certain marketing and quality discounts such as, inter alia, API quality and others.

The Company has signed a long-term Gas Supply Contract with Methanex in Chile. The price of the gas sold under this contract is determined based on a formula that takes into account various international prices of methanol, including US Gulf methanol spot barge prices, methanol spot Rotterdam prices and spot prices in Asia.

In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral de Preços do Mercado), or IGPM.

If oil and methanol prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, post-tax loss for the year would have been higher by US$ 23,940,000 (post tax profit lower by US$ 29,186,000 in 2014 and US$ 27,179,000 in 2013).

The Group has no price-hedging transaction currently outstanding. The Board could consider adopting commodity price hedging measures, when deemed appropriate, according to the size of the business, production levels and market implied volatility.

Note

Financial Instruments-risk management (continued)

Credit risk – concentration

The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognised values. There is not considered to be any significant risk in respect of the Group’s major customers.

In Colombia, the Group have diversified the customer base and for the year ended 31 December 2015, the Colombian subsidiary made 62.1% of the oil sales to Gunvor (a global privately-held company, dedicated to commodities trading), 12.6% to Trafigura (one of the world’s leading independent commodity trading and logistics houses) and 9.2% to Petrominerales (a local independent company, dedicated to oil and gas exploration and production), with Gunvor accounting for 39.1%, Trafigura 7.9% and Petrominerales 5.8% of consolidated revenues for the same period.

All the oil produced in Chile is sold to ENAP as well as the gas produced by TdF Blocks (15% of total revenue, 28% in 2014 and 40% in 2013), the State owned oil and gas company. In Chile, most of gas production is sold to the local subsidiary of the Methanex, a Canadian public company (7% of consolidated revenues, 6% in 2014 and 7% in 2013).

In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the operator of the Manati Field and the State owned company.

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

See disclosure in Note 24.

Funding and Liquidity risk

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

The Group is positioned at the end of 2015 with a cash balance of US$ 82,730,000 and over 80% of its total indebtedness maturing in 2020. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 20,000 boepd in production. This scale and positioning permit GeoPark to protect its financial condition and selectively allocate capital to the optimal projects subject to prevailing macroeconomic conditions.

Note

Financial Instruments-risk management (continued)

Funding and liquidity risk (continued)

However, during 2015 and impacted by the current low oil price environment, the Company’s Leverage Ratio and the Interest Coverage did not meet certain thresholds included in the 2020 Bond Indenture. This situation may limit the Company’s capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes (Note 26).

The most significant funding transactions executed in 2015 and 2014 include:

On February 2014, the Group received a gross proceed of US$ 98,000,000 from the issuance of new shares.

On March 2014, GeoPark executed a loan agreement with Itaú BBA International (Itau) for US$ 70,450,000 to finance the acquisition of a working interest in the Manatí field (Brazil) maturing between 2015 and 2019.

On March 2015, the Group reached an agreement with Itau to: (i) extend the principal payments that were originally due in 2015 (amounting to approximately US$ 15,000,000), which were divided pro-rata during the remaining principal instalments, starting in March 2016 and (ii) increase the variable interest rate equal to the six-month LIBOR + 4.0%.

On December 2015, the Group announced the execution of an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provides GeoPark with access to up to US$ 100,000,000 in the form of prepaid future oil sales, subject to certain customary covenants. Funds committed by Trafigura are available to GeoPark upon request until September 2016 and are to be repaid by the Company through future oil deliveries over 2.5 years with a six-month grace period. As of 31 December 2015 no prepayments were requested.

Note

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 cash flow to interest rate risk.

The Group does not face interest rate risk on its US$ 300,000,000 Notes which carry a fixed rate coupon of 7.50% per annum. As consequence, the accruals and interest payment are no substantially affected to the market interest rate changes.

At 31 December 2015 the outstanding long-term borrowing affected by variable rates amounted to US$ 76,178,000, representing 20% of total borrowings, which was composed by the loans from Itaú Bank and Banco de Chile that have a floating interest rate based on LIBOR.

The Group analyses its interest rate exposure on a dynamic basis. Various scenarios are simulated taking into consideration refinancing, renewal of existing positions, alternative financing and hedging. Based on these scenarios, the Group calculates the impact on profit and loss of a defined interest rate shift. For each simulation, the same interest rate shift is used for all currencies. The scenarios are run only for liabilities that represent the major interest-bearing positions.

At 31 December 2015, if 1% is added to interest rates on currency-denominated borrowings with all other variables held constant, post-tax loss for the year would have been US$ 507,000 higher (post-tax profit lower US$ 312,000 in 2014, nil in 2013).

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 at bank and in hand. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plus net debt.

The Group’s strategy is to keep the gearing ratio within a 30% to 45% range, in normal market conditions. Due to the market conditions prevailing during 2015 the gearing ratio at year end is above such range. Measures taken by the Company in this connection are described in Note 35.

Note

Financial Instruments-risk management (continued)

Capital risk management (continued)

The gearing ratios at 31 December 2015 and 2014 were as follows:

Amounts in US$ '000	2015	2014
Net Debt	295,943	241,921
Total Equity	200,167	479,126
Total Capital	496,110	721,047
Gearing Ratio	60%	34%

Note

Accounting estimates and assumptions

Estimates and assumptions are used in preparing the financial statements. Although these estimates are based on management's best knowledge of current events and actions, actual results may differ from them. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

The key estimates and assumptions used in these consolidated financial statements are noted below:

Cash flow estimates for impairment assessments require assumptions about two primary elements - future prices and reserves. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The group´s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and own assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs.

Given the significant assumptions required and the possibility that actual conditions will differ, management considers the assessment of impairment to be a critical accounting estimate (see Notes 35 and 36).

The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of 31 December 2015 prepared by DeGolyer and MacNaughton, an international consultancy to the oil and gas industry based in Dallas. It incorporates many factors and assumptions including:

Note

Accounting estimates and assumptions (continued)

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 gas prices and quality differentials;

assumed effects of regulation by governmental agencies; and

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 Company makes assessments and estimates regarding whether an exploration asset should continue to be carried forward as an exploration and evaluation asset not yet determined or when insufficient information exists for this type of cost to remain as an asset. In making this assessment the Management takes professional advice from qualified experts.

Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities.

Note

Accounting estimates and assumptions (continued)

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 Company has adopted the following criterion for recognising well plugging and abandonment related costs: The present value of future costs necessary for well plugging and abandonment is calculated for each area on the basis of a cash flow that is discounted at an average interest rate applicable to Company’s indebtedness. The liabilities recognised are based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates.

From time to time, the Company may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. For example, from time to time, the Company receives notice of environmental, health and safety violations. Based on what the Management of the Company currently knows, it is not expected any material impact on the financial statements.

Note

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 corporation tax. Tax paid is presented as a separate item under operating activities.

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

Amounts in US$ '000	2015	2014	2013
Increase in asset retirement obligation	985	1,603	7,183
Financial leases	-	-	14,133
Increase in provisions for other long-term liabilities	-	5,636	-
Purchase of property, plant and equipment	830	1,382	12,799

Note

Consolidated Statement of Cash Flow (continued)

Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment, cash flows relating to the purchase and sale of enterprises to third parties and cash flows from financial lease transactions. 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.

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

Amounts in US$ '000	2015	2014	2013
Increase in Prepaid taxes	(16,611)	(3,310)	(4,283)
Decrease / (Increase) in Inventories	2,752	(410)	(4,166)
Decrease / (Increase) in Trade receivables	22,470	13,791	(10,357)
Decrease / (Increase) in Prepayments and other receivables and Other assets	405	12,569	(13,330)
Decrease in Trade and other payables	(33,120)	(12,097)	(493)
	(24,104)	10,543	(32,629)

Note

Segment information

The committee considers the business from a geographic perspective. As from 2015, the committee has changed the disclosure of certain elements of performance to be more comparable with other companies in the market and also to better follow up the performance of the business. This change impacts the segment information because gross profit or loss is no longer shown but no impact is generated in the measure of segment profit and loss.

Note

Segment information (continued)

The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit for the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payment and other non recurring events. Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses. Other information provided, except as noted below, to the Executive Committee is measured in a manner consistent with that in the financial statements.

Segment areas (geographical segments):

Amounts in US$ '000	Argentina	Brazil	Colombia	Peru	Chile	Corporate	Total
2015
Net revenue	597	32,388	131,897	-	44,808	-	209,690
Sale of crude oil	597	955	131,897	-	29,180	-	162,629
Sale of gas	-	31,433	-	-	15,628	-	47,061
Production and operating costs	(1,448)	(8,056)	(48,534)	-	(28,704)	-	(86,742)
Royalties	(34)	(2,998)	(8,150)	-	(1,973)	-	(13,155)
Transportation costs	(2)	-	(2,068)	-	(2,441)	-	(4,511)
Share-based payment	(197)	-	(234)	-	(132)	-	(563)
Other costs	(1,215)	(5,058)	(38,082)	-	(24,158)	-	(68,513)
Operating (loss) / profit	(2,350)	6,639	(37,227)	(6,719)	(180,264)	(12,570)	(232,491)
Adjusted EBITDA	(684)	20,460	66,736	(6,520)	(183)	(6,022)	73,787

Depreciation	(199)	(13,568)	(52,434)	(129)	(39,227)	-	(105,557)
Impairment loss	-	-	(45,059)	-	(104,515)	-	(149,574)
Write-off	-	-	(4,333)	-	(25,751)	-	(30,084)
Total assets	3,181	114,974	153,071	4,287	381,143	47,143	703,799

Employees (average)	93	11	130	16	153	-	403
Employees at year end	90	12	133	11	106	-	352

Note

Segment information (continued)

Amounts in US$ '000	Argentina	Brazil	Colombia	Peru	Chile	Corporate	Total
2014
Net revenue	1,308	35,621	246,085	-	145,720	-	428,734
Sale of crude oil	1,304	1,541	246,054	-	118,203	-	367,102
Sale of gas	4	34,080	31	-	27,517	-	61,632
Production costs	(550)	(8,148)	(80,953)	-	(41,768)	-	(131,419)
Royalties	(241)	(2,794)	(12,354)	-	(6,777)	-	(22,166)
Transportation costs	(87)	-	(4,663)	-	(6,784)	-	(11,534)
Share-based payment	(433)	-	(423)	-	(763)	-	(1,619)
Other costs	211	(5,354)	(63,513)	-	(27,444)	-	(96,100)
Operating (loss) / profit	(4,321)	10,658	67,212	(2,419)	11,733	(11,019)	71,844
Adjusted EBITDA	(816)	22,637	130,209	(2,425)	76,420	(5,948)	220,077

Depreciation	(229)	(11,613)	(51,584)	-	(37,077)	(25)	(100,528)
Impairment loss	-	-	(9,430)	-	-	-	(9,430)
Write-off	(31)	-	(1,564)	-	(28,772)	-	(30,367)
Total assets	3,839	151,770	263,070	4,813	541,481	74,143	1,039,116

Employees (average)	100	10	121	4	208	-	443
Employees at year end	100	12	133	14	197	-	456

Amounts in US$ '000	Argentina	Brazil	Colombia	Peru	Chile	Corporate	Total
2013
Net revenue	1,538	-	179,324	-	157,491	-	338,353
Sale of crude oil	1,532	-	179,324	-	134,579	-	315,435
Sale of gas	6	-	-	-	22,912	-	22,918
Production costs	(287)	-	(72,479)	-	(38,530)	-	(111,296)
Royalties	(194)	-	(9,661)	-	(7,384)	-	(17,239)
Transportation costs	(204)	-	(4,733)	-	(6,455)	-	(11,392)
Share-based payment	(347)	-	(905)	-	(1,300)	-	(2,552)
Other costs	458	-	(57,180)	-	(23,391)	-	(80,113)
Operating (loss) / profit	(1,942)	(3,107)	38,811	-	63,110	(12,908)	83,964
Adjusted EBITDA	166	(3,037)	82,611	-	96,348	(8,835)	167,253

Depreciation	(225)	(2)	(39,406)	-	(30,239)	(96)	(69,968)
Write-off	-	-	(3,258)	-	(7,704)	-	(10,962)
Total assets	7,977	29,222	259,421	-	477,263	72,532	846,415

Employees (average)	97	3	107	-	184	-	391
Employees at year end	98	4	109	-	193	-	404

Approximately 22% of capital expenditure was allocated to Chile (66% in 2014 and 63% in 2013), 66% was allocated to Colombia (29% in 2014 and 37% in 2013) and 12% was allocated to Brazil (5% in 2014, nil in 2013). The capital expenditure referred does not include total consideration for M&A activities.

Note

Segment information (continued)

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

Amounts in US$ '000	2015	2014	2013
Operating netback	118,027	274,509	214,682
Administrative expenses	(30,590)	(40,340)	(39,572)
Geological and geophysical expenses	(13,650)	(14,092)	(7,857)
Adjusted EBITDA for reportable segments	73,787	220,077	167,253
Depreciation ^(a)	(105,557)	(100,528)	(69,968)
Share-based payment	(8,223)	(8,373)	(9,167)
Impairment and write-off of unsuccessful efforts	(179,658)	(39,797)	(10,962)
Others ^(b)	(12,840)	465	6,808
Operating (loss) profit	(232,491)	71,844	83,964
Financial costs	(35,655)	(27,622)	(33,115)
Foreign exchange loss	(33,474)	(23,097)	(761)
(Loss) Profit before tax	(301,620)	21,125	50,088

^(a)

Net of capitalised costs for oil stock included in Inventories.

^(b)

In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs.

Note

Net Revenue

Amounts in US$ '000	2015	2014	2013
Sale of crude oil	162,629	367,102	315,435
Sale of gas	47,061	61,632	22,918
	209,690	428,734	338,353

Note

Production and operating costs

Amounts in US$ '000	2015	2014	2013
Well and facilities maintenance	19,974	25,475	20,662
Staff costs (Note 10)	17,999	16,112	11,650
Share-based payment (Notes 10 and 29)	563	1,619	2,552
Royalties	13,155	22,166	17,239
Consumables	8,591	16,157	14,855
Transportation costs	4,511	11,534	11,392
Equipment rental	3,517	7,563	7,139
Safety and Insurance costs	3,239	5,733	4,843
Gas plant costs	2,878	3,277	3,217
Field camp	2,645	5,932	4,805
Non operated blocks costs	2,127	9,730	5,635
Other costs	7,543	6,121	7,307
	86,742	131,419	111,296

Note

Depreciation

Amounts in US$ '000	2015	2014	2013
Oil and gas properties	84,849	89,651	59,234
Production facilities and machinery	15,467	9,621	9,341
Furniture, equipment and vehicles	2,850	1,862	964
Buildings and improvements	874	523	661
Depreciation of property, plant and equipment ^(*)	104,040	101,657	70,200

Related to:

Productive assets	100,316	99,360	68,579
Administrative assets	3,724	2,297	1,621
Depreciation total ^(*)	104,040	101,657	70,200

^(*)Depreciation without considering capitalised costs for oil stock included in Inventories.

Note

Staff costs and Directors Remuneration

	2015	2014	2013
Number of employees at year end	352	456	404
Amounts in US$ '000
Wages and salaries	40,574	41,593	29,504
Share-based payments (Note 29)	8,223	9,178	8,362
Share-based payments – Cash awards (Note 29)	-	(805)	805
Social security charges	6,197	6,597	5,291
Director’s fees and allowance	1,239	1,998	1,426
	56,233	58,561	45,388

Recognised as follows:

Production and operating costs	18,562	17,731	14,202
Geological and geophysical expenses	11,336	12,939	7,676
Administrative expenses	26,335	27,891	23,510
	56,233	58,561	45,388

Board of Directors’ and key managers’ remuneration
Salaries and fees	6,549	11,003	7,702
Share-based payments	6,544	3,314	2,971
Other benefits in kind	167	130	742
	13,260	14,447	11,415

Note

Staff costs and Directors Remuneration (continued)

Directors’ Remuneration

	Executive Directors’ Fees	Executive Directors’ Bonus⁽⁷⁾	Non-Executive Directors’ Fees (in US$)	Director Fees Paid in Shares No. of Shares ⁽¹⁾	Cash Equivalent Total Remuneration
Gerald O’Shaughnessy	US$ 200,000	US$ 75,000	-	-	US$ 275,000
James F. Park	US$ 450,000	US$ 325,000	-	-	US$ 775,000
Pedro Aylwin ⁽²⁾	-	-	-	-	-
Peter Ryalls⁽³⁾	-	-	US$ 108,000	20,343	US$ 198,029
Juan Cristóbal Pavez⁽⁴⁾	-	-	US$ 99,000	20,343	US$ 189,029
Carlos Gulisano⁽⁵⁾	-	-	US$ 99,000	20,343	US$ 189,029
Steven J. Quamme⁽⁶⁾	-	-	US$ 33,322	5,811	US$ 64,207
Robert Bedingfield	-	-	US$ 70,000	17,042	US$ 140,025

¹ Only 8,285 shares of the 83,882 shares paid as Director Fees were not issued during 2015 (see Note 29).

² Pedro Aylwin has a service contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director.

³ Technical Committee Chairman.

⁴ Compensation Committee Chairman.

⁵ Nomination Committee Chairman.

⁶ Audit Committee Chairman until his resignation on 19 March 2015. Afterwards the Chairman is Robert Bedingfield.

⁷ On 10 December 2015, 123,839 shares were allocated to the payment of the Bonus.

The non-executive Directors annual fees correspond to US$ 80,000 to be settled in cash and US$ 100,000 to be settled in stocks, paid quarterly in equal installments. In the event that a non-executive Director serves as Chairman of any Board Committees, an additional annual fee of US$ 20,000 shall apply. A Director who serves as a member of any Board Committees shall receive an annual fee of US$ 10,000. Total payment due shall be calculated in an aggregate basis for Directors serving in more than one Committee. The Chairman fee shall not be added to the member´s fee for the same Committee. Payments of Chairmen and Committee members´ fees shall be made quarterly in arrears and settled in cash only.

During the first half of 2015, a decrease of 20% in the compensation program for the services of the non-executive Directors was approved.

Stock Awards to Executive Directors

The following Stock Options were issued to Executive Directors during 2012:

Name	N° of Underlying Common Shares	Grant Date	Exercise Price (US$)	Earliest Exercise Date
Gerald O’Shaughnessy	270,000	23 Nov 2012	0.001	23 Nov 2015
James F. Park	450,000	23 Nov 2012	0.001	23 Nov 2015

On 30 November 2015, the 720,000 shares were issued.

Note

Geological and geophysical expenses

Amounts in US$ '000	2015	2014	2013
Staff costs (Note 10)	10,557	11,712	6,451
Share-based payment (Notes 10 and 29)	779	1,227	1,225
Allocation to capitalised project	(598)	(2,317)	(2,437)
Other services	3,093	2,380	1,406
Amortisation of other long-term liabilities related to unsuccessful efforts	-	-	(600)
Recovery of abandonments costs	-	-	(753)
	13,831	13,002	5,292

Note

Administrative expenses

Amounts in US$ '000	2015	2014	2013
Staff costs (Note 10)	18,215	20,366	16,694
Share-based payment (Notes 10 and 29)	6,881	5,527	5,390
Consultant fees	4,115	6,791	6,424
Office expenses	2,535	3,190	2,652
Travel expenses	1,497	2,052	1,258
Director’s fees and allowance	1,238	1,998	1,426
New projects	559	2,798	3,720
Other administrative expenses	2,431	3,145	7,398
	37,471	45,867	44,962

Note

Selling expenses

Amounts in US$ '000	2015	2014	2013
Transportation	4,760	23,106	16,181
Selling taxes	440	433	406
Storage	11	148	665
Allowance for doubtful accounts	-	741	-
	5,211	24,428	17,252

Note

Financial costs

Amounts in US$ '000	2015	2014	2013
Financial expenses
Interest and amortisation of debt issue costs	30,543	29,466	25,208
Less: amounts capitalised on qualifying assets	(637)	(3,112)	(1,313)
Bank charges and other financial costs	4,443	2,672	2,519
Unwinding of long-term liabilities (Note 27)	2,575	1,972	1,523
Notes GeoPark Fell SpA cancellation costs	-	-	8,603
Financial income
Interest received	(1,269)	(3,376)	(3,425)
	35,655	27,622	33,115

Note

Tax reforms in Colombia and Chile

Colombia

The Colombian Congress approved a Tax Reform in December 2014. This reform had introduced a temporary net wealth tax assessed on net equity on domestic and foreign legal entities, kept the rate of the income tax on equality (Enterprise contribution on equality, “CREE” for its Spanish acronym) at 9%, and applied a CREE surcharge until 2018, among other changes.

The net wealth tax (NWT) assessed on net equity applied for tax years 2015 through 2017 for domestic and foreign entities that hold any wealth in Colombia, directly or indirectly, via permanent establishments (PEs) or branches. In the case of foreign or domestic individuals, the NWT would apply until 2018.

NWT applied at progressive rates ranging from 1.15% in 2014; 1% in 2015 and decreased to 0.4% in 2016 and finally would disappear in 2017, for corporate taxpayers. NWT paid is not deductible or creditable for Colombian income tax purposes.

The Reform also extended the current 9% CREE tax rate, which was scheduled to decrease to 8% in 2016. Also, it introduced a new CREE surcharge, beginning in 2015, from 5% in 2015, 6% in 2016, and 8% in 2017 to 9% in 2018. Therefore, the accumulated corporate income tax rate will rise to 43% in 2018. The Company considered the effects of this rate increase in the deferred income tax calculation.

Note

Tax reforms in Colombia and Chile (continued)

Colombia (continued)

In addition, in December 2015, Colombia's government announced its plan for a tax reform to be submitted to Congress in March 2016. The main proposed changes included in the project are the following:

- Unification between Income Tax and CREE, resulting in a “new income tax” with a rate between 30% and 35%;

- Elimination of NWT;

- Incorporation of dividend distribution withholding tax, with a rate between 10% and 15%;

- Increase of VAT rate from 16% to 19%

All these measures, if approved, will have effect for 2017 fiscal year onwards.

Chile

The Chilean Congress approved a reform to the income tax law in September 2014. Under this reform the income tax rate increased from 20% in 2013 to 21% in 2014, 22.5% in 2015, 24% in 2016, 25.5% in 2017 and 27% in 2018.

The operating subsidiaries that GeoPark controls in Chile, which are GeoPark TdF S.A., GeoPark Fell SpA and GeoPark Magallanes Limitada, are not affected by such income tax reform since they are covered by the tax treatment established in the Special contract of operations (“CEOPs”).

Note

Income tax

Amounts in US$ '000	2015	2014	2013
Current tax	7,262	23,574	13,337
Deferred income tax (Note 17)	(24,316)	(18,379)	1,817
	(17,054)	5,195	15,154

Note

Income Tax (continued)

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	2015	2014	2013
(Loss) Profit before tax	(301,620)	21,125	50,088
Tax losses from non-taxable jurisdictions	15,852	5,010	14,348
Taxable (loss) profit	(285,768)	26,135	64,436

Income tax calculated at domestic tax rates applicable to (losses) profits in the respective countries	(62,589)	7,606	14,011
Tax losses where no deferred income tax is recognised	16,325	148	328
Effect of currency translation on tax base	6,776	(8,128)	(5,146)
Expiration of tax loss carry-forwards	-	-	1,988
Changes in the income tax rate (Note 15)	625	691	-
Non recoverable tax loss carry-forwards	15,537	-	-
Non-taxable results ⁽¹⁾	6,272	4,878	3,973
Income tax	(17,054)	5,195	15,154

⁽¹⁾

Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities.

Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Income tax rates in those countries where the Group operates (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 39%.

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

Amounts in US$ '000	2015	2014	2013
Argentina	3,834	6,707	10,259
Chile ⁽¹⁾	209,910	105,293	15,935
Brazil ⁽¹⁾	-	3,191	-
Total tax losses at 31 December	213,744	115,191	26,194

⁽¹⁾ Taxable losses have no expiration date.

At the balance sheet date deferred tax assets in respect of tax losses in Argentina and in certain Companies in Chile have not been recognised as there is insufficient evidence of future taxable profits before the statute of limitation of these tax losses causes them to expire.

Note

Income Tax (continued)

Expiring dates for tax losses accumulated at 31 December 2015 are:

Expiring date	Amounts in US$ '000
2016	986
2017	1,301
2020	1,547

Note

Deferred income tax

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

Amounts in US$ '000	2015	2014
Deferred tax at 1 January	3,130	(9,729)
Acquisition of subsidiaries	-	(3,132)
Reclassification ⁽¹⁾	(6,061)	(2,123)
Currency translation differences	(3,694)	(265)
Income statement credit	24,316	18,379
Deferred tax at 31 December	17,691	3,130

⁽¹⁾ Corresponds to differences between income tax provision and the final tax return presented.

The breakdown and movement of deferred tax assets and liabilities as of 31 December 2015 and 2014 are as follows:

Amounts in US$ '000	At the beginning of year	Currency translation differences	(Charged) / credited to net profit	At end of year
Deferred tax assets
Difference in depreciation rates and other	1,434	-	30,314	31,748
Taxable losses	31,761	(3,694)	(25,169)	2,898
Total 2015	33,195	(3,694)	5,145	34,646
Total 2014	13,358	(423)	20,260	33,195

Note

Deferred income tax (continued)

Amounts in US$ '000	At the beginning of year	Acquisition of subsidiaries	(Charged) / credited to net profit	Reclassification ⁽¹⁾	Currency translation differences	At end of year
Deferred tax liabilities
Difference in depreciation rates and other	(34,717)	-	10,110	(1,409)	-	(26,016)
Taxable losses	4,652	-	9,061	(4,652)	-	9,061
Total 2015	(30,065)	-	19,171	(6,061)	-	(16,955)
Total 2014	(23,087)	(3,132)	(1,881)	(2,123)	158	(30,065)

⁽¹⁾ Corresponds to differences between income tax provision and the final tax return presented.

Note

Earnings per share

Amounts in US$ '000 except for shares	2015	2014	2013
Numerator:
(Loss) Profit for the year attributable to owners	(234,031)	8,085	22,521
Denominator:
Weighted average number of shares used in basic EPS	57,759,001	56,396,812	43,603,846
(Losses) Earnings after tax per share (US$) – basic	(4.05)	0.14	0.52

Amounts in US$ '000 except for shares	*2015 ^()**	2014	2013
Weighted average number of shares used in basic EPS	57,759,001	56,396,812	43,603,846
Effect of dilutive potential common shares
Stock awards at US$ 0.001	-	2,443,600	2,928,203
Weighted average number of common shares for the purposes of diluted earnings per shares	57,759,001	58,840,412	46,532,049
Earnings after tax per share (US$) – diluted	(4.05)	0.14	0.48

⁽¹⁾ For the year ended 31 December 2015, there were 1,032,279 of potential shares that could have a dilutive impact but were considered antidilutive due to negative earnings.

Note

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	Exploration and evaluation assets⁽²⁾	Total
Cost at 1 January 2013	344,371	3,576	86,949	3,198	54,025	93,106	585,225

Additions	9,367	2,060	512	-	89,976	133,301	235,216
Disposals	(553)	(22)	(15,870)^(*)	-	-	-	(16,445)
Write-off / Impairment loss	-	-	-	-	-	(10,962)^(a)	(10,962)
Transfers	140,075	117	27,246	3,820	(103,572)	(67,686)	-
Cost at 31 December 2013	493,260	5,731	98,837	7,018	40,429	147,759	793,034

Additions	3,013	3,367	11	490	136,232	97,919	241,032
Acquisition of subsidiaries	112,646	201	-	-	-	-	112,847
Currency translation differences	(21,941)	(122)	-	-	-	(988)	(23,051)
Disposals	-	(353)	(666)	-	-	-	(1,019)
Write-off / Impairment loss	(9,430)	-	-	-	-	(30,367)^(b)	(39,797)
Transfers	172,399	3,233	13,464	2,019	(117,236)	(73,879)	-
Cost at 31 December 2014	749,947	12,057	111,646	9,527	59,425	140,444	1,083,046

Additions	(4,640)⁽¹⁾	954	-	272	36,543	12,299	45,428
Currency translation differences	(27,522)	(182)	(2,577)	(92)	-	(1,510)	(31,883)
Disposals	(241)	(13)	(1,685)	(84)	-	-	(2,023)
Write-off / Impairment loss	(128,956)	-	(13,242)	-	(7,376)	(30,084)^(c)	(179,658)
Transfers	60,404	929	30,690	895	(58,769)	(34,149)	-
Cost at 31 December 2015	648,992	13,745	124,832	10,518	29,823	87,000	914,910
Depreciation and write-down at 1 January 2013	(98,156)	(1,836)	(26,336)	(1,060)	-	-	(127,388)
Depreciation	(59,234)	(964)	(9,341)	(661)	-	-	(70,200)
Depreciation and write-down at 31 December 2013	(157,390)	(2,800)	(35,677)	(1,721)	-	-	(197,588)
Depreciation	(89,651)	(1,862)	(9,621)	(523)	-	-	(101,657)
Disposals	-	278	151	-	-	-	429
Currency translation differences	6,602	(65)	-	-	-	-	6,537
Depreciation and write-down at 31 December 2014	(240,439)	(4,449)	(45,147)	(2,244)	-	-	(292,279)
Depreciation	(84,849)	(2,850)	(15,467)	(874)	-	-	(104,040)
Disposals	-	8	-	15	-	-	23
Currency translation differences	4,115	(26)	-	(92)	-	-	3,997
Depreciation and write-down at 31 December 2015	(321,173)	(7,317)	(60,614)	(3,195)	-	-	(392,299)
Carrying amount at 31 December 2013	335,870	2,931	63,160	5,297	40,429	147,759	595,446
Carrying amount at 31 December 2014	509,508	7,608	66,499	7,283	59,425	140,444	790,767
Carrying amount at 31 December 2015	327,819	6,428	64,218	7,323	29,823	87,000	522,611

Note

Property, plant and equipment (continued)

^(*) During 2013, the Company entered into a finance lease for which it has transferred a substantial portion of the risk and rewards of some assets which had a book value of US$ 14,100,000. In 2014, the finance lease finalized when the purchase option on the assets subject to the agreement was exercised by the lessee.

⁽¹⁾ Corresponds to the effect of change in estimate of assets retirement obligations in Colombia.

⁽²⁾ Exploration wells movement and balances are shown in the table below; seismic and other exploratory assets amount to US$ 64,094,000 (US$ 99,939,000 in 2014 and US$ 117,841,000 in 2013).

Amounts in US$ '000	Total
Exploration wells at 31 December 2013	29,918
Additions	87,741
Write-offs	(24,339)
Transfers	(52,815)
Exploration wells at 31 December 2014	40,505
Additions	16,067
Write-offs	(6,280)
Transfers	(27,386)
Exploration wells at 31 December 2015	22,906

As of 31 December 2015, there were seven exploratory wells that have been capitalised for a period over a year amounting to US$ 19,273,000 and three exploratory wells that have been capitalised for a period less than a year amounting to US$ 3,633,000.

^(a) Corresponds to the cost of five unsuccessful exploratory wells: two of them in Chile (one in Fell Block and one in Tranquilo Block) and three of them in Colombia (one well in Cuerva Block, one well in each of the non-operated blocks, Arrendajo and Llanos 32).

^(b) Corresponds to the cost of ten unsuccessful exploratory wells: eight of them in Chile (three in Flamenco Block, two in Fell Block, two in Tranquilo Block and one in Campanario Block) and two of them in Colombia (two in the non-operated Arrendajo Block). The charge also includes the loss generated by the write-off of the remaining seismic cost for Otway and Tranquilo Blocks, registered in previous years.

^(c) Corresponds to the cost of two unsuccessful exploratory wells in Colombia (one well in CPO4 Block and one well in Llanos 32). The charge also includes the loss generated by the write-off of the seismic cost for Flamenco Block in Chile generated by the relinquishment of 143 sq km in November 2015 and the write off of two wells drilled in previous years in the same block for which no additional work would be performed.

Note

Subsidiary undertakings

The following chart illustrates main companies of the Group structure as of 31 December 2015:

(*) LGI is not a subsidiary, it is Non-controlling interest.

Note

Subsidiary undertakings (continued)

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

	Name and registered office	Ownership interest
Subsidiaries	GeoPark Argentina Limited – Bermuda	100%
	GeoPark Argentina Limited – Argentinean Branch	100% (a)
	GeoPark Latin America Limited	100%
	GeoPark Latin America Limited – Agencia en Chile	100% (a)
	GeoPark S.A. (Chile)	100% (a) (b)
	GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil)	100% (a) (f)
	GeoPark Chile S.A. (Chile)	80% (a) (c)
	GeoPark Fell S.p.A. (Chile)	80% (a) (c)
	GeoPark Magallanes Limitada (Chile)	80% (a) (c)
	GeoPark TdF S.A. (Chile)	68.8% (a) (d)
	GeoPark Colombia S.A. (Chile)	100% (a)
	GeoPark Colombia SAS (Colombia)	100% (a) (h)
	GeoPark Brazil S.p.A. (Chile)	100% (a) (b)
	GeoPark Latin America Coöperatie U.A. (The Netherlands)	100%
	GeoPark Colombia Coöperatie U.A. (The Netherlands)	100% (a) (c)
	GeoPark S.A.C. (Peru)	100% (a)
	GeoPark Perú S.A.C. (Peru)	100% (a)
	GeoPark Operadora del Perú S.A.C. (Peru)	100% (a)
	GeoPark Peru Coöperatie U.A. (The Netherlands)	100%
	GeoPark Brazil Coöperatie U.A. (The Netherlands)	100%
	GeoPark Colombia E&P S.A.(Panama)	100% (b)
Joint operations	Tranquilo Block (Chile)	50% (e)
	Flamenco Block (Chile)	50% (e)
	Campanario Block (Chile)	50% (e)
	Isla Norte Block (Chile)	60% (e)
	Llanos 17 Block (Colombia)	36.84%
	Yamu/Carupana Block (Colombia)	89.5%/100% (e)
	Llanos 34 Block (Colombia)	45% (e)
	Llanos 32 Block (Colombia)	10%
	CPO-4 Block (Colombia)	50% (e)
	Puelen (Argentina)	18%
	Sierra del Nevado (Argentina)	18%
	CN-V (Argentina)	50%
	Manati Field (Brazil)	10%

(a)

Indirectly owned.

(b)

Dormant companies.

(c)

LG International has 20% interest.

(d)

LG International has 20% interest through GeoPark Chile S.A. and a 14% direct interest, totaling 31.2%.

(e)

GeoPark is the operator in all blocks.

(f)

On 17 December 2014, the ANP approved the transfer of cession of rights of the Block from Rio das Contas to GeoPark Brazil. On 31 January 2015, both companies, Rio das Contas and GeoPark Brazil were merged into GeoPark Brazil.

Note

Prepaid taxes

Amounts in US$ '000	2015	2014
V.A.T.	14,486	8,884
Income tax payments in advance	4,844	4,834
Other prepaid taxes	1,037	994
Total prepaid taxes	20,367	14,712
Classified as follows:
Current	19,195	13,459
Non current	1,172	1,253
Total prepaid taxes	20,367	14,712

Note

Inventories

Amounts in US$ '000	2015	2014
Crude oil	2,120	6,719
Materials and spares	2,144	1,813
	4,264	8,532

Note

Trade receivables and Prepayments and other receivables

Amounts in US$ '000	2015	2014
Trade receivables	13,480	36,917
	13,480	36,917
To be recovered from co-venturers (Note 32)	4,634	5,931
Related parties receivables (Note 32)	38	-
Prepayments and other receivables	6,605	8,411
	11,277	14,342
Total	24,757	51,259

Classified as follows:
Current	24,537	50,910
Non current	220	349
Total	24,757	51,259

Trade receivables that are aged by less than three months are not considered impaired. As of 31 December 2015, trade receivables of US$ 51,000 (US$ 6,092 in 2014) were aged by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no balances due between 31 days and 90 days as of 31 December 2015 and 2014.

Note

Trade receivables and Prepayments and other receivables (continued)

Movements on the Group provision for impairment are as follows:

Amounts in US$ '000	2015	2014
At 1 January	774	33
Foreign exchange income	(178)	-
Allowance for doubtful accounts (Note 13)	-	741
	596	774

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

Financial instruments by category

Amounts in US$ '000	Loans and receivables
		2015	2014
Assets as per statement of financial position
Trade receivables		13,480	36,917
To be recovered from co-venturers (Nota 32)		4,634	5,931
Other financial assets ^(*)		14,424	12,979
Cash at bank and in hand		82,730	127,672
		115,268	183,499

^(*) Other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations. Non current financial assets also include a non current account receivable. Current financial assets corresponds to short term investments with original maturities up to three months.

Note

Financial instruments by category (continued)

Amounts in US$ '000	Other financial liabilities at amortised cost
	2015	2014
Liabilities as per statement of financial position
Trade payables	25,906	64,457
Payables to related parties (Note 32)	21,045	16,591
To be paid to co-venturers (Note 32)	113	1,335
Borrowings	378,673	369,593
	425,737	451,976

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	2015	2014
Trade receivables
Counterparties with an external credit rating (Moody’s)
Ba2	-	11,793
B3	5,834	-
Baa3	6,315	11,292
Counterparties without an external credit rating
Group1 ^(*)	1,331	13,832
Total trade receivables	13,480	36,917

^(*) 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.

Note

Financial instruments by category (continued)

Cash at bank and other financial assets ⁽¹⁾
Amounts in US$ '000	2015	2014
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services)
A1	862	17
A2	46,272	22,621
Aa2	460	-
A3	1,675	-
Ba1	3,705	-
Baa1	105	40,402
Baa3	29,425	42,218
Caa2	160	21,145
BBB-	56	-
BRC 1+	-	994
Counterparties without an external credit rating	14,424	13,142
Total	97,144	140,539

⁽¹⁾ The remaining balance sheet item ‘cash at bank and in hand’ corresponds to cash on hand amounting to US$ 10,000 (US$ 112,000 in 2014).

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 31 December 2015
Borrowings	42,865	44,419	391,988	-
Trade payables	25,906	-	-	-
Payables to related parties	1,561	1,561	25,094	-
	70,332	45,980	417,082	-
At 31 December 2014
Borrowings	41,124	40,342	109,152	322,500
Trade payables	64,457	-	-	-
Payables to related parties	1,325	1,325	17,226	-
	106,906	41,667	126,378	322,500

Note

Share capital

Issued share capital	2015	2014
Common stock (amounts in US$ ‘000)	59	58
The share capital is distributed as follows:
Common shares, of nominal US$ 0.001	59,535,614	57,790,533
Total common shares in issue	59,535,614	57,790,533

Authorised share capital
US$ p0er share	0.001	0.001

Number of common shares (US$ 0.001 each)	5,171,949,000	5,171,949,000
Amount in US$	5,171,949	5,171,949

Details regarding the share capital of the Company are set out below:

Common shares

As of 31 December 2015, 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 2013			43.9	44
IPO	Feb 2014	14.0	57.9	58
Stock awards	Feb 2014	0.0	57.9	58
Buyback program	Dec 2014	(0.1)	57.8	58
Shares outstanding at the end of 2014			57.8	58
Stock awards	Nov 2015	1.5	59.3	59
Stock awards	Dec 2015	0.5	59.8	60
Stock awards	Dec 2015	0.1	59.9	60
Buyback program	Dec 2015	(0.4)	59.5	59
Shares outstanding at the end of 2015			59.5	59

Note

Share capital (continued)

Stock Award Program and Other Share Based Payments

On 29 October 2013, the Company put into place an irrevocable, non-discretionary share purchase program for the purchase of its common shares for the account of the EBT. This Purchase Program expired on 31 December 2013. The common shares purchased under the program will be used to satisfy future awards under the incentive schemes. During 2013, the Company purchased 50,000 common shares for a total amount of US$ 440,000.

Under the stock awards programs and other share based payments, during 2013, 60,000 new common shares were issued, pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 506,630.

On 12 November 2015 and 22 December 2015, 817,600 and 478,000 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 11,359,000 and US$ 3,577,000, respectively. On 17 September 2013, 295,599 common shares were allotted to the trustee of the EBT, generating a share premium of US$ 3,441,689.

On 30 November 2015 720,000 new common shares were issued to the Executive Directors, generating a share premium of US$ 7,309,000.

During 2015, the Company issued 99,555 (2,301 in 2014 and 10,430 in 2013) shares to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 486,692 (US$ 22,413 in 2014 and US$ 100,988 in 2013). The amount of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period.

IPO

On 7 February 2014, the SEC declared effective the Company’s registration statement upon which 13,999,700 shares were issued at a price of US$ 7 per share, including over-allotment option. Gross proceeds from the offering totalled US$ 98,000,000.

Buyback Program

On 19 December 2014, the Company approved a program to repurchase up to US$ 10,000,000 of common shares, par value US$ 0.001 per share of the Company (the “Repurchase Program”). The Repurchase Program began on 19 December 2014 and was resumed on 14 April 2015 and then on 10 June 2015, expiring on 18 August 2015. The Shares repurchased will be used to offset, in part, any expected dilution effects resulting from the Company’s employee incentive schemes, including grants under the Company’s Stock Award Plan and the Limited Non-Executive Director Plan. During 2015 and 2014, the Company purchased 370,074 and 73,082 common shares for a total amount of US$ 1,615,000 and US$ 388,000, respectively. These transactions had no impact on the Company’s results.

Note

Borrowings

Amounts in US$ '000	2015	2014
Outstanding amounts as of 31 December
Notes GeoPark Latin America Agencia en Chile (a)	302,495	300,963
Banco Itaú (b)	69,142	68,540
Banco de Crédito e Inversiones (c)	-	90
Banco de Chile (d)	7,036	-
	378,673	369,593
Classified as follows:
Current	35,425	27,153
Non current	343,248	342,440

The fair value of these financial instruments at 31 December 2015 amounts to US$ 352,410,000 (US$ 360,181,000 in 2014). The fair values are based on cash flows discounted using a rate based on the borrowing rate of 7.51% (2014: 7.40%) and are within level 2 of the fair value hierarchy.

(a) During February 2013, the Company successfully placed US$ 300,000,000 notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws.

The Notes, issued by the Company's wholly-owned subsidiary GeoPark Latin America Limited Agencia en Chile ("the Issuer"), were priced at 99.332% and carry a coupon of 7.50% per annum (yield 7.625% per annum). Final maturity of the notes will be 11 February 2020. The Notes are guaranteed by GeoPark Limited and GeoPark Latin America Cooperatie U.A. and are secured with a pledge of all of the equity interests of the Issuer in GeoPark Chile S.A. and GeoPark Colombia S.A. and a pledge of certain intercompany loans. The debt issuance cost for this transaction amounted to US$ 7,637,000. The indenture governing our Notes due 2020 includes incurrence test covenants that provides among other things, that, the Debt to EBITDA ratio should not exceed 2.5 times and the EBITDA to Interest ratio should exceed 3.5 times. As of the date of these consolidated financial statements, the Company’s Debt to EBITDA ratio was 5.1 times and the EBITDA to Interest ratio was 2.4 times, primarily due to the lower oil prices that impacted the Company’s EBITDA generation. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, as specified in the indenture governing the Notes. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others, (other than in each case, certain specific exceptions). As of the date of these consolidated financial statements, the Company is in compliance of all the indenture’s provisions.

Note

Borrowings (continued)

(b) During March 2014, GeoPark executed a loan agreement with Itaú BBA International for US$ 70,450,000 to finance the acquisition of a 10% working interest in the Manatí field in Brazil. The interest rate applicable to this loan is LIBOR plus 3.9% per annum. The interest will be paid semi-annually; principal will be cancelled semi-annually with a year grace period. The debt issuance cost for this transaction amounted to US$ 3,295,000. The facility agreement includes customary events of default, and requires the Brazilian subsidiary to comply with customary covenants, including the maintenance of a ratio of net debt to EBITDA of up to 3.5x for the first two years and up to 3.0x thereafter. The credit facility also limits the borrower’s ability to pay dividends if the ratio of net debt to EBITDA is greater than 2.5x. As of the date of these consolidated financial statements, the Company has complied with these covenants.

In March 2015, the Company reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting to approximately US$ 15,000,000), which will be divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) increase the variable interest rate to six-month LIBOR + 4.0%.

(c) During October 2007, GeoPark executed a mortgage loan agreement with Banco de Crédito e Inversiones (BCI), a Chilean private bank, for the acquisition of the operational base in Fell Block. The loan was granted in Chilean pesos and is repayable over a period of 8 years. The interest rate applicable to this loan is 6.6%. The mortgage loan was fully repaid on October 2015.

(d) During December 2015, GeoPark executed a loan agreement with Banco de Chile for US$ 7,028,000 to finance the start-up of new Ache gas field in GeoPark-operated Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per annum. The interest and the principal will be paid on monthly basis; with a six months grace period, with final maturity on December 2017.

As of the date of these consolidated financial statements, the Group has available credit lines for over US$ 37,000,000.

Note

Provisions and other long-term liabilities

Amounts in US$ ‘000	Asset retirement obligation	Deferred Income	Other	Total
At 1 January 2014	24,166	6,204	2,706	33,076
Addition to provision	1,603	-	5,934	7,537
Recovery of abandonments costs	(1,317)	-	-	(1,317)
Acquisition of subsidiaries	6,862	-	-	6,862
Foreign currency translation	(1,170)	-	-	(1,170)
Exchange difference	1,170	-	(752)	418
Amortisation	-	(468)	-	(468)
Unwinding of discount	1,972	-	-	1,972
At 31 December 2014	33,286	5,736	7,888	46,910
Addition to provision	985	-	293	1,278
Recovery of abandonments costs	(5,229)	-	-	(5,229)
Foreign currency translation	(2,469)	-	-	(2,469)
Exchange difference	2,469	-	(2,381)	88
Amortisation	-	(703)	-	(703)
Unwinding of discount	2,575		-	2,575
At 31 December 2015	31,617	5,033	5,800	42,450

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. The amortisation is in line with the related asset.

Other mainly relates to fiscal controversies associated to income taxes in one of the Colombian subsidiaries. These controversies relate to fiscal periods prior to the acquisition of these subsidiaries by the Company. In connection to this, the Company has recorded an account receivable for an amount of US$ 5,636,000, with the previous owners for the same amount, which is recognized under other financial assets in the balance sheet.

Note

Trade and other payables

Amounts in US$ '000	2015	2014
V.A.T	908	3,449
Trade payables	25,906	64,457
Payables to related parties ⁽¹⁾(Note 32)	21,045	16,591
Staff costs to be paid	6,702	7,226
Royalties to be paid	2,475	2,398
Taxes and other debts to be paid	8,197	10,031
To be paid to co-venturers	113	1,335
	65,346	105,487
Classified as follows:
Current	45,790	88,904
Non current	19,556	16,583

⁽¹⁾

The outstanding amount corresponds to a loan granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks. The maturity of this loan is July 2020 and the applicable interest rate is 8% per annum.

The average credit period (expressed as creditor days) during the year ended 31 December 2015 was 38 days (2014: 50 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

Share-based payment

IPO Award Program and Executive Stock Option plan

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

Stock Award Program and Other Share Based Payments

During 2008, GeoPark Shareholders voted to authorize the Board to use up to 12% of the issued share capital of the Company at the relevant time for the purposes of the Performance-based Employee Long-Term Incentive Plan.

Note

Share-based payment (continued)

Main characteristics of the Stock Awards Programs are:

All employees are eligible.

Exercise price is equal to the nominal value of shares.

Vesting period is four years.

Specific Award amounts are reviewed and approved by the Executive Directors and the Remuneration Committee of the Board of Directors.

On 23 November 2012, the Remuneration Committee and the Board of Directors approved granting 720,000 options over ordinary shares of US$0.001 each to the Executive Directors. Options granted vest on the third anniversary of the date on which they are granted and have an exercise price of US$0.001. On 30 November 2015, the options were exercised and the shares were issued.

Additionally, during 2013 the Company approved two new share-based compensation programs: i.) a stock awards plan oriented to Managers (non-Top Management) and key employees who qualifies as an equity-settled plan and ii.) a cash awards plan, oriented to all non-management employees which qualifies as a cash-settled plan.

Main characteristics of these news plans are:

Exercise price: US$ 0.001

Grant date: July 2013

Grant price: £ 5.8

Vesting date: 31 December 2015

Conditions to be able to exercise:

Continue to be an employee

Obtain the Company minimum Production, Adjusted EBITDA and Reserves target for the year of vesting

The stock market price at the date of vesting should be higher than the share price at the price of grant

Amount of shares for equity-settled plan: 500,000

Estimated equivalent amount of shares for cash-settled plan: 500,000

Also during 2013, the Company approved a plan named Value Creation Plan (“VCP”) oriented to Top Management. The VCP establishes awards payables in a variable number of shares with some limitation, subject to certain market conditions, among others, reach certain stock market price for the Company share at vesting date. VCP has been classified as an equity-settled plan.

Note

Share-based payment (continued)

On 10 December 2015, after full discussion by the Compensation Committee regarding programs´ conditions, the Committee confirmed conditions will not be archived (mainly impacted by oil international prices) to execute these programs.

On 19 December 2014, the Company has approved a new share-based compensation program for 500,000 shares oriented to new employees. This new program, which was granted on 31 December 2014, has a vesting period of three years.

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 profit
Year of issuance	Awards at the beginning	Awards granted in the year	Awards forfeited	Awards exercised	Awards at year end	2015	2014	2013
2014	500,000	-	-	-	500,000	898	-	-
2013	478,000	-	478,000	-	-	594	1,291	619
2012	428,000	-	48,500	-	379,500	636	1,102	1,296
2011	478,000	-	-	478,000	-	879	848	893
2010	817,600	-	-	817,600	-	-	2,623	2,779
Subtotal						3,007	5,864	5,587
Stock options to Executive Directors	720,000	-	-	720,000	-	2,390	2,474	2,365
Shares granted to Non-Executive Directors	23,958	83,882	-	99,555	8,285	371	223	101
VCP	-	-	-	-	-	617	617	309
Executive Directors Bonus	-	123,839	-	-	123,839	400	-	-
Key Management Bonus	-	445,185	-	-	445,185	1,438	-	-
	3,445,558	652,906	526,500	2,115,155	1,456,809	8,223	9,178	8,362

The awards that are forfeited correspond to employees that had left the Group before vesting date, except for the ones related to the 2013 program that are forfeited because the conditions were not achieved.

Note

Interests in Joint operations

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

In Chile, GeoPark is the operator in all the blocks. In Colombia, GeoPark is the operator in Llanos 34 and Yamu/Carupana blocks.

The following amounts represent the Company’s share in the assets, liabilities and results of the joint operations which have been consolidated line by line in the consolidated statement of financial position and statement of income:

Subsidiary / Joint operation	Interest	PP&E E&E Assets	Other Assets	Total Assets	Current Liabilities	Total Liabilities	NET ASSETS/ (LIABILITIES)	Net revenue	Operating (loss) profit
2015
GeoPark Magallanes Ltda.
Tranquilo Block	50%	-	45	45	(2)	(2)	43	-	(69)
GeoPark TdF S.A.
Flamenco Block	50%	14,932	-	14,932	(53)	(53)	14,879	1,810	(51,411)
Campanario Block	50%	27,570	-	27,570	(10)	(10)	27,560	13	(7,267)
Isla Norte Block	60%	8,583	-	8,583	(16)	(16)	8,567	355	(5,661)
Colombia SAS
Llanos 17 Block	36.84%	-	-	-	(93)	(93)	(93)	3	(6,325)
Yamu/Carupana Block	89,5%	3,569	2,061	5,630	(2,235)	(2,235)	3,395	1,409	(16,552)
Llanos 34 Block	45%	76,667	429	77,096	(3,295)	(3,295)	73,801	114,276	53,049
Llanos 32 Block	10%	3,106	96	3,202	(213)	(213)	2,989	8,258	(1,343)
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field	10%	50,801	12,930	63,731	(10,395)	(10,395)	53,336	32,388	20,354

Note

Interests in Joint operations (continued)

Subsidiary / Joint operation	Interest	PP&E E&E Assets	Other Assets	Total Assets	Current liabilities	Total Liabilities	NET ASSETS/ (LIABILITIES)	Net revenue	Operating (loss) profit
2014
GeoPark Magallanes Ltda.
Tranquilo Block	50%	109	-	109	(125)	(125)	(16)	-	(220)
GeoPark TdF S.A.
Flamenco Block	50%	35,110	-	35,110	(1,653)	(1,653)	33,457	4,385	(6,278)
Campanario Block	50%	34,309	-	34,309	(7,086)	(7,086)	27,223	216	(6,151)
Isla Norte Block	60%	12,208	-	12,208	(241)	(241)	11,967	901	(283)
Colombia SAS
Llanos 17 Block	36.84%	6,037	-	6,037	(122)	(122)	5,915	1,292	(160)
Yamu/Carupana Block	90% - 79.5%	16,590	2,211	18,801	(2,727)	(2,727)	16,074	10,560	(2,916)
Llanos 34 Block	45%	76,726	1,514	78,240	(3,380)	(3,380)	74,860	176,624	96,889
Llanos 32 Block	10%	8,909	27	8,936	(122)	(122)	8,814	11,024	4,041
GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field	10%	46,382	43,891	90,273	(11,587)	(11,587)	78,686	35,621	18,935
2013
GeoPark Magallanes Ltda.
Tranquilo Block	29%	15,255	210	15,465	(391)	(391)	15,074	-	(275)
GeoPark TdF S.A.
Flamenco Block	50%	42,048	-	42,048	(2,537)	(2,537)	39,511	243	(239)
Campanario Block	50%	17,172	-	17,172	(405)	(405)	16,767	-	-
Isla Norte Block	60%	4,497	-	4,497	(303)	(303)	4,194	-	-
Colombia SAS
Llanos 17 Block	36.84%	6,448	29	6,477	-	-	6,477	1,407	(544)
Yamu/Carupana Block	75% - 54.50%	15,476	482	15,958	-	-	15,958	17,727	2,127
Llanos 34 Block	45%	51,963	1,129	53,092	-	-	53,092	78,390	39,192
Llanos 32 Block	10%	4,993	-	4,993	-	-	4,993	5,507	1,035

Capital commitments are disclosed in Note 31 (b).

Note

Commitments

(a) Royalty commitments

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 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 in connection with 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 Company 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%

Note

Commitments (continued)

(a) Royalty commitments (continued)

Additionally, under the terms of the Winchester Stock Purchase Agreement, we are 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 both an earnings based measure and 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 Company’s best estimate of the total commitment over the remaining life of the concession is in a range between US$ 50,000,000 and US$ 60,000,000. During 2015, the Company has accrued and paid US$ 7,100,000 (US$ 24,600,000 in 2014 and US$ 11,500,000 in 2013) and US$ 9,200,000 (US$ 21,000,000 in 2014 and US$ 7,800,000 in 2013), respectively.

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 particular concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Manatí Block, royalties are calculated at 7.5% of gas production.

In Argentina, crude oil production accrues royalties payable to the Provinces of Santa Cruz and Mendoza equivalent to 12% on estimated value at well head of those products. This value is equivalent to final sales price less transport, storage and treatment costs.

(b) Capital commitments

Chile

On 18 August 2015, the Chilean Ministry accepted the Company’s proposal to extend the first exploratory period in the Campanario Block and Isla Norte Block for an additional period of 18 months. The future investment commitments assumed by GeoPark outstanding are up to:

Campanario Block: 3 exploratory wells before 11 July 2017 (US$ 11,880,000)

Isla Norte Block: 2 exploratory wells before 7 May 2017 (US$ 6,480,000)

The investments made in the first exploratory period will be assumed 100% by GeoPark. As of 31 December 2015, the Company has established a guarantee for its commitments that amounts to US$ 17,500,000.

Note

Commitments (continued)

(b) Capital commitments (continued)

On 6 January 2016, the Chilean Ministry accepted the Company’s proposal for the commitments related to the second exploratory phase in the Flamenco Block which commenced on 8 November 2015. The investment related to the drilling of one exploratory well will be assumed 100% by GeoPark and shall be made before 7 November 2017. The remaining commitment amounts to US$ 2,100,000.

Colombia

The Llanos 62 Block (100% working interest) has committed to drill two exploratory wells before June 2016. The remaining commitment amounts to US$ 6,000,000.

The VIM 3 Block minimum investment program consists of 200 sq km of 2D seismic and drilling one exploratory well, with a total estimated investment of US$ 22,200,000 during the initial three year exploratory period ending in September 2018.

The Llanos 34 Block (45% working interest) has committed to drill two exploratory wells before September 2017. The remaining commitment amounts to US$ 4,320,000 at GeoPark’s working interest.

Brazil

On 14 May 2013, the ANP awarded GeoPark seven new concessions in Brazil in an international bidding round, Round 11. For these seven concessions, GeoPark committed to invest a minimum of US$ 17,000,000 (including bonuses and work program commitment for the first exploratory phase). During this first exploratory phase, that lasts three years, GeoPark has already invested US$ 6,300,000 in seismic and US$ 4,500,000 in bonuses paid to ANP.

For SEAL-T-268 Block, awarded on 28 November 2013 by the ANP in the international bidding Round 12, GeoPark has committed to invest a minimum of US$ 700,000 (including bonus and work program commitments) during the first exploratory period ending May 2017.

In October 2015, the Company was awarded four new exploratory blocks in the Brazil Bid Round 13. GeoPark has committed to invest for the new blocks, a minimum of approximately US$ 2,500,000 (including bonus and work program commitments) during the first exploratory period ending December 2018. GeoPark has already invested US$ 370,000 in signature bonus paid to ANP.

Note

Commitments (continued)

(b) Capital commitments (continued)

Argentina

On 20 August 2014, the consortium of GeoPark and Pluspetrol was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina de Energia S.A. ("EMESA"). The consortium consists of Pluspetrol (Operator with a 72% working interest ("WI"), EMESA (Non-operated with a 10% WI) and GeoPark (Non-operated with an 18% WI).

GeoPark has committed to a minimum aggregate investment of US$ 6,200,000 for its WI, which includes the work program commitment on both blocks during the first three years of the exploratory period.

On 22 July 2015, the Company signed a farm-in agreement with Wintershall for the CN-V Block in Argentina. GeoPark will operate during the exploratory phase and receive a 50% working interest in the CN-V Block in exchange for its commitment to drill two exploratory wells, for a total of US$ 10,000,000.

(c) Operating lease commitments – Group company as lessee

The Group leases various plant and machinery under non-cancellable operating lease agreements.

The Group also leases offices under non-cancellable operating lease agreements. The lease terms are between 2 and 3 years, and the majority of lease agreements are renewable at the end of the lease period at market rate.

During 2015 a total amount of US$ 16,731,000 (US$ 19,409,000 in 2014 and US$19,110,000 in 2013) was charged to the income statement and US$ 7,102,000 of operating leases were capitalised as Property, plant and equipment (US$ 51,341,000 in 2014 and US$ 37,263,000 in 2013).

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

Amounts in US$ ’000	2015	2014	2013
Operating lease commitments
Falling due within 1 year	12,878	37,926	68,817
Falling due within 1 – 3 years	8,257	33,949	56,556
Falling due within 3 – 5 years	2,456	16,109	31,145
Falling due over 5 years	309	505	505
Total minimum lease payments	23,900	88,489	157,023

Note

Related parties

Controlling interest

The main shareholders of GeoPark Limited, a company registered in Bermuda, as of 31 December 2015, are:

Shareholder	Common shares	Percentage of outstanding common shares
Cartica Management LLC⁽¹⁾	9,690,972	16.28%
Gerald E. O’Shaughnessy⁽²⁾	7,871,276	13.22%
James F. Park⁽³⁾	7,891,269	13.25%
IFC Equity Investments⁽⁴⁾	3,456,594	5.81%
Moneda A.F.I.⁽⁵⁾	3,184,650	5.35%
Juan Cristóbal Pavez⁽⁶⁾	2,913,709	4.89%
Other shareholders	24,527,144	41.20%
	59,535,614	100.00%

⁽¹⁾ Held through certain private investment funds managed and controlled by Cartica Management, LLC. Mr. Steven Quamme and Mrs. Farida Khambata, partners at Cartica Management LLC, are deemed to have shared voting and investment power over such shares, added to the shares personally held by each one of them. Mr. Quamme personally holds 20,236 shares and therefore is deemed to beneficially own an aggregate of 9,711,208 shares and Mrs. Farida Khambata personally holds 75,151 shares and therefore is deemed to beneficially own an aggregate of 9,766,123 shares.

⁽²⁾ Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, The Globe Resources Group Inc., and other investment vehicles.

⁽³⁾ Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of our Board of Directors. The number of common shares held by Mr. Park does not reflect the 328,812 common shares held as of 31 December 2015 in the employee benefit trust described under ‘‘Management—Compensation—Employee Benefit Trust’’.

⁽⁴⁾IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff.

⁽⁵⁾ Held through various funds managed by Moneda A.F.I. (Administradora de Fondos de Inversión), an asset manager.

⁽⁶⁾ Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 35,905 common shares held by him personally.

Note

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
2015
To be recovered from co-venturers	-	4,634	Joint Operations	Joint Operations
Prepayments and other receivables	-	38	LGI	Partner
Payables account	-	(21,045)	LGI	Partner
To be paid to co-venturers	-	(113)	Joint Operations	Joint Operations
Financial costs	1,560	-	LGI	Partner
Geological and geophysical expenses	101	-	Carlos Gulisano	Non-Executive Director ^(*)
Administrative expenses	66	-	Carlos Gulisano	Non-Executive Director ^(*)
Administrative expenses	377	-	Pedro Aylwin	Executive Director ^(**)
2014
To be recovered from co-venturers	-	5,931	Joint Operations	Joint Operations
Payables account	-	(16,591)	LGI	Partner
To be paid to co-venturers	-	(1,335)	Joint Operations	Joint Operations
Financial costs	592	-	LGI	Partner
Geological and geophysical expenses	16	-	Carlos Gulisano	Non-Executive Director ^(*)
Administrative expenses	114	-	Carlos Gulisano	Non-Executive Director ^(*)
Administrative expenses	568	-	Pedro Aylwin	Executive Director ^(**)
2013
To be recovered from co-venturers	-	15,508	Joint Operations	Joint Operations
Payables account	-	(8,456)	LGI	Partner
To be paid to co-venturers	-	(1,201)	Joint Operations	Joint Operations
Financial costs	112	-	LGI	Partner
Geological and geophysical expenses	24	-	Carlos Gulisano	Non-Executive Director ^(*)
Administrative expenses	176	-	Carlos Gulisano	Non-Executive Director ^(*)

^(*) Corresponding to consultancy services.

^(**) Corresponding to wages and salaries for US$ 317,000 (US$ 374,000 in 2014) and bonus for US$ 60,000 (US$ 194,000 in 2014).

There have been no other transactions with the Board of Directors, Executive Board, 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 Executive Board and other benefits informed in Note 10.

Note

Fees paid to Auditors

Amounts in US$ '000	2015	2014	2013
Audit fees	557	620	1,091 ^(*)
Tax services fees	129	281	292
Non-audit services fees	-	540	45
Fees paid to auditors	686	1,441	1,428

^(*)Include fees related to the IPO process.

Non-audit services fees relates to due diligence, consultancy and other services for 2014 and 2013.

Note

Business transactions

Colombia

Swap operation

On 19 November 2015, GeoPark’s Colombian subsidiary agreed to exchange its 10% non-operating economic interest in Cerrito Block for additional interests held by Trayectoria, the counterpart in the Yamú Block, operated by GeoPark, that includes a 10% economic interest in all of the Yamú fields. According to the terms of the swap operation, GeoPark written off a receivable with Trayectoria. Following this transaction, GeoPark shall continue to be the operator and have an 89.5% interest in the Carupana Field and 100% in Yamú and Potrillo Fields, all fields located in the Yamú Block. The Company recognized a US$ 296,000 loss as a result of this transaction.

On 29 July 2014, GeoPark’s Colombian subsidiary agreed to exchange its 10% non-operating economic interest in Arrendajo Block for additional interests held by the counterpart in the Yamú Block (GeoPark operated) that includes a 15% economic interest in all of the Yamú fields except for the Carupana field, where the counterparty had a 25% economic interest. According to the terms of the exchange, GeoPark received US$ 3,200,000 in cash from the exchange, adjusted by working capital. Following this transaction, GeoPark shall continue to be the operator and have a 79.5% interest in the Carupana Field and 90% in Yamú and Potrillo Fields, all fields located in the Yamú Block. This transaction had no impact on the results of the Company.

Note

Business transactions (continued)

Brazil

Acquisition in Brazil

GeoPark entered into Brazil with the acquisition of a 10% working interest in the offshore Manati gas field ("Manati Field"), the largest natural gas producing field in Brazil. On 14 May, 2013, GeoPark executed a stock purchase agreement ("SPA") with Panoro Energy do Brazil Ltda., the subsidiary of Panoro Energy ASA, ("Panoro"), a Norwegian listed company with assets in Brazil and Africa, to acquire all of the issued and outstanding shares of its wholly-owned Brazilian subsidiary, Rio das Contas Produtora de Petróleo Ltda ("Rio das Contas"), the direct owner of 10% of the BCAM-40 Block (the "Block"), which includes the shallow-depth offshore Manati Field in the Camamu-Almada basin.

GeoPark has paid a cash consideration of US$ 140 million at 31 March 2014 or the closing date, which was adjusted for working capital with an effective date of 30 April 2013. The agreement also provides for possible future contingent payments by GeoPark over the next five years, depending on the economic performance and cash generation of the Block. The Company has estimated that there are no any future contingent payments at the acquisition date and as of the date of these financial statements either.

The Manati Field is a strategically important, profitable upstream asset in Brazil and currently provides approximately 50% of the gas supplied to the northeastern region of Brazil and more than 75% of the gas supplied to Salvador, the largest city and capital of the northeastern state of Bahia. The field is largely developed with existing producing wells and an extensive pipeline, treatment and delivery infrastructure and is not expected to require significant future capital expenditures to meet current production estimates.

The Manati Field is operated by Petrobras (35% working interest), the Brazilian national company, largest oil and gas operator in Brazil and internationally-respected offshore operator. Other partners in the Block include Queiroz Galvao Exploração e Produção (45% working interest) and Brasoil Manati Exploração Petrolífera S.A. (10% working interest).

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.

Note

Business transactions (continued)

Brazil (continued)

The following table summarises the consideration paid, the fair value of assets acquired and liabilities assumed for the abovementioned transaction:

Amounts in US$ '000	Total
Cash (including working capital adjustments)	140,100
Total consideration	140,100
Cash and cash equivalents	25,133
Property, plant and equipment (including mineral interest)	112,847
Trade receivables	9,757
Prepayments and other receivables	5,945
Other financial assets	950
Deferred income tax liabilities	(3,132)
Trade and other payables	(4,538)
Provision for other long-term liabilities	(6,862)
Total identifiable net assets	140,100

The purchase price allocation above mentioned is final. Acquisition-related costs have been charged to administrative expenses in the consolidated income statement for the year ended 31 December 2012.

The revenue included in the consolidated statement of comprehensive income since acquisition date contributed by the acquired company was US$ 35,621,000 for the year 2014. The acquired company also contributed profit of US$ 18,952,000 over the same period. Had Rio das Contas been consolidated from 1 January 2014 the consolidated statement of income would show pro-forma revenue of US$ 440,298,000 and profit of US$ 23,139,000 for the year 2014.

Round 12

On 28 November 2013, the ANP awarded GeoPark two concessions in the ANP´s 12^th Bid Round. One of these two concessions was the Block PN-T-597. As a result of a class action filed by the Federal Prosecutor’s Office, an injunction was issued by a Brazilian Federal Court against the ANP, the Federal Government and GeoPark Brazil on 13 December 2013. Due to the injunction to which GeoPark Brazil had interpreted that it could not proceed to execution of the concession agreement, GeoPark filed a request to the ANP to suspend the execution of the Concession Agreement. In April 2015, GeoPark was called to have the contract signed, which occurred on 17 July 2015. Notwithstanding all GeoPark efforts to seek for clarification to whether or not the Concession Agreement could be executed according to ANP´s understanding, the judge issued an interlocutory decision on 13 August 2015, with a clear position that the Concession Agreement should not be executed. GeoPark immediately filed a Request towards ANP to annul the signature of the contract and all its effects and revert to the status quo ante, which maintains Geopark´s right to the Block. On 9 October 2015, ANP´s Board issued the Resolution 828/2015 which approved the annulment of the signature of the Contract and revoked the previous Decision that called GeoPark for the signature.

Note

Business transactions (continued)

Brazil (continued)

Round 13

In October 2015, the Company was awarded four new exploratory blocks (covering 30,200 acres) in the Brazil Bid Round 13, complementing the Company’s existing exploration portfolio in the Reconcavo and Potiguar basins. The bidding round was organized by the ANP and all proceedings and bids have been made public. The winning bids are subject to confirmation of qualification requirements.

The awarded blocks were:

Block (Basin)	Working Interest (WI)	Operator
POT-T-747 (Potiguar)	70% (*)	GeoPark
POT-T-882 (Potiguar)	70% (*)	GeoPark
REC-T-93 (Reconcavo)	70%	GeoPark
REC-T-128 (Reconcavo)	70%	GeoPark

(*) 30% WI of proposed partners is subject to ANP approval.

Peru

Entry in Peru

The Company has executed a Joint Investment Agreement and Joint Operating Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in and operate the Morona Block located in northern Peru. GeoPark will assume a 75% working interest (“WI”) of the Morona Block, with Petroperu retaining a 25% WI. The transaction has been approved by the Board of Directors of both Petroperu and GeoPark.

The transaction is subject to customary conditions, certain license modifications and a presidential decree.

The Morona Block, also known as Lote 64, covers an area of 1.9 million acres on the western side of the Marañón Basin, one of the most prolific hydrocarbon basins in Peru.

The Morona Block contains the Situche Central oil field, which has been delineated by two wells (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the Situche Central field, the Morona Block has a large exploration potential with several high impact prospects and plays – with exploration resources currently estimated to range from 200 to 600 mmbo.

Note

Business transactions (continued)

Peru (continued)

The Morona Block includes geophysical surveys of 2,783 km (2D seismic) and 465 sq km (3D seismic), and an operating field camp and logistics infrastructure. The expected work program and development plan for the Situche Central oil field is to be completed in three stages.

The goal of the initial stage will be to put the field into production through a long term test to help determine the most effective overall development plan and to begin to generate cash flow. This initial stage requires an investment of approximately US$ 140,000,000 to US$ 160,000,000 and is expected to be completed within 18 to 24 months after closing. GeoPark has committed to carry Petroperu during this initial phase. The subsequent work program stages, which will be initiated once production has been established, are focused on carrying out the full development of the Situche Central field, including transportation infrastructure, and new exploration drilling of the block. Petroperu will also have the right to increase its WI in the block up to 50%, subject to GeoPark recovering its investments in the block by certain agreed factors.

GeoPark has already been qualified as an Operator by Perupetro, the Peruvian petroleum licensing agency. As of the date of the issuance of these Consolidated Financial Statements, the transaction is pending of approval.

Note

35 Oil industry situation and the impact on GeoPark’s operations

Oil price crisis started in the second half of 2014 and prices fell dramatically, WTI and Brent, the main international oil price markers, fell more than 60% between October 2014 and February 2016. During 2015, prices have remained low and volatile (WTI and Brent fell more than 40% between March 2015 and February 2016). As a consequence of this market conditions, the Company has undertaken a decisive cost cutting program to ensure its ability to both maximize the work program and preserve its liquidity. The main decisions included:

Reduction of its capital investment taking advantage of the discretionary work program.

Deferment of capital projects by regulatory authority and partner agreement.

Renegotiation and reduction of oil and gas service contracts, including drilling and civil work contractors, as well as transportation trucking and pipeline costs.

Operating cost improved efficiencies and temporary suspension of certain marginal producing oil and gas fields.

Further cost reductions are expected to result from a general depreciation of Latin American currencies (Colombian peso, Brazilian real, Chilean peso, Argentine peso and Peruvian sol), in connection with operating and structure costs established in local currencies.

Note

Oil industry situation and the impact on GeoPark’s operations (continued)

During February 2015, the Company reduced its workforce significantly. This reduction streamlined certain internal functions and departments for creating a more efficient workforce in the current economic environment. As a result, the Company achieved cost savings associated with the reduction of full-time and temporary employees, excluding one-time termination costs. Continuous efforts and actions to reduce costs and preserve liquidity have continued throughout the year and will continue in the future.

In addition, actions taken by the Company to maximize ongoing work projects and to reduce expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives included in the cost cutting program adopted may expose the Company to claims and contingencies from interested parties that may have a negative impact on its business, financial condition, results of operations and cash flows. As of the date of these consolidated financial statements, according to internal estimates, the Company has recognized approximately US$ 4,100,000 for future contingent payments in connection with claims of third parties. The mentioned costs are allocated under the other (expenses) income line, included in the Consolidated Statement of Income.

Note

Impairment test on Property, plant and equipment

As a result of the situation described in Note 35, the Company evaluated the recoverability of its fixed assets affected by oil price drop, as such situation constitutes an impairment indicator according to IAS 36 and, consequently, it triggers the need of assessing fair value of the assets involved against their carrying amount.

The Management of the Company considers as Cash Generating Unit (CGU) each of the blocks in which the Group has working or economic interests. The blocks with no material investment on fixed assets or with operations that are not linked to oil prices were not subject to impairment test.

The main assumptions taken into account for the impairment tests for the blocks below mentioned were:

The future oil prices have been calculated taking into consideration the oil curves prices available in the market, provided by international advisory companies, weighted through internal estimations in accordance with price curves used by D&M;

Three price scenarios were projected and weighted in order to minimize misleading: low price, middle price and high price (see below table “Oil price scenarios”);

The table “Oil price scenarios” was based on WTI future price estimations; the Company adjusted this marker price on its model valuation to reflect the effective price applicable in each location (see Note 3 “Price risk”);

The model valuation was based on the expected cash flow approach;

Note

Impairment test on Property, plant and equipment (continued)

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 2016 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 15).

Table Oil price scenarios (*):

	Amounts in US$ per Bbl.
Year	Low price (15%)	Middle price (60%)	High price (25%)	Weighted market price used for the impairment test
2016	35,7	35,7	39,3	36,6
2017	39,0	46,8	57,2	48,3
2018	49,4	59,3	72,5	61,1
2019	53,1	63,7	77,8	65,6
2020	56,7	68,1	83,2	70,2
Over 2021	59,6	71,5	87,4	73,7

(*) The percentages indicated between brackets represent the Company estimation regarding each price scenario.

Summary for impairment:

Country	Carrying amount (US$ million)	Impairment loss (US$ million)	Pre-tax discount rate
Chile	354,3	104,5	12.8%
Brazil	50,8	-	16.2%
Colombia	101,5	45,1	17.1%

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 impairment loss would have been higher by approximately US$ 29,000,000.

Peru and Argentina segments have no associated assets subject to impairment.

Note

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 Company’s oil and gas production activities carried out in Chile, Colombia, Brazil and Argentina.

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

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as of 31 December 2015, 2014 and 2013. 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 well equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.

Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
Year ended 31 December 2015
Acquisition of properties
Proved	-	-	-	-	-
Unproved	-	-	-	-	-
Total property acquisition
Exploration	3,598	14,845	1,103	2,562	22,108
Development	13,315	14,752	56	3,780	31,903
Total costs incurred	16,913	29,597	1,159	6,342	54,011
Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
Year ended 31 December 2014
Acquisition of properties
Proved	-	-	-	112,646	112,646
Unproved	-	-	-	-	-
Total property acquisition	-	-	-	112,646	112,646
Exploration	84,251	14,114	(123)	12,004	110,246
Development	82,742	55,336	126	1,052	139,256
Total costs incurred	166,993	69,450	3	125,702	362,148
Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
Year ended 31 December 2013
Acquisition of properties
Proved	-	-	-	-	-
Unproved	-	-	-	-	-
Total property acquisition	-	-	-	-	-
Exploration	91,140	47,668	(1,917)	1,702	138,593
Development	61,748	37,983	124	-	99,855
Total costs incurred	152,888	85,651	(1,793)	1,702	238,448

⁽¹⁾Includes capitalised amounts related to asset retirement obligations.

Note

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

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

The following table presents the capitalized costs as at 31 December 2015, 2014 and 2013, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
At 31 December 2015
Proved properties
Equipment, camps and other facilities ⁽¹⁾	79,040	42,852	843	2,097	124,832
Mineral interest and wells ⁽¹⁾	367,722	213,480	4,849	62,941	648,992
Other uncompleted projects ⁽¹⁾	21,830	7,703	290	-	29,823
Unproved properties	70,062	8,180	-	8,758	87,000
Gross capitalised costs	538,654	272,215	5,982	73,796	890,647
Accumulated depreciation	(201,138)	(160,759)	(5,654)	(14,236)	(381,787)
Total net capitalised costs	337,516	111,456	328	59,560	508,860

⁽¹⁾

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

Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
At 31 December 2014
Proved properties
Equipment, camps and other facilities	81,998	28,805	843	-	111,646
Mineral interest and wells ⁽¹⁾	426,638	227,755	4,849	90,705	749,947
Other uncompleted projects	37,902	20,204	-	1,053	59,159
Unproved properties	113,403	18,176	-	8,865	140,444
Gross capitalised costs	659,941	294,940	5,692	100,623	1,061,196
Accumulated depreciation	(163,217)	(111,855)	(5,562)	(4,951)	(285,585)
Total net capitalised costs	496,724	183,085	130	95,672	775,611

⁽¹⁾

Includes capitalised amounts related to asset retirement obligations and impairment loss in Colombia for US$ 9,430,000.

Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
At 31 December 2013
Proved properties
Equipment, camps and other facilities	77,481	20,514	843	-	98,838
Mineral interest and wells ⁽¹⁾	310,364	178,048	4,849	-	493,261
Other uncompleted projects	33,176	7,053	-	-	40,229
Unproved properties	109,862	37,853	31	13	147,759
Gross capitalised costs	530,883	243,468	5,723	13	780,087
Accumulated depreciation	(127,447)	(60,150)	(5,470)	-	(193,067)
Total net capitalised costs	403,436	183,318	253	13	587,020

⁽¹⁾

Includes capitalised amounts related to asset retirement obligations.

Note

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 31 December 2015, 2014 and 2013. Income tax for the years presented was calculated utilizing the statutory tax rates.

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

Amounts in US$ '000	Chile	Colombia	Argentina	Brazil	Total
Year ended 31 December 2014
Net revenue	145,720	246,085	1,308	35,621	428,734
Production costs, excluding depreciation
Operating costs	(34,991)	(67,470)	(309)	(5,354)	(108,124)
Royalties	(6,777)	(12,354)	(241)	(2,794)	(22,166)
Total production costs	(41,768)	(79,824)	(550)	(8,148)	(130,290)
Exploration expenses ⁽¹⁾	(36,057)	(4,567)	123	(2,164)	(42,665)
Accretion expense ⁽²⁾	(816)	(547)	-	(609)	(1,972)
Impairment loss for non-financial assets	-	(9,430)	-	-	(9,430)
Depreciation, depletion and amortization	(35,856)	(51,856)	(94)	(11,554)	(99,360)
Results of operations before income tax	31,223	99,861	787	13,146	145,017
Income tax expense	(4,684)	(33,953)	(275)	(4,470)	(43,382)
Results of oil and gas operations	26,539	65,908	512	8,676	101,635

⁽¹⁾

Do not include Peru costs.

⁽²⁾

Represents accretion of ARO liability.

Note

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	Chile	Colombia	Argentina	Brazil	Total
Year ended 31 December 2013
Net revenue	157,491	179,324	1,538	-	338,353
Production costs, excluding depreciation
Operating costs	(30,915)	(62,818)	(92)	-	(93,825)
Royalties	(7,383)	(9,661)	(195)	-	(17,239)
Total production costs	(38,298)	(72,479)	(287)	-	(111,064)
Exploration expenses	(13,138)	(3,341)	1,928	(1,703)	(16,254)
Accretion expense ⁽²⁾	(429)	(880)	(214)	-	(1,523)
Depreciation, depletion and amortization	(29,287)	(39,233)	(59)	-	(68,579)
Results of operations before income tax	76,339	63,391	2,906	(1,703)	140,933
Income tax (expense) benefit	(11,451)	(20,919)	(1,017)	579	(32,808)
Results of oil and gas operations	64,888	42,472	1,889	(1,124)	108,125

⁽²⁾

Represents accretion of ARO liability.

Table 4 - Reserve quantity information

Estimated oil and gas reserves

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

The Company 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 Company estimates its reserves at least once a year. The Company’s reserves estimation as of 31 December 2015, 2014 and 2013 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).

Note

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

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

The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2015, 2014 and 2013 are summarised as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	As of 31 December 2015		As of 31 December 2014		As of 31 December 2013
	Oil and condensate (Mbbl)	Natural gas (MMcf)	Oil and condensate (Mbbl)	Natural gas (MMcf)	Oil and condensate (Mbbl)	Natural gas (MMcf)
Net proved developed
Chile ⁽¹⁾	498.0	4,922.0	1,463.7	9,352.0	2,236.6	10,037.0
Colombia ⁽²⁾	8,177.8	-	7,594.8	-	3,250.9	-
Brazil ⁽³⁾	120.0	36,158.0	69.0	20,863.0	-	-
Total consolidated	8,795.8	41,080.0	9,127.5	30,215.0	5,487.5	10,037.0

Net proved undeveloped
Chile ⁽⁴⁾	5,455.8	31,593.0	4,978.2	24,618.0	3,138.4	22,122.0
Colombia ⁽⁵⁾	22,245.5	-	17,140.5	-	6,175.7	-
Brazil ⁽³⁾	-	-	61.0	19,601.0	-	-
Total consolidated	27,701.3	31,593.0	22,179.7	44,219.0	9,314.1	22,122.0

Total proved reserves	36,497.1	72,673.0	31,307.2	74,434.0	14,801.6	32,159.0

(1)

Fell Block accounts for 91% of the reserves (92% in 2014 and 100% in 2013) (LGI owns a 20% interest) and Flamenco Block accounts for 9% (8% in 2014) (LGI owns 31.2% interest).

(2)

Llanos 34 Block and Cuerva Block account for 94% and 3% (79% and 17% in 2014 and 58% and 36% in 2013) of the proved developed reserves, respectively (LGI owns a 20% interest).

(3)

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

(4)

Fell Block accounts for 100% of the reserves (96% in 2014 and 100% in 2013) (LGI owns a 20% interest), (Flamenco Block accounts for 3% and Isla Norte accounts for 1% 2014) (LGI owns 31.2% interest).

(5)

Llanos 34 Block and Cuerva Block account for 95% and 4% (91% and 7% in 2014 and 74% and 23% in 2013) of the proved undeveloped reserves, respectively (LGI owns a 20% interest).

Note

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	Chile	Colombia	Brazil	Total
Reserves as of 31 December 2012	5,258.1	6,627.0	-	11,885.1
Increase (decrease) attributable to:
Revisions	271.1	(277.0)	-	(5.9)
Extensions and discoveries (1)	1,431.0	5,210.0	-	6,641.0
Production	(1,585.2)	(2,133.4)	-	(3,718.6)
Reserves as of 31 December 2013	5,375.0	9,426.6	-	14,801.6
Increase (decrease) attributable to:
Revisions (2)	124.9	2,489.7	-	2,614.6
Extensions and discoveries (3)	2,314.0	16,477.0	-	18,791.0
Purchases of minerals in place	-	-	150.0	150.0
Production	(1,372.0)	(3,658.0)	(20.0)	(5,050.0)
Reserves as of 31 December 2014	6,441.9	24,735.3	130.0	31,307.2
Increase (decrease) attributable to:
Revisions	119.0	(1.0)	7.6	125.6
Extensions and discoveries (4)	100.0	10,489.0	-	10,589.0
Production	(707.1)	(4,800.0)	(17.6)	(5,524.7)
Reserves as of 31 December 2015	5,953.8	30,423.3	120.0	36,497.1

(1)

Mainly due to 2013 discoveries in Llanos 34 (Taro Taro, Tigana and Tigana Sur) and Yamú (Potrillo).

(2)

In Chile, the revisions are mainly due to Field’s performance in Fell and TdF Blocks. In Colombia, the revisions are mainly due to the performance of Tua Field and secondly to the performance of Max and Taro-taro Fields in Llanos 34 Block.

(3)

In Chile, the discoveries mainly due to Loij Field discovery and Konawentru Field extensions. In Colombia, the discoveries mainly due to Tigana Field extensions wells and Aruco Field discovery in Llanos 34 Block.

(4)

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

Note

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

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

Millions of cubic feet	Chile	Brazil	Total
Reserves as of 31 December 2012	29,581.0	-	29,581.0
Increase (decrease) attributable to:
Revisions (1)	4,691.0	-	4,691.0
Extensions and discoveries	2,219.0	-	2,219.0
Production	(4,332.0)	-	(4,332.0)
Reserves as of 31 December 2013	32,159.0	-	32,159.0
Increase (decrease) attributable to:
Revisions (2)	3,312.0	-	3,312.0
Extensions and discoveries (3)	3,014.0	-	3,014.0
Purchases of minerals in place	-	47,680.0	47,680.0
Production	(4,515.0)	(7,216.0)	(11,731.0)
Reserves as of 31 December 2014	33,970.0	40,464.0	74,434.0
Increase (decrease) attributable to:
Revisions (4)	(2,680.0)	2,907.0	227.0
Extensions and discoveries (5)	9,378.0	-	9,378.0
Production	(4,153.0)	(7,213.0)	(11,366.0)
Reserves as of 31 December 2015	36,515.0	36,158.0	72,673.0

(1)

The revisions are mainly due to adjustments in the Fell Block as a response to a workover in Monte Aymond field, and associated gas from drilling campaigns in Konawentru and Yagán Norte fields.

(2)

The revisions are mainly due to Chercán Field development in TdF Block and gas and associated gas performance/development in Fields of Fell Block.

(3)

Mainly due to the Ache Field discovery and the associated gas from Konawentru extension well.

(4)

In Brazil, the revisions are primary due to the production performance of Manati field.

(5)

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

Revisions refer to changes in interpretation of discovered accumulations and some technical / logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases.

Note

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 2015, 2014 and 2013 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 Company. 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 Company’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 Company has on the discounted future net cash flows derived from the reserves of hydrocarbons.

Amounts in US$ '000	Chile	Colombia	Brazil	Total
At 31 December 2015
Future cash inflows	403,199	1,032,339	221,206	1,656,744
Future production costs	(186,933)	(309,394)	(99,832)	(596,159)
Future development costs	(112,312)	(99,305)	(16,360)	(227,977)
Future income taxes	(17,904)	(195,957)	(16,837)	(230,698)
Undiscounted future net cash flows	86,050	427,683	88,177	601,910
10% annual discount	(17,895)	(127,586)	(15,861)	(161,342)
Standardized measure of discounted future net cash flows	68,155	300,097	72,316	440,568

Note

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	Chile	Colombia	Brazil	Total
At 31 December 2014
Future cash inflows	778,820	1,732,395	307,535	2,818,750
Future production costs	(250,529)	(587,096)	(124,265)	(961,890)
Future development costs	(184,352)	(100,036)	(19,965)	(304,353)
Future income taxes	(54,442)	(303,090)	(19,566)	(377,098)
Undiscounted future net cash flows	289,497	742,173	143,739	1,175,409
10% annual discount	(61,839)	(158,102)	(31,594)	(251,535)
Standardized measure of discounted future net cash flows	227,658	584,071	112,145	923,874
At 31 December 2013
Future cash inflows	610,106	686,227	-	1,296,333
Future production costs	(164,820)	(274,246)	-	(439,066)
Future development costs	(215,426)	(82,964)	-	(298,390)
Future income taxes	(38,599)	(118,104)	-	(156,703)
Undiscounted future net cash flows	191,261	210,913	-	402,174
10% annual discount	(27,401)	(37,121)	-	(64,522)
Standardized measure of discounted future net cash flows	163,860	173,792	-	337,652

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

Amounts in US$ '000	Chile	Colombia	Brazil	Total
Present value at 31 December 2012	202,449	133,645	-	336,094
Sales of hydrocarbon , net of production costs	(128,993)	(118,417)	-	(247,410)
Net changes in sales price and production costs	(4,925)	4,754	-	(171)
Changes in estimated future development costs	(118,760)	(68,337)	-	(187,097)
Extensions and discoveries less related costs	63,948	186,738	-	250,686
Development costs incurred	83,983	39,922	-	123,905
Revisions of previous quantity estimates	37,389	(9,928)	-	27,461
Net changes in income taxes	4,102	(17,827)	-	(13,725)
Accretion of discount	24,667	23,242	-	47,909

Note

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 (continued)

Amounts in US$ '000	Chile	Colombia	Brazil	Total
Present value at 31 December 2013	163,860	173,792	-	337,652
Sales of hydrocarbon , net of production costs	(110,451)	(208,337)	(39,414)	(358,202)
Net changes in sales price and production costs	18,310	19,215	7,409	44,934
Changes in estimated future development costs	(134,272)	(51,176)	(22,143)	(207,591)
Extensions and discoveries less related costs	96,614	600,391	-	697,005
Development costs incurred	157,988	59,272	1,340	218,600
Revisions of previous quantity estimates	25,114	103,411	1,559	130,084
Net changes in income taxes	(9,751)	(141,687)	4,156	(147,282)
Purchase of minerals in place	-	-	142,423	142,423
Accretion of discount	20,246	29,190	16,815	66,251
Present value at 31 December 2014	227,658	584,071	112,145	923,874
Sales of hydrocarbon , net of production costs	(20,948)	(97,152)	(37,428)	(155,528)
Net changes in sales price and production costs	(256,828)	(547,379)	(27,404)	(831,611)
Changes in estimated future development costs	28,227	(20,123)	542	8,646
Extensions and discoveries less related costs	23,595	174,951	-	198,546
Development costs incurred	15,093	29,965	4,872	49,930
Revisions of previous quantity estimates	(5,463)	(14,528)	4,845	(15,146)
Net changes in income taxes	28,611	101,576	1,573	131,760
Accretion of discount	28,210	88,716	13,171	130,097
Present value at 31 December 2015	68,155	300,097	72,316	440,568

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 FinancialOfficer

Date: March 10, 2016