UNITED STATES
SECURITIES AND EXCHANGE COMMISSION



Washington, D.C. 20549





FORM 20-F

(Mark One)



| | o | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
| | - | ----------------------------------------------------------------------------------------------



| | OR | 
| | -- | 



| | x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934for the fiscal year ended December 31, 2016
| | - | -------------------------------------------------------------------------------------------------------------------------------



| | OR | 
| | -- | 



| | o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from ________________ to ________________
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------



OR

| | o | SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Date of event requiring this shell company report
| | - | --------------------------------------------------------------------------------------------------------------------------------------------



Commission
file number: 	001-36298



GEOPARK
LIMITED

(Exact name of Registrant as specified
in its charter)

Bermuda



(Jurisdiction of incorporation)

Nuestra Señora de los Ángeles
179

Las Condes, Santiago, Chile



(Address of principal executive offices)



Pedro Aylwin



Director of Legal and Governance



GeoPark Limited



Nuestra Señora de los Ángeles
179



Las Condes, Santiago, Chile



Phone: +56 (2) 2242 9600



Fax: +56 (2) 2242 9600 ext. 201

(Name, Telephone, E-mail and/or Facsimile
number and Address of Company Contact Person)



Copies to:

Maurice Blanco, Esq.



Davis Polk & Wardwell LLP



450 Lexington Avenue



New York, NY 10017



Phone: (212) 450 4000



Fax: (212) 701 5800



Securities registered or to be registered
pursuant to Section 12(b) of the Act:

|Title
        of each class                 | Name
        of each exchange on which registered
|------------------------------------------- | -------------------------------------------------
|Common shares, par value US$0.001 per share | New York Stock Exchange                          



Securities registered or to be registered
pursuant to Section 12(g) of the Act:



None(Title of Class)



Securities for which there is a reporting
obligation pursuant to Section 15(d) of the Act:



None(Title of Class)



Indicate the number of outstanding shares of each of the issuer’s
classes of capital stock or common stock as of the close of business covered by the annual report.



Common shares: 59,940,881



Indicate by check mark if the registrant is a well-known seasoned
issuer, as defined in Rule 405 of the Securities Act.



o  Yes      x  No

If this report is an annual or transition report, indicate by
check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.



o  Yes     x  No

Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days.



x  Yes      o  No










Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required
to submit and post such files).



o  Yes      o  No

Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer”
in Rule 12b-2 of the Exchange Act. (Check one):



|Large accelerated filer  o | Accelerated filer  x | Non-accelerated filer  o
|-------------------------- | -------------------- | ------------------------

Indicate by check mark which basis of accounting
the registrant has used to prepare the financial statements included in this filing:



|US GAAP  o | International Financial Reporting Standards as issued by the International Accounting Standards Board  x | Other  o
|---------- | -------------------------------------------------------------------------------------------------------- | --------

If “Other” has been checked in response to the previous
question indicate by check mark which financial statement item the registrant has elected to follow.



o  Item
17   o  Item 18

If this is an annual report, indicate by
check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



o  Yes      x  No











GeoPark
LIMITED



Table
of Contents






Page







|PRESENTATION OF FINANCIAL AND OTHER INFORMATION                | iii
|-------------------------------------------------------------- | ---
|FORWARD-LOOKING STATEMENTS                                     | vi 
|PART I                                                         | 1  
|ITEM 1.  IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 1  
|A.   Directors and senior management                           | 1  
|B.   Advisers                                                  | 1  
|C.   Auditors                                                  | 1  
|ITEM 2.  OFFER STATISTICS AND EXPECTED TIMETABLE               | 1  
|A.   Offer statistics                                          | 1  
|B.   Method and expected timetable                             | 1  
|ITEM 3.  KEY INFORMATION                                       | 1  
|A.   Selected financial data                                   | 1  
|B.   Capitalization and indebtedness                           | 5  
|C.   Reasons for the offer and use of proceeds                 | 5  
|D.   Risk factors                                              | 6  
|ITEM 4.  INFORMATION ON THE COMPANY                            | 33 
|A.   History and development of the company                    | 33 
|B.   Business Overview                                         | 35 
|C.   Organizational structure                                  | 90 
|D.   Property, plant and equipment                             | 90 
|ITEM 4A.  UNRESOLVED STAFF COMMENTS                            | 90 
|ITEM 5.  OPERATING AND FINANCIAL REVIEW AND PROSPECTS          | 91 
|A.   Operating results                                         | 91 
|B.   Liquidity and capital resources                           | 106
|C.   Research and development, patents and licenses, etc.      | 115
|D.   Trend information                                         | 115
|E.   Off-balance sheet arrangements                            | 116
|F.   Tabular disclosure of contractual obligations             | 116
|G.   Safe harbor                                               | 116
|ITEM 6.  DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES            | 116
|A.   Directors and senior management                           | 116
|B.   Compensation                                              | 121
|C.   Board practices                                           | 124
|D.   Employees                                                 | 126
|E.   Share ownership                                           | 127
|ITEM 7.  MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS     | 128
|A.   Major shareholders                                        | 128
|B.   Related party transactions                                | 128
|C.   Interests of Experts and Counsel                          | 130
|ITEM 8.  FINANCIAL INFORMATION                                 | 131
|A.   Consolidated statements and other financial information   | 131
|B.   Significant changes                                       | 132
|ITEM 9.  THE OFFER AND LISTING                                 | 132
|A.   Offering and listing details                              | 132
|B.   Plan of distribution                                      | 132
|C.   Markets                                                   | 132
|D.   Selling shareholders                                      | 132
|E.   Dilution                                                  | 133
|F.   Expenses of the issue                                     | 133





i


Table of Contents






|ITEM 10.  ADDITIONAL INFORMATION                                                       | 133
|-------------------------------------------------------------------------------------- | ---
|A.   Share capital                                                                     | 133
|B.   Memorandum of association and bye-laws                                            | 133
|Enforcement of Judgments                                                               | 140
|C.   Material contracts                                                                | 141
|D.   Exchange controls                                                                 | 141
|E.   Taxation                                                                          | 141
|F.   Dividends and paying agents                                                       | 144
|G.   Statement by experts                                                              | 144
|H.   Documents on display                                                              | 144
|I.   Subsidiary information                                                            | 145
|ITEM 11.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                   | 145
|ITEM 12.  DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES                       | 145
|A.   Debt securities                                                                   | 145
|B.   Warrants and rights                                                               | 145
|C.   Other securities                                                                  | 145
|D.   American Depositary Shares                                                        | 145
|PART II                                                                                | 146
|ITEM 13.  DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES                              | 146
|A.   Defaults                                                                          | 146
|B.   Arrears and delinquencies                                                         | 146
|ITEM 14.  MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 146
|ITEM 15.  CONTROLS AND PROCEDURES                                                      | 146
|A.   Disclosure Controls and Procedures                                                | 146
|B.   Management’s Annual Report on Internal Control over Financial Reporting           | 146
|C.   Attestation Report of the Registered Public Accounting Firm                       | 147
|D.   Changes in Internal Control over Financial Reporting                              | 147
|ITEM 16.  RESERVED                                                                     | 147
|ITEM 16A.  Audit committee financial expert                                            | 147
|ITEM 16B.  Code of Conduct                                                             | 147
|ITEM 16C.  Principal Accountant Fees and Services                                      | 147
|ITEM 16D.  Exemptions from the listing standards for audit committees                  | 148
|ITEM 16E.  Purchases of equity securities by the issuer and affiliated purchasers      | 148
|ITEM 16F.  Change in registrant’s certifying accountant                                | 149
|ITEM 16G.  Corporate governance                                                        | 149
|ITEM 16H.  Mine safety disclosure                                                      | 150
|PART III                                                                               | 151
|ITEM 17.  Financial statements                                                         | 151
|ITEM 18.  Financial statements                                                         | 151
|ITEM 19.  Exhibits                                                                     | 151
|Glossary of oil and natural gas terms                                                  | 154
|Index to Consolidated Financial Statements                                             | F-1



ii


Table of Contents


PRESENTATION
OF FINANCIAL AND OTHER INFORMATION



Certain definitions



Unless otherwise indicated or the context
otherwise requires, all references in this annual report to:



| | · | “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company”
and words of a similar effect, are to GeoPark Limited (formerly GeoPark Holdings Limited), an exempted company incorporated under
the laws of Bermuda, together with its consolidated subsidiaries;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an established branch, under the laws of Chile,
of GeoPark Latin America Limited (“GeoPark Latin America”), an exempted company incorporated under the laws of Bermuda;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | “GeoPark Colombia” are prior to our internal corporate reorganization of our Colombian operations, to our subsidiary
GeoPark Colombia S.A., a sociedad anónima cerrada incorporated under the laws of Chile and subsequent to such reorganization,
to GeoPark Colombia Coöperatie U.A., a cooperative duly incorporated under the laws of the Netherlands;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | “LGI” are to LG International Corp., a company incorporated under the laws of Korea”;
| | - | -------------------------------------------------------------------------------------



| | · | “Notes due 2020” are to our 2013 issuance of US$300.0 million aggregate principal amount of 7.50% senior secured
notes due 2020;
| | - | --------------------------------------------------------------------------------------------------------------------------------



| | · | “US$” and “U.S. dollar” are to the official currency of the United States of America;
| | - | -------------------------------------------------------------------------------------



| | · | “Ch$” and “Chilean pesos” are to the official currency of Chile;
| | - | ----------------------------------------------------------------



| | · | “AR$” and “Argentine pesos” are to the official currency of Argentina;
| | - | ----------------------------------------------------------------------



| | · | “real,” “reais” and “R$” are to the official currency of Brazil;
| | - | ----------------------------------------------------------------



| | · | “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo,
Gás Natural e Biocombustíveis);
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------



| | · | “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos);
| | - | --------------------------------------------------------------------------------------------



| | · | “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo)
| | - | -----------------------------------------------------------------------------------



| | · | “economic interest” means an indirect participation interest in the net revenues from a given block based on bilateral
agreements with the concessionaires; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | “working interest” means the right granted to the lessee of a property to explore for and to produce and own oil,
gas, or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty
or carried basis.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Financial statements



Our consolidated financial
statements



This annual report includes our audited
consolidated financial statements as of December 31, 2016 and 2015 and for each of the years ended December 31, 2016, 2015 and
2014 (hereinafter “Consolidated Financial Statements”).



Our Consolidated Financial Statements are
presented in US$ and have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as
issued by the International Accounting Standards Board (“IASB”).



iii


Table of Contents


Our Consolidated Financial Statements have
been audited by Price Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers Network (“PwC”),
an independent registered public accounting firm, as stated in their report included elsewhere in this annual report.



Our fiscal year ends December 31. References
in this annual report to a fiscal year, such as “fiscal year 2016,” relate to our fiscal year ended on December 31
of that calendar year.



Non IFRS financial measures



Adjusted EBITDA



Adjusted EBITDA is a supplemental non-IFRS
financial measure that is used by management and external users of our financial statements, such as industry analysts, investors,
lenders and rating agencies.



We define Adjusted EBITDA as profit for
the period before net finance cost, income tax, depreciation, amortization and certain non-cash items such as impairment charges
or impairment reversals,  write-offs of unsuccessful exploration and evaluation assets, accrual of stock options and stock awards,
unrealized gains in commodity risk management contracts and bargain purchase gain on acquisition of subsidiaries. Adjusted EBITDA
is not a measure of profit or cash flows as determined by IFRS.



We believe Adjusted EBITDA is useful because
it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period
without regard to our financing methods or capital structure. We exclude the items listed above from profit for the period in arriving
at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting
methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should
not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities
as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from
Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s
cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets,
or unrealized gains in commodity risk management contracts, none of which are components of Adjusted EBITDA. Our computation of
Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.



For a reconciliation of Adjusted EBITDA
to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial Statements as of and for the years
ended 2016, 2015 and 2014.



Oil and gas reserves and production information



DeGolyer and MacNaughton
2016 Year-end Reserves Report



The information included elsewhere in this
annual report regarding estimated quantities of proved reserves in Colombia, Chile, Brazil and Peru is derived, in part, from estimates
of the proved reserves as of December 31, 2016. The reserves estimates are derived from the DeGolyer and MacNaughton Reserves Report
(“D&M Reserves Report”), which was prepared for us by the independent reserves engineering team of DeGolyer and
MacNaughton and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates
located in the Fell, Campanario, Flamenco and Isla Norte Blocks in Chile, Llanos 32, Llanos 34, Yamú Blocks, La Cuerva in
Colombia, BCAM-40 (Manati) in Brazil and the Morona Block in Peru.



Market share and other information



Market data, other statistical information,
information regarding recent developments in Chile, Colombia, Brazil, Peru and Argentina and certain industry forecast data used
in this annual report were obtained from internal reports and studies, where appropriate, as well as estimates, market research,
publicly available information and industry publications. Industry publications generally state that the information they include
has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed.
Similarly, internal reports and studies, estimates and market research, which we believe to be reliable and accurately extracted
by us for use in this annual report, have not been independently verified. However, we believe such data is accurate and agree
that we are responsible for the accurate extraction of such information from such sources and its correct reproduction in this
annual report.



iv


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In addition, we have provided definitions
for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms” included as Appendix
A to this annual report.



Rounding



We have made rounding adjustments to some
of the figures included elsewhere in this annual report. Accordingly, numerical figures shown as totals in some tables may not
be an arithmetic aggregation of the figures that precede them.



v


Table of Contents


FORWARD-LOOKING
STATEMENTS



This annual report contains statements
that constitute forward-looking statements. Many of the forward-looking statements contained in this annual report can be identified
by the use of forward-looking words such as “anticipate,” “believe,” “could,” “expect,”
“should,” “plan,” “intend,” “will,” “estimate” and “potential,”
among others.



Forward-looking statements appear in a
number of places in this annual report and include, but are not limited to, statements regarding our intent, belief or current
expectations. Forward-looking statements are based on our management’s beliefs and assumptions and on information currently
available to our management. Such statements are subject to risks and uncertainties, and actual results may differ materially from
those expressed or implied in the forward-looking statements due to various factors, including, but not limited to, those identified
under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties
include factors relating to:



| | · | the volatility of oil and natural gas prices;
| | - | ---------------------------------------------



| | · | operating risks, including equipment failures and the amounts and timing of revenues and expenses;
| | - | --------------------------------------------------------------------------------------------------



| | · | termination of, or intervention in, concessions, rights or authorizations granted by the Chilean, Colombian, Brazilian, Peruvian
and Argentine governments to us;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | uncertainties inherent in making estimates of our oil and natural gas data;
| | - | ---------------------------------------------------------------------------



| | · | environmental constraints on operations and environmental liabilities arising out of past or present operations;
| | - | ----------------------------------------------------------------------------------------------------------------



| | · | discovery and development of oil and natural gas reserves;
| | - | ----------------------------------------------------------



| | · | project delays or cancellations;
| | - | --------------------------------



| | · | financial market conditions and the results of financing efforts;
| | - | -----------------------------------------------------------------



| | · | political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which
we operate;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



| | · | fluctuations in inflation and exchange rates in Colombia, Chile, Brazil, Peru, Argentina and in other countries in which we
may operate in the future;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services;
| | - | ---------------------------------------------------------------------------------------------------------



| | · | contract counterparty risk;
| | - | ---------------------------



| | · | projected and targeted capital expenditures and other cost commitments and revenues;
| | - | ------------------------------------------------------------------------------------



| | · | weather and other natural phenomena;
| | - | ------------------------------------



| | · | the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws
and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | current and future litigation;
| | - | ------------------------------



| | · | our ability to successfully identify, integrate and complete acquisitions;
| | - | --------------------------------------------------------------------------



| | · | our ability to retain key members of our senior management and key technical employees;
| | - | ---------------------------------------------------------------------------------------



| | · | competition from other similar oil and natural gas companies;
| | - | -------------------------------------------------------------



vi


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| | · | market or business conditions and fluctuations in global and local demand for energy;
| | - | -------------------------------------------------------------------------------------



| | · | the direct or indirect impact on our business resulting from terrorist incidents or responses to such incidents, including
the effect on the availability of and premiums on insurance; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | other factors discussed under “Item 3. Key Information—D. Risk factors” in this annual report.
| | - | ----------------------------------------------------------------------------------------------



Forward-looking statements speak only as
of the date they are made, and we do not undertake any obligation to update them in light of new information or future developments
or to release publicly any revisions to these statements in order to reflect later events or circumstances or to reflect the occurrence
of unanticipated events.



vii


Table of Contents


PART I



ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS



| | A. | Directors and senior management
| | -- | -------------------------------



Not applicable.



| | B. | Advisers
| | -- | --------



Not applicable.



| | C | Auditors
| | - | --------



Not applicable.



ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE



| | A. | Offer statistics
| | -- | ----------------



Not applicable.



| | B | Method and expected timetable
| | - | -----------------------------



Not applicable.



ITEM 3. KEY INFORMATION



| | A. | Selected financial data
| | -- | -----------------------



We have derived our
selected historical  balance sheet data as of December 31, 2016 and 2015 and our income statement and cash flow data
for the years ended December 31, 2016, 2015 and 2014 from our Consolidated Financial Statements included elsewhere in this
annual report, which have been audited by PwC. We have derived our selected balance sheet data as of December 31, 2014, 2013,
and 2012 and our income statement and cash flow data for the years ended December 31,  2013 and 2012  from our Consolidated
Financial Statements not included elsewhere in this annual report.



During 2015, our Management changed the
presentation of the Consolidated Statement of Income by reordering the profit and loss line items, eliminating gross profit and
presenting depreciation and write-off of unsuccessful efforts as separate line items. This change is intended to provide readers
of our financial statements with more relevant information and a better explanation of the elements of performance. This change
has been applied to comparative figures for the years 2014, 2013 and 2012 presented in this document.



We maintain our books and records in US$
and prepare our Consolidated Financial Statements in accordance with IFRS.



This financial information should be read
in conjunction with “Presentation of Financial and Other Information,” “Item 5. Operating and Financial Review
and Prospects” and our Consolidated Financial Statements and the related notes thereto.



The selected historical financial data
set forth in this section does not include an

y results or other financial information of our Colombian, Brazilian or Peruvian acquisitions
prior to their incorporation into our financial statements.



1


Table of Contents


Statement of income
data







|                                                                                            |  | For
    the year ended December 31,                
|------------------------------------------------------------------------------------------- |  | ---------------------------------------------------
|                                                                                            |  | 2016                                               
|                                                                                            |  | (in thousands of US$, except
    per share numbers)
|                                                                                            |  |                                                    
|Revenue                                                                                     |  |                                                    
|Net oil sales                                                                               |  |                                                    
|Net gas sales                                                                               |  |                                                    
|Net revenue                                                                                 |  |                                                    
|Commodity risk management contracts                                                         |  |                                                    
|Production and operating costs                                                              |  |                                                    
|Geological and geophysical expenses                                                         |  |                                                    
|Administrative expenses                                                                     |  |                                                    
|Selling expenses                                                                            |  |                                                    
|Depreciation                                                                                |  |                                                    
|Write-off of unsuccessful efforts                                                           |  |                                                    
|Impairment for non-financial assets                                                         |  |                                                    
|Other operating income/(expense)                                                            |  |                                                    
|Operating (loss)/profit                                                                     |  |                                                    
|Financial costs                                                                             |  |                                                    
|Foreign exchange loss                                                                       |  |                                                    
|Bargain purchase gain on acquisition of subsidiaries                                        |  |                                                    
|(Loss) Profit before
    tax                                                                |  |                                                    
|Income tax benefit (expense)                                                                |  |                                                    
|(Loss) Profit for the
    year                                                              |  |                                                    
|Non-controlling interest                                                                    |  |                                                    
|(Loss) Profit attributable
    to owners of the Company                                     |  |                                                    
|(Losses) Earnings per
    share for profit attributable to owners of the Company—Basic      |  |                                                    
|(Losses) Earnings per
    share for profit attributable to owners of the Company—Diluted(1) |  |                                                    
|Weighted average common shares  outstanding—Basic                                           |  |                                                    
|Weighted average common shares outstanding—Diluted(1)                                       |  |                                                    
|Common Shares outstanding
    at year-end                                                   |  |                                                    





__________________

|(1) | See Note 18 to our Consolidated Financial Statements.
|--- | -----------------------------------------------------



2


Table of Contents


Balance sheet data



|                                                |  | As of December 31,   
|----------------------------------------------- |  | ---------------------
|                                                |  | 2016                 
|                                                |  | (In thousands of US$)
|Assets                                          |  |                      
|Non-current assets                              |  |                      
|Property, plant and equipment                   |  |                      
|Prepaid taxes                                   |  |                      
|Other financial assets                          |  |                      
|Deferred income tax                             |  |                      
|Prepayments and other receivables               |  |                      
|Total non-current assets                        |  |                      
|Current assets                                  |  |                      
|Other financial assets                          |  |                      
|Inventories                                     |  |                      
|Trade receivables                               |  |                      
|Prepayments and other receivables               |  |                      
|Prepaid taxes                                   |  |                      
|Cash at bank and in hand                        |  |                      
|Total current assets                            |  |                      
|Total assets                                    |  |                      
|Share capital                                   |  |                      
|Share premium                                   |  |                      
|Other                                           |  |                      
|Equity attributable to owners of the Company    |  |                      
|Equity attributable to non-controlling interest |  |                      
|Total equity                                    |  |                      
|Liabilities                                     |  |                      
|Non-current liabilities                         |  |                      
|Borrowings                                      |  |                      
|Provisions for other long-term liabilities      |  |                      
|Trade and other payables                        |  |                      
|Deferred income tax                             |  |                      
|Total non-current liabilities                   |  |                      
|Current liabilities                             |  |                      
|Borrowings                                      |  |                      
|Derivative financial instrument liabilities     |  |                      
|Current income tax                              |  |                      
|Trade and other payables                        |  |                      
|Total current liabilities                       |  |                      
|Total liabilities                               |  |                      
|Total equity and liabilities                    |  |                      
|                                                |  |                      

3


Table of Contents


Cash flow data



|                                |  | For the year ended December 31,
|------------------------------- |  | -------------------------------
|                                |  | 2016                           
|                                |  | (In thousands of US$)          
|Cash provided by (used in)      |  |                                
|Operating activities            |  |                                
|Investing activities            |  |                                
|Financing activities            |  |                                
|Net increase (decrease) in cash |  |                                



Other financial data



|                                   |  | For the year ended December 31,
|---------------------------------- |  | -------------------------------
|                                   |  | 2016                           
|Adjusted EBITDA(1) (US$ thousands) |  |                                
|Adjusted EBITDA margin(2)          |  |                                
|Adjusted EBITDA per boe(3)         |  |                                




| | (1) | Adjusted EBITDA is a non-IFRS financial measure. For a definition of Adjusted EBITDA and other information relating to this
measure, see “Presentation of Financial and Other Information—Financial statements—Non-IFRS financial measures.”
For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial
Statements.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Adjusted EBITDA margin is defined as Adjusted EBITDA divided by net revenue.
| | --- | ----------------------------------------------------------------------------



| | (3) | Adjusted EBITDA per boe is defined as Adjusted EBITDA divided by total boe.
| | --- | ---------------------------------------------------------------------------



Exchange rates



In Colombia, Chile, Argentina and Peru,
our functional currency is the U.S. dollar. In Brazil, our functional currency is the real.



Our operations in Brazil accounted for
16% of our consolidated assets and 15% of our revenues for the years ended December 31, 2015 and 2016, respectively. This portion
of our business is exposed to losses that may arise from currency fluctuation, as a significant amount of our revenues, operating
costs, administrative expenses and taxes in Brazil are denominated in reais. Furthermore, we financed our acquisition of
Rio das Contas Produtora de Petróleo Ltda. (a Brazilian limited liability company; “Rio das Contas”) in part
through our Brazilian subsidiary’s entrance into a US$70.5 million credit facility with Itaú BBA International plc.
This exposes us to exchange rate losses from the devaluation of the Brazilian reais against the U.S. dollar.



In the past, the Brazilian Central Bank
has occasionally intervened to control unstable movements in foreign exchange rates. We cannot predict whether the Brazilian Central
Bank or the Brazilian government will continue to permit the real to float freely or will intervene in the exchange rate
market through the return of a currency band system or otherwise. The real may depreciate or appreciate substantially against
the U.S. dollar. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments
or there are reasons to foresee a serious imbalance, temporary restrictions may be imposed on remittances of foreign capital abroad.
We cannot assure you that such measures will not be taken by the Brazilian government in the future.



As a result of the devaluation that occurred
in the year ended December 31, 2015, we recorded exchange rate losses amounting to US$35.6 million in 2015 and we recorded exchange
rate gains amounting to US$14.5 million in the year ended December 31, 2016, due to revaluation of the local currency in our Brazilian
subsidiary. This result was mainly generated by the credit facility with Itaú BBA International plc that we incurred to
acquire Rio das Contas in March 31, 2014. See “—D. Risk factors—Risks relating to our business—Our results
of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.”



The following tables show the selling rate
for the U.S. dollar for the periods and dates indicated. The information in the “Average” column represents the average
of the daily exchange rates during the periods presented. The numbers in the “Period-end” column are the quotes for
the exchange rate as of the last business day of the period in question. As of April 6, 2017, the exchange rate for the purchase
of the U.S. dollar as reported by the Central Bank of Brazil was R$3.1160 per U.S. dollar.



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The following table presents the monthly
high and low representative market rate during the months indicated.



|Recent exchange rates of Real per US$ | Period
        End | Average | Low    | High  
|------------------------------------- | ------------------ | ------- | ------ | ------
|Month:                                |                    |         |        |       
|October 2016                          | 3.1811             | 3.1872  | 3.1193 | 3.2359
|November 2016                         | 3.3967             | 3.3420  | 3.2024 | 3.4446
|December 2016                         | 3.2591             | 3.3562  | 3.2591 | 3.4650
|January 2017                          | 3.1270             | 3.1966  | 3.1270 | 3.2729
|February 2017                         | 3.0993             | 3.1042  | 3.0510 | 3.1479
|March 2017                            | 3.1282             | 3.1261  | 3.0765 | 3.1735
|April 2017 (through April 6, 2017)    | 3.1160             | 3.1120  | 3.0923 | 3.1231

_____________________

Source:
Central Bank of Brazil.





The following table presents the average
R$ per U.S. dollar representative market rate for each of the five most recent years, calculated by using the average of the exchange
rates on the last day of each month during the period, and the representative year-end market rate for each of the five most recent
years.



|Real per US$                                | Period/Year
        End | Average | Low    | High  
|------------------------------------------- | ----------------------- | ------- | ------ | ------
|Period:                                     |                         |         |        |       
|2012                                        | 2.1121                  | 1.9476  | 1.7024 | 2.1121
|2013                                        | 2.3426                  | 2.1579  | 1.9528 | 2.4457
|2014                                        | 2.6562                  | 2.3564  | 2.1974 | 2.7403
|2015                                        | 3.9048                  | 3.3876  | 2.5690 | 4.1949
|2016                                        | 3.2591                  | 3.4500  | 3.1193 | 4.1558
|First quarter 2016                          | 3.5589                  | 3.8604  | 3.5589 | 4.1558
|Second quarter 2016                         | 3.2098                  | 3.4186  | 3.2098 | 3.6921
|Third quarter 2016                          | 3.2462                  | 3.2418  | 3.1302 | 3.3388
|Fourth quarter 2016                         | 3.2591                  | 3.2790  | 3.1193 | 3.4650
|First quarter 2017                          | 3.1282                  | 3.1182  | 3.0510 | 3.2729
|Second quarter 2017 (through April 6, 2017) | 3.1160                  | 3.1120  | 3.0923 | 3.1231

_____________________

Source:
Central Bank of Brazil.



Exchange rate fluctuation may affect the
US$ value of any distributions we make with respect to our common shares. See “—D. Risk factors—Risks relating
to our business—Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange
rates.”



B.       Capitalization
and indebtedness



Not applicable.



C.       Reasons for
the offer and use of proceeds



Not applicable.



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D.       Risk factors



Our business, financial condition and
results of operations could be materially and adversely affected if any of the risks described below occur. As a result, the market
price of our common shares could decline, and you could lose all or part of your investment. This annual report also contains forward-looking
statements that involve risks and uncertainties. See “Forward-Looking Statements.” The risks below are not the only
ones facing our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect
us.



Risks relating to our business



A substantial or extended decline in
oil, natural gas and methanol prices may materially adversely affect our business, financial condition or results of operations.



The prices that we receive for our oil
and natural gas production heavily influence our revenues, profitability, access to capital and growth rate. Historically, the
markets for oil, natural gas and methanol (which have influenced prices for almost all of our Chilean gas sales) have been volatile
and will likely continue to be volatile in the future. International oil, natural gas and methanol prices have fluctuated widely
in recent years and may continue to do so in the future.



The prices that we will receive for our
production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited,
to the following:



| | · | global economic conditions;
| | - | ---------------------------



| | · | changes in global supply and demand for oil, natural gas and methanol;
| | - | ----------------------------------------------------------------------



| | · | the actions of the Organization of the Petroleum Exporting Countries (“OPEC”);
| | - | ------------------------------------------------------------------------------



| | · | political and economic conditions, including embargoes, in oil-producing countries or affecting other countries;
| | - | ----------------------------------------------------------------------------------------------------------------



| | · | the level of oil- and natural gas-producing activities, particularly in the Middle East, Africa, Russia, South America and
the United States;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------



| | · | the level of global oil and natural gas exploration and production activity;
| | - | ----------------------------------------------------------------------------



| | · | the level of global oil and natural gas inventories;
| | - | ----------------------------------------------------



| | · | the price of methanol;
| | - | ----------------------



| | · | availability of markets for natural gas;
| | - | ----------------------------------------



| | · | weather conditions and other natural disasters;
| | - | -----------------------------------------------



| | · | technological advances affecting energy production or consumption;
| | - | ------------------------------------------------------------------



| | · | domestic and foreign governmental laws and regulations, including environmental, health and safety laws and regulations;
| | - | ------------------------------------------------------------------------------------------------------------------------



| | · | proximity and capacity of oil and natural gas pipelines and other transportation facilities;
| | - | --------------------------------------------------------------------------------------------



| | · | the price and availability of competitors’ supplies of oil and natural gas in captive market areas;
| | - | ---------------------------------------------------------------------------------------------------



| | · | quality discounts for oil production based, among other things, on API and mercury content;
| | - | -------------------------------------------------------------------------------------------



| | · | taxes and royalties under relevant laws and the terms of our contracts;
| | - | -----------------------------------------------------------------------



| | · | our ability to enter into oil and natural gas sales contracts at fixed prices;
| | - | ------------------------------------------------------------------------------



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| | · | the level of global methanol demand and inventories and changes in the uses of methanol;
| | - | ----------------------------------------------------------------------------------------



| | · | the price and availability of alternative fuels; and
| | - | ----------------------------------------------------



| | · | future changes to our hedging policies.
| | - | ---------------------------------------



These factors and the volatility of the
energy markets make it extremely difficult to predict future oil, natural gas and methanol price movements. For example, recently,
oil and natural gas prices have fluctuated significantly. From January 1, 2011 to December 31, 2016, Brent spot prices ranged from
a low of US$30.7 per barrel to a high of US$125.5 per barrel, NYMEX West Texas International (“WTI”) crude oil contracts
prices ranged from a low of US$30.3 per bbl to a high of US$109.5 per bbl, Henry Hub natural gas average spot prices ranged from
a low of US$1.7 per mmbtu to a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$250 per metric
ton to a high of US$635 per metric ton. Furthermore, oil, natural gas and methanol prices do not necessarily fluctuate in direct
relationship to each other.



For the year ended December 31, 2016, 75%
of our revenues, were derived from oil. Because we expect that our production mix will continue to be weighted towards oil, our
financial results are more sensitive to movements in oil prices.



As of December 31, 2016, natural gas comprised
25% of our revenues. A decline in natural gas prices could negatively affect our future growth, particularly for future gas sales
where we may not be able to secure or extend our current long-term contracts.



Lower oil and natural gas prices may impact
our revenues on a per unit basis, and may also reduce the amount of oil and natural gas that can be produced economically. In addition,
changes in oil and natural gas prices can impact the valuation of our reserves and, in periods of lower commodity prices, we may
curtail production and capital spending or may defer or delay drilling wells because of lower cash generation. Lower oil and natural
gas prices could also affect our growth, including future and pending acquisitions. A substantial or extended decline in oil or
natural gas prices could adversely affect our business, financial condition and results of operations.



For example, during 2014 and 2015, we evaluated
the recoverability of our fixed assets affected by the oil price decline and recorded an impairment of non-financial assets amounting
to, respectively, US$9.4 million and US$149.6 million. US$5.7 million of the impairment recorded in 2015 was reversed in 2016 due
to increased estimated market prices for 2017 and 2018 and improvements in cost structure. See Note 35 to our Consolidated Financial
Statements for details regarding oil price scenarios, discount rates considered and sensitivity analysis affecting the impairment
charges.



During 2016, we entered into derivative
financial instruments to manage exposure to oil price risk. These derivatives were zero-premium collars and were placed with major
financial institutions and commodity traders. We entered into the derivatives under ISDA Master Agreements and Credit Support Annexes,
which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protecting
the Company from potential non-performance risk by its counterparties. See Note 36 to our Consolidated Financial Statements for
details regarding Commodity Risk Management Contracts.



The current oil price crisis has impacted
our operations and corporate strategy.



We face limitations on our ability to increase
prices or improve margins on the oil and natural gas that we sell. As a consequence of the oil price crisis which started in the
second half of 2014 (WTI and Brent, the main international oil price markers, fell by more than 60% between August 2014 and March
2016), the Company has undertaken decisive measures to ensure its ability to both maximize ongoing projects and to preserve its
cash.



Funding our anticipated capital expenditures
relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow.
Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well
as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current
operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together
with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work
program, which would cause us to further decrease our work program and would harm our business outlook, investor confidence and
our share price.



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In addition, actions taken by the company
to maximize ongoing projects and to reduce expenses, including renegotiations and reduction of oil and gas service contracts and
other initiatives such as cost cutting may expose us to claims and contingencies from interested parties that may have a negative
impact on our business, financial condition, results of operations and cash flows. If oil prices are lower than expected, we may
be unable to meet our contractual obligations with oil and service contracts and our suppliers. Equally, those third parties may
be unable to meet their contractual obligations to us as a result of the oil price crisis, impacting on our operations.



In budgeting for our future activities,
we have relied on a number of assumptions, including, with regard to our discovery success rate, the number of wells we plan to
drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect,
the timing of third-party projects and our ability to obtain needed financing with respect to any further acquisitions and the
availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business,
political, economic, regulatory, environmental and competitive uncertainties, conditions in the financial markets, contingencies
and risks, all of which are difficult to predict and many of which are beyond our control. In addition, we opportunistically seek
out new assets and acquisition targets to complement our existing operations, and have financed such acquisitions in the past through
the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority
stakes in certain operations to our partners. We may need to raise additional funds more quickly if one or more of our assumptions
prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts
more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions
for raising capital are favorable. The ultimate amount of capital that we will expend may fluctuate materially based on market
conditions, our continued production, decisions by the operators in blocks where we are not the operator, the success of our drilling
results and future acquisitions. Our future financial condition and liquidity will be impacted by, among other factors, our level
of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal
drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural
gas discovered, the speed with which we can bring such discoveries to production and the actual cost of exploration, appraisal
and development of our oil and natural gas assets.



Unfavorable credit and market conditions,
declines in oil prices have affected and could continue to affect negatively the economies of the countries in which we operate
and may negatively affect our business, and results of operations.



Declines in oil prices have had, and may
continue to have, a negative impact on our business, financial condition, results of operations and cash flows. In addition, the
declines in WTI and Brent, the main international oil price markers, which fell by more than 60% between August 2014 and March
2016 and which are expected to remain volatile in the near future, may also negatively affect the economies of the countries in
which we operate. Any of the foregoing factors or a combination of these factors could have an adverse effect on our results of
operations and financial condition.



Unless we replace our oil and natural
gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification
of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas
in commercial quantities.



Production from oil and gas properties
declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Accordingly, our current proved
reserves will decline as these reserves are produced. As of December 31, 2016, our reserves-to-production (or reserve life) ratio
for net proved reserves in Colombia, Chile, Brazil and Peru was 9.0 years. According to estimates, if on January 1, 2017 we ceased
all drilling and development activities, including recompletions, refracs and workovers, our proved developed producing reserves
base in Colombia, Chile, Brazil and Peru would decline 30% during the first year.



Our future oil and natural gas reserves
and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current
reserves and using cost-effective methods to find or acquire additional recoverable reserves. While we have had success in identifying
and developing commercially exploitable fields and drilling locations in the past, we may be unable to replicate that success in
the future. We may not identify any more commercially exploitable fields or successfully drill, complete or produce more oil or
gas reserves, and the wells which we have drilled and currently plan to drill within our blocks or concession areas may not discover
or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable
us to continue to operate profitably. If we are unable to replace our current and future production, the value of our reserves
will decrease, and our business, financial condition and results of operations will be materially adversely affected.



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We derive a significant portion of our
revenues from sales to a few key customers.



In Colombia, for the year ended December
31, 2016, we made 90% of our oil sales to C.I. Trafigura Petroleum Colombia S.A.S., a leading commodity trading and logistics company
(“Trafigura”), representing 59% of our consolidated revenues for the same period. Sales for the year ended December
31, 2016 were made mostly under long-term agreements. In 2017 we are expected to sell most of our Colombian production to Trafigura.



In Chile, 100% of our crude oil
and condensate sales are made to ENAP. For the year ended December 31, 2016, sales to ENAP represented 10% of our total
revenues. ENAP imports the majority of the oil it refines and partially supplements those imports with volumes supplied
locally by its own operated fields and those operated by us. The sales contract with ENAP is commonly revised every year to
reflect changes in the global oil market and to adjust for ENAP’s logistics costs in the Gregorio oil terminal. As of
the date of this annual report, we are negotiating a new agreement with ENAP that we expect will take effect in April 2017.
In addition, in Chile, in the year ended December 31, 2016, almost all of our natural gas sales were made to Methanex Chile
S.A., the Chilean subsidiary of the Methanex Corporation (or “Methanex”), a leading global methanol producer,
under a long-term contract, the “Methanex Gas Supply Agreement”, which expires on April 30, 2017. In March 2017,
we executed a new gas supply agreement with Methanex effective from May 1, 2017 to December 31, 2026. Sales to Methanex
represented 9% of our consolidated revenues for the year ended December 31, 2016.



In Brazil, all of our revenues from the
sale of gas and condensate in the Manati Field in Brazil were generated from sales to Petróleo Brasileiro S.A. (“Petrobras”),
the operator of the Manati Field, pursuant to a long-term gas off-take contract. See “Item 4. Information on the Company—B.
Business Overview—Significant Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”



If any of our buyers were to decrease or
cease purchasing oil or gas from us, or if any of them were to decide not to renew their contracts with us or to renew them at
a lower sales price, this could have a material adverse effect on our business, financial condition and results of operations.
For example, see “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Colombia”
and ““Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile.”



Our results of operations could be
materially adversely affected by fluctuations in foreign currency exchange rates.



Although a majority of our net revenues
is denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Colombia, Chile,
Brazil, Peru and Argentina could have a material adverse effect on our results of operations. A portion of the cost reductions
that we achieved in 2015 and 2016 (as compared to 2014) were related to the depreciation of local currencies, including mainly
the Col$, the Ch$ and the Brazilian real. An appreciation of local currencies can increase our costs and negatively impact
our results from operations.



Furthermore, we have not entered, into
derivative transactions to hedge the effect of changes in the exchange rate of local currencies to the US$. Because our Consolidated
Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities,
into US$ at exchange rates in effect during or at the end of each reporting period.



Through our Brazilian operations, we are
exposed to fluctuations in the real against the US$, as our Brazilian revenues and expenses are mostly denominated in reais.
The real has experienced frequent and substantial variations in relation to the US$ and other foreign currencies, which
could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of
operations. For example, in 2016, we recorded exchange rate gains amounting to US$14.5 million in our Brazilian subsidiary that
were mainly generated by the credit facility of US$70.5 million that we incurred to acquire Rio das Contas in March 31, 2014. See
“—A. Selected financial data—Exchange rates.”



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There are inherent risks and uncertainties
relating to the exploration and production of oil and natural gas.



Our performance depends on the success
of our exploration and production activities and on the existence of the infrastructure that will allow us to take advantage of
our oil and gas reserves. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control,
including the risk that exploration activities will not identify commercially viable quantities of oil or natural gas. Our decisions
to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic and
other data obtained through geophysical, geochemical and geological analysis, production data and engineering studies, the results
of which are often inconclusive or subject to varying interpretations.



Furthermore, the marketability of any oil
and natural gas production from our projects may be affected by numerous factors beyond our control. These factors include, but
are not limited to, proximity and capacity of pipelines and other means of transportation, the availability of upgrading and processing
facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating
to prices, sale restrictions, taxes, governmental stake, allowable production, importing and exporting of oil and natural gas,
environmental protection and health and safety). The effect of these factors, individually or jointly, cannot be accurately predicted,
but may have a material adverse effect on our business, financial condition and results of operations.



There can be no assurance that our drilling
programs will produce oil and natural gas in the quantities or at the costs anticipated, or that our currently producing projects
will not cease production, in part or entirely. Drilling programs may become uneconomic as a result of an increase in our operating
costs or as a result of a decrease in market prices for oil and natural gas. Our actual operating costs or the actual prices we
may receive for our oil and natural gas production may differ materially from current estimates. In addition, even if we are able
to continue to produce oil and gas, there can be no assurance that we will have the ability to market our oil and gas production.
See “—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and
natural gas markets and generate significant incremental costs or delays in our oil and natural gas production” below.



Our identified potential drilling location
inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence
or timing of their drilling.



Our management team has specifically identified
and scheduled certain potential drilling locations as an estimation of our future multi-year drilling activities on our existing
acreage. These identified potential drilling locations, including those without proved undeveloped reserves, represent a significant
part of our growth strategy.



Our ability to drill and develop these
identified potential drilling locations depends on a number of factors, including oil and natural gas prices, the availability
and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease
expirations, the availability of gathering systems, marketing and transportation constraints, refining capacity, regulatory approvals
and other factors. Because of the uncertainty inherent in these factors, there can be no assurance that the numerous potential
drilling locations we have identified will ever be drilled or, if they are, that we will be able to produce oil or natural gas
from these or any other potential drilling locations.



Our business requires significant capital
investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all.



Because the oil and natural gas industry
is capital intensive, we expect to make substantial capital expenditures in our business and operations for the exploration and
production of oil and natural gas reserves. See “Item 4. Information on the Company –B. Business Overview—2017
Strategy and Outlook.” We incurred capital expenditures of US$39 million and US$49 million during the years ended December
31, 2016 and 2015, respectively. See “Item 5. Operating and Financial Review and Prospects—A. Operating Results—Factors
Affecting our Results of Operations—Discovery and exploitation of reserves.”



The actual amount and timing of our future
capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling
results, the availability of drilling rigs and other equipment and services, and regulatory, technological and competitive developments.
In response to changes in commodity prices, we may increase or decrease our actual capital expenditures. We intend to finance our
future capital expenditures through cash generated by our operations and potential future financing arrangements. However, our
financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities
or the sale of assets.



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If our capital requirements vary materially
from our current plans, we may require further financing. In addition, we may incur significant financial indebtedness in the future,
which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or financing
on terms favorable to us. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition
opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows
from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating
results.



Oil and gas operations contain a high
degree of risk and we may not be fully insured against all risks we face in our business.



Oil and gas exploration and production
is speculative and involves a high degree of risk and hazards. In particular, our operations may be disrupted by risks and hazards
that are beyond our control and that are common among oil and gas companies, including environmental hazards, blowouts, industrial
accidents, occupational safety and health hazards, technical failures, labor disputes, community protests or blockades, unusual
or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and
other accidents. For example, in the first half of 2013 we experienced a well control incident at our Chercán 1 well in
the Flamenco Block in Chile with no harm to employees or property. While we were able to bring that incident under control without
injuries or environmental damage, there can be no assurance that we will not experience similar or more serious incidents in the
future, which could result in damage to, or destruction of, wells or production facilities, personal injury, environmental damage,
business interruption, financial losses and legal liability.



While we believe that we maintain customary
insurance coverage for companies engaged in similar operations, we are not fully insured against all risks in our business. In
addition, insurance that we do and plan to carry may contain significant exclusions from and limitations on coverage. We may elect
not to obtain certain non-mandatory types of insurance if we believe that the cost of available insurance is excessive relative
to the risks presented. The occurrence of a significant event or a series of events against which we are not fully insured and
any losses or liabilities arising from uninsured or underinsured events could have a material adverse effect on our business, financial
condition or results of operations.



The development schedule of oil and natural
gas projects is subject to cost overruns and delays.



Oil and natural gas projects may experience
capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential
equipment, supplies, personnel and oil field services. The cost to execute projects may not be properly established and remains
dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and
procurement costs. Development of projects may be materially adversely affected by one or more of the following factors:



| | · | shortages of equipment, materials and labor;
| | - | --------------------------------------------



| | · | fluctuations in the prices of construction materials;
| | - | -----------------------------------------------------



| | · | delays in delivery of equipment and materials;
| | - | ----------------------------------------------



| | · | labor disputes;
| | - | ---------------



| | · | political events;
| | - | -----------------



| | · | title problems;
| | - | ---------------



| | · | obtaining easements and rights of way;
| | - | --------------------------------------



| | · | blockades or embargoes;
| | - | -----------------------



| | · | litigation;
| | - | -----------



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| | · | compliance with governmental laws and regulations, including environmental, health and safety laws and regulations;
| | - | -------------------------------------------------------------------------------------------------------------------



| | · | adverse weather conditions;
| | - | ---------------------------



| | · | unanticipated increases in costs;
| | - | ---------------------------------



| | · | natural disasters;
| | - | ------------------



| | · | accidents;
| | - | ----------



| | · | transportation;
| | - | ---------------



| | · | unforeseen engineering and drilling complications;
| | - | --------------------------------------------------



| | · | environmental or geological uncertainties; and
| | - | ----------------------------------------------



| | · | other unforeseen circumstances.
| | - | -------------------------------



Any of these events or other unanticipated
events could give rise to delays in development and completion of our projects and cost overruns.



For example, in 2013, the drilling and
completion cost for the exploratory well Chilco x-1 in our Flamenco Block in Chile was originally estimated at US$2.6 million,
but the actual cost was approximately US$4.0 million, mainly due to mechanical issues during the drilling as it was the first well
drilled with a new drilling rig.



Delays in the construction and commissioning
of projects or other technical difficulties may result in future projected target dates for production being delayed or further
capital expenditures being required. These projects may often require the use of new and advanced technologies, which can be expensive
to develop, purchase and implement and may not function as expected. Such uncertainties and operating risks associated with development
projects could have a material adverse effect on our business, results of operations or financial condition.



Competition in the oil and natural gas
industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural
gas and secure trained personnel.



We compete with the major oil and gas companies
engaged in the exploration and production sector, including state-owned exploration and production companies that possess substantially
greater financial and other resources than we do for researching and developing exploration and production technologies and access
to markets, equipment, labor and capital required to acquire, develop and operate our properties. We also compete for the acquisition
of licenses and properties in the countries in which we operate.



Our competitors may be able to pay more
for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number
of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to offer better
compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition
for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not
be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel or raising additional capital, which could have a material adverse effect on our business, financial
condition or results of operations. See “Item 4. Information on the Company—B. Business Overview—Our competition.”



Our estimated oil and gas reserves are
based on assumptions that may prove inaccurate.



Our oil and gas reserves estimates in Colombia,
Chile, Brazil, and Peru as of December 31, 2016 are based on the D&M Reserves Report. Although classified as “proved
reserves,” the reserves estimates set forth in the D&M Reserves Reports are based on certain assumptions that may prove
inaccurate. DeGolyer and MacNaughton’s primary economic assumptions in estimates included oil and gas sales prices determined
according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided
by us.



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In Chile, DeGolyer and MacNaughton ’s
estimates are based in part on the assumption that Methanex continues to commit to purchase Fell Block gas under the existing long-term
contract beyond April 30, 2017. In March 2017, we executed a new gas supply agreement with Methanex effective from May 1, 2017
to December 31, 2026.



Oil and gas reserves engineering is a subjective
process of estimating accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may
differ materially from those set out herein. Numerous assumptions and uncertainties are inherent in estimating quantities of proved
oil and gas reserves, including projecting future rates of production, timing and amounts of development expenditures and prices
of oil and gas, many of which are beyond our control. Results of drilling, testing and production after the date of the estimate
may require revisions to be made. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate
of our oil and gas reserves. Accordingly, reserves estimates are often materially different from the quantities of oil and gas
that are ultimately recovered, and if such recovered quantities are substantially lower than the initial reserves estimates, this
could have a material adverse impact on our business, financial condition and results of operations.



Our inability to access needed equipment
and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental
costs or delays in our oil and natural gas production.



Our ability to market our oil and natural
gas production depends substantially on the availability and capacity of processing facilities, oil tankers, transportation facilities
(such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated
by third parties. Our failure to obtain such facilities on acceptable terms or on a timely basis could materially harm our business.
We may be required to shut down oil and gas wells because access to transportation or processing facilities may be limited or unavailable
when needed. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to
deliver the production to market, which could cause a material adverse effect on our business, financial condition and results
of operations. In addition, the shutting down of wells can lead to mechanical problems upon bringing the production back on line,
potentially resulting in decreased production and increased remediation costs. The exploitation and sale of oil and natural gas
and liquids will also be subject to timely commercial processing and marketing of these products, which depends on the contracting,
financing, building and operating of infrastructure by third parties.



In Colombia, producers of crude oil have
historically suffered from tanker transportation logistics issues and limited storage capacity, which cause delays in delivery
and transfer of title of crude oil. Such capacity issues in Colombia may require us to transport crude from our Colombian operations
via truck, which may increase the costs of those operations. Road infrastructure is limited in certain areas in which we operate,
and certain communities have used and may continue to use road blockages, which can sometimes interfere with our operations in
these areas. For example, in December 2014, our Colombian production was impacted by approximately 5,000 bopd during the last 13
days of the year by a road blockage, which was restored to normal production levels by the beginning of January 2015.



In Chile, we transport the crude oil we
produce in the Fell Block by truck to ENAP’s processing, storage and selling facilities at the Gregorio Refinery. As of the
date of this annual report, ENAP purchases all of the crude oil we produce in Chile. We rely upon the continued good condition,
maintenance and accessibility of the roads we use to deliver the crude oil we produce. If the condition of these roads were to
deteriorate or if they were to become inaccessible for any period of time, this could delay delivery of crude oil in Chile and
materially harm our business. For example, in January 2011, social and labor unrest resulted in the roads to the Gregorio Refinery
being closed for two days, and we were unable to deliver crude oil to ENAP.



In the Fell Block, we depend on ENAP-owned
gas pipelines to deliver the gas we produce to Methanex, the sole purchaser of the gas we produce. If ENAP’s pipelines were
unavailable, this could have a materially adverse effect on our ability to deliver and sell our product to Methanex, which could
have a material adverse effect on our gas sales. In addition, gas production in some areas in the Tierra del Fuego Blocks and the
Otway and Tranquilo Blocks could require us to build a new network of gas pipelines in order for us to be able to deliver our product
to market, which could require us to make significant capital investments.



While Brazil has a well-developed network
of hydrocarbon pipelines, storage and loading facilities, we may not be able to access these facilities when needed. Pipeline facilities
in Brazil are often full and seasonal capacity restrictions may occur, particularly in natural gas pipelines. Our failure to secure
transportation or access to pipelines or other facilities once we commence operations in the concessions we were awarded in Brazil
on acceptable terms or on a timely basis could materially harm our business.



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In Peru, future production in the Morona
Block is expected to be transported through the existing North Peruvian Pipeline, which is currently out of service due to technical
issues. Though the Peruvian government is implementing a program to maintain the pipeline, significant delays in restoring pipeline
capacity, future technical issues, other general infrastructure problems or social unrest affecting pipeline operation may adversely
affect the recoverability of our future investments, our future production or revenues related to the Morona Block.



In addition, as the Morona Block is located
in a remote area of the tropical rainforest, the development of the project involves that significant infrastructure has to be
built, as processing facilities, storages tanks and an approximately 97 km pipeline from the site to the North Peruvian Pipeline.
Also, as there are no roads available in the surrounding area, logistics will be performed by helicopters or barges during specific
seasons of the year. These issues may lead us to incur significant costs or investments that may not be recoverable through our
commercial activities in the Morona Block.



Our use of seismic data is subject to
interpretation and may not accurately identify the presence of oil and natural gas.



Even when properly used and interpreted,
seismic data and visualization techniques are tools only used to assist geoscientists in identifying subsurface structures as well
as eventual hydrocarbon indicators, and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those
structures. In addition, the use of seismic and other advanced technologies requires significant expenditures and we could incur losses as a result of these expenditures. Because of these uncertainties associated with
our use of seismic data, some of our drilling activities may not be successful or economically viable, and our overall drilling
success rate or our drilling success rate for activities in a particular area could decline, which could have a material adverse
effect on us.



Through our Brazilian operations, we
face operational risks relating to offshore drilling.



Our operations in the BCAM-40 Concession
in Brazil may include shallow-offshore drilling activity in two areas in the Camamu-Almada Basin, which we expect will continue
to be operated by Petrobras.



Offshore operations are subject to a variety
of operating risks and laws and regulations, including among other things, with respect to environmental, health and safety matters,
specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions.
These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities,
compliance costs, fines or penalties that could reduce or eliminate the funds available for exploration, development or leasehold
acquisitions, or result in loss of equipment and properties. For example, the Manati Field has been subject to administrative infraction
notices, which have resulted in fines against Petrobras in an aggregate amount of US$12.5 million, all of which are pending a final
decision of the Brazilian Institute for the Environment and Natural Renewable Resources (Instituto Brasileiro do Meio-Ambiente
e dos Recursos Naturais Renováveis). Although the administrative fines were filed against Petrobras, as a party to the
concession agreement governing the Manati Field, Rio das Contas may be liable up to its participation interest of 10%.



Additionally, offshore drilling generally
requires more time and more advanced drilling technologies, involving a higher-risk of technological failure and usually higher
drilling costs. Offshore projects often lack proximity to existing oilfield service infrastructure, necessitating significant capital
investment in flow line infrastructure before we can market the associated oil or gas of a commercial discovery, increasing both
the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some offshore
reserve discoveries may never be produced economically.



Further, because we are not the operator
of our offshore fields, all of these risks may be heightened since they are outside of our control. We have a 10% interest in the
Manati Field which limits our operating flexibility in such offshore fields. See “—We are not, and may not be in the
future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working
interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts,
associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly-owned, assets.”



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We may suffer delays or incremental costs
due to difficulties in negotiations with landowners and local communities, including native communities, where our reserves are
located.



Access to the sites where we operate requires
agreements (including, for example, assessments, rights of way and access authorizations) with landowners and local communities.
If we are unable to negotiate agreements with landowners, we may have to go to court to obtain access to the sites of our operations,
which may delay the progress of our operations at such sites. In Chile, for example, we have negotiated the necessary agreements
for many of our current operations in the Magallanes Basin. In Brazil, in the event that social unrest continues or intensifies,
this may lead to delays or damage relating to our ability to operate the assets we have acquired or may acquire in our Brazil Acquisitions.



In Colombia, although we have agreements
with many landowners and are in negotiations with others, we expect our costs to increase following current and future negotiations
regarding access to our blocks, as the economic expectations of landowners have generally increased, which may delay access to
existing or future sites. In addition, the expectations and demands of local communities on oil and gas companies operating in
Colombia may also increase. As a result, local communities have demanded that oil and gas companies invest in remediating and improving
public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure
that was previously paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are
now dealing with increasing difficulties resulting from instances of social unrest, temporary road blockages and conflicts with
landowners. For example, in December 2014, production from certain fields in the Llanos 34 Block was affected by a road blockage
resulting in our reduction of production for a period of 13  days that was returned to normal in early January 2015.



There can be no assurance that disputes
with landowners and local communities will not delay our operations or that any agreements we reach with such landowners and local
communities in the future will not require us to incur additional costs, thereby materially adversely affecting our business, financial
condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected government
to restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites.



In Peru, the Morona Block is located in
land inhabited by native communities. Though we have already signed certain agreements with native communities authorizing the
execution of the Environmental Impact Assessment for the Morona Project, similar projects in the Peruvian rainforest have faced
significant social conflicts and work delays due to community claims. Social conflicts or community claims could adversely affect
the recoverability of our future investments, our future production and revenues related to the Morona Block.



Under the terms of some of our various
CEOPs, E&P Contracts and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic
reports in order to retain our rights and establish development areas. Failure to meet these obligations may result in the loss
of our interests in the undeveloped parts of our blocks or concession areas.



In order to protect our exploration and
production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make
and declare discoveries within certain time periods specified in our various special operation contracts (Contratos Especiales
de Operación para la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter “CEOP”),
E&P Contracts and concession agreements, our interests in the undeveloped parts of our license areas may lapse. Should the
prospects we have identified under these contracts and agreements yield discoveries, we may face delays in drilling these prospects
or be required to relinquish these prospects. The costs to maintain or operate the CEOPs, E&P Contracts and concession agreements
over such areas may fluctuate and may increase significantly, and we may not be able to meet our commitments under such contracts
and agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. For example,
in 2016, after fulfilling the committed exploratory commitments, five exploratory blocks were relinquished to the ANP. See “Item 4.
Information on the Company—B. Business Overview—Our operations—Operations in Brazil.”



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In Peru, the rights
to explore and produce hydrocarbons are granted through a license contract signed with Perupetro. The scope and schedule of such
development will depend on us and Petroperu. The license contract could be terminated by Perupetro if the development obligations
included in such agreement are not fulfilled. In addition, there is also an exploratory commitment consisting of the drilling of
one exploratory well every two and a half years. Failure to fulfill the exploratory commitment will lead to acreage relinquishment
materially affecting the project. Moreover, we have entered into a Joint Investment Agreement with Petroperu by which, subject
to the economic and technical feasibility of the Morona Project, we are obliged to bear 100% of capital cost required to carry
out long test to existing well Situche Central 3X, and if we decide to continue with the project after that, to the existing well
Situche Central 2X. In addition, we are required to cover any capital or operational expenditures associated with the project until
December 31, 2020. We expect these expenditures to be substantially reimbursed by Petroperu from revenues associated with future
sales. Failure to fulfill such obligations will result in the loss of our participating interest in the License Contract of the
Morona Block, and subject us to possible damage claims from Petroperu.



For additional details regarding the status
of our operations with respect to our various special contracts and concession agreements, see “Item 4. Information on the
Company—B. Business Overview—Our operations.”



A significant amount of our reserves
or production have been derived from our operations in certain blocks, including the Llanos 34 in Colombia, the Fell Block in Chile,
the BCAM-40 Concession in Brazil and the Morona Block in Peru.



For the year ended December 31, 2016, the
Llanos 34 Block contained 50% of our net proved reserves and generated 66% of our production, the Fell Block contained 17% of
our net proved reserves and generated 17% of our total production, the BCAM-40 Concession contained 7% of our net proved reserves
and generated 13% of our production and the Morona Block contained 25% of our net proved reserves. While our continuing expansion
with new exploratory blocks incorporated in our portfolio mean that the above mentioned blocks may be expected to be a less significant
component of our overall business, we cannot be sure that we will be able to continue diversifying our reserves and production.
Resulting from these, any government intervention, impairment or disruption of our production due to factors outside of our control
or any other material adverse event in our operations in such blocks would have a material adverse effect on our business, financial
condition and results of operations.



Our contracts in obtaining rights to
explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our
CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances.



Under certain CEOPs, E&P Contracts
and concession agreements to which we are or may in the future become parties, we are or may become subject to guarantees to perform
our commitments and/or to make payment for other obligations, and we may not be able to obtain financing for all such obligations
as they arise. If such obligations are not complied with when due, in addition to any other remedies that may be available to other
parties, this could result in cancelation of our CEOPs, E&P Contracts and concession agreements or dilution or forfeiture of
interests held by us. As of December 31, 2016, the aggregate outstanding amount of this potential liability for guarantees was
approximately US$69.8 million, mainly related to capital commitments in Isla Norte, Campanario and Flamenco Blocks in Chile, rounds
11, 12 and 13 concessions in Brazil, three blocks in Argentina and the Llanos 32, VIM-3, and Llanos 34 Blocks in Colombia. See
“Item 4. Information on the Company—B. Business Overview—Our operations” and Note 31(b) to our Consolidated
Financial Statements.



Additionally, certain of the CEOPs, E&P
Contracts and concession agreements to which we are or may in the future become a party are subject to set expiration dates. Although
we may want to extend some of these contracts beyond their original expiration dates, there is no assurance that we can do so on
terms that are acceptable to us or at all, although some CEOPs contain provisions enabling exploration extensions.



In Colombia, our E&P Contracts may
be subject to early termination for a breach by the parties, a default declaration, application of any of the contracts’
unilateral termination clauses or pursuant to termination clauses mandated by Colombian law. Anticipated termination declared by
the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH
and/or a restriction on our ability to engage in contracts with the Colombian government during a certain period of time. See “Item
4. Information on the Company—B. Business Overview—Significant Agreements—Colombia—E&P Contracts.”



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In Chile, our CEOPs provide for early termination
by Chile in certain circumstances, depending upon the phase of the CEOP. For example, pursuant to the Fell Block CEOP, Chile has
the right to terminate the CEOP under certain circumstances if we fail to perform. If the Fell Block CEOP is terminated in the
exploitation phase, we will have to transfer to Chile, free of charge, any productive wells and related facilities, provided that
such transfer does not interfere with our abandonment obligations and excluding certain pipelines and other assets. See “Item
4. Information on the Company—B. Business Overview—Significant Agreements—Chile—CEOPs—Fell Block
CEOP.” If the CEOP is terminated early due to a breach of our obligations, we may not be entitled to compensation. Our CEOPs
for the Tierra del Fuego Blocks, which are in the exploration phase, may be subject to early termination during this phase under
certain circumstances, including if we fail to perform under the terms of the CEOPs, voluntarily relinquish all areas under the
CEOPs or if we cease to operate in the CEOP area or declare bankruptcy. If the Tierra del Fuego Block CEOPs are terminated within
the exploration phase, we are released from all obligations under the CEOPs, except for obligations regarding the abandonment of
fields, if any. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile—CEOPs.”
There can be no assurance that the early termination of any of our CEOPs would not have a material adverse effect on us. In addition,
according to the Chilean Constitution, Chile is entitled to expropriate our rights in our CEOPs for reasons of public interest.
Although Chile would be required to indemnify us for such expropriation, there can be no assurance that any such indemnification
will be paid in a timely manner or in an amount sufficient to cover the harm to our business caused by such expropriation.



In Brazil, concession agreements generally
may be renewed at the ANP’s discretion for an additional period, provided that a renewal request is made at least 12 months
prior to the termination of the concession agreement and there has not been a breach of the terms of the concession agreement.
We expect that all our concession agreements will provide for early termination in the event of: (i) government expropriation for
reasons of public interest; (ii) revocation of the concession pursuant to the terms of the concession agreement; or (iii) failure
by us or our partners to fulfill all of our respective obligations under the concession agreement (subject to a cure period). Administrative
or monetary sanctions may also be applicable, as determined by the ANP, which shall be imposed based on applicable law and regulations.
In the event of early termination of a concession agreement, the compensation to which we are entitled may not be sufficient to
compensate us for the full value of our assets. Moreover, in the event of early termination of any concession agreement due to
failure to fulfill obligations thereunder, we may be subject to fines and/or other penalties.



In Peru, License Contracts for hydrocarbon
exploitation are in force and will remain in effect for 30 years. This term is non-renewable. With regard to the Morona Block,
approximately one-third of the contract term has already elapsed, and twenty years remain. Nevertheless, since May 14, 2013, the
License Contract related to the Morona Block is under force majeure. During a force majeure period contract terms are suspended
(including the term time) as long as the party to the contract is fulfilling certain obligations related to obtaining environmental
permits, as is currently the case with the Morona Block. The term of the agreement will be extended by the same amount of time
it has been suspended by a force majeure event. The concession year expiration is related to approval of environmental impact assessment
(EIA) study for project development. The expiration of the License Contract will occur twenty years after EIA approval. The License Contract is also subject to early termination in case of our breach
of contractual obligations. In such an event, all the existing facilities and wells located in the block will be transferred, without
charge, to Perupetro, and we will have to carry out abandonment plans for remediation and restoration of any polluted area in the
block and for de-commission the facilities that are no longer required for the block’s operations.



Early termination or nonrenewal of any
CEOP, E&P Contract or concession agreement could have a material adverse effect on our business, financial situation or results
of operations.



We may not be able to meet delivery requirements
under the crude sale agreements in Colombia.



We historically sold to several customers
in Colombia, including sales made through wellhead or pipeline. For 2017 and 2018, we expect to sell most of our Colombian production
under long-term agreements with Trafigura. The Trafigura offtake contract began in March 2016 and expires in December 2018.



Under the Trafigura Agreement, we follow
agreed priorities for the volumes to be transported through the ODL Pipeline. For the period March 1, 2016 to September 2016, Trafigura
received 10,000 bopd of our production. The Trafigura Agreement was amended in 2016 and February 2017, setting the current volumes
to be delivered to Trafigura to 12,000 bopd until December 2018. Nonperformance of our obligations of delivery to Trafigura in
terms, amounts and quality of the crude may lead us to pay Trafigura’s fare commitments in the ODL Pipeline for the transport,
dilution and download of crude, and may lead to early termination of the crude sales agreement as well as the immediate repayment
of any amounts outstanding under the prepayment agreement of up to US$100 million, as well as compensation for other damages.



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We sell almost all of our natural gas
in Chile to a single customer, who has in the past temporarily idled its principal facility.



For the year ended December 31, 2016, almost
all of our natural gas sales in Chile were made to Methanex under a long-term contract, the Methanex Gas Supply Agreement, which
expires on April 30, 2017. Sales to Methanex represented 9% of our consolidated revenues for the year ended December 31, 2016.
Methanex also buys gas from ENAP and a consortium that Methanex has formed with ENAP. While our current contract with Methanex
requires it to purchase the entirety of our production of natural gas from the Fell Block, and requires us to sell to Methanex
all of our natural gas production from Fell Block, subject to minor exceptions, if Methanex were to decrease or cease its purchase
of gas from us, this would have a material adverse effect on our revenues derived from the sale of gas. In March 2017, we executed
a new gas supply agreement with Methanex effective from May 1, 2017 to December 31, 2026. Under the new agreement, Methanex commits
to purchase up to 400,000 SCM/d of gas produced by us.



Methanex has two methanol producing facilities
at its Cabo Negro production facility, near the city of Punta Arenas in southern Chile. Methanex relies on local suppliers of natural
gas, including ENAP, for its operations. We alone cannot supply Methanex with all the natural gas it requires for its operations.



In the past, the Methanex plant was idled
due to an anticipated insufficient supply of natural gas. The supply of natural gas decreased during the winter months of 2015
due to the increase in seasonal gas demand from the city of Punta Arenas, to which gas producers, including us, gave priority,
delivering gas to the city through Methanex which re-sold our gas to ENAP. See “Item 4. Information on the Company—B. Business
Overview—Marketing and delivery commitments—Chile.”



However, we cannot be sure that Methanex
will continue to purchase the gas from us, including the above committed levels as from May 1, 2017, or that its efforts to reduce
the risk of future shut-downs will be successful, which could have a material adverse effect on our gas revenues. Additionally,
we cannot be sure that Methanex will have sufficient supplies of gas to operate its plant and continue to purchase our gas production
or that methanol prices would be sufficient to cover the operating costs. We cannot be sure that we would be able to sell our gas
production to other parties or on similar terms, which could have a material adverse effect on our business, financial condition
and results of operations.



We are not, and may not be in the future,
the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests
in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated
costs, or the rate of production of any non-operated and, to an extent, any non-wholly-owned, assets.



As of December 31, 2016, we are not the
operator of approximately 26% or sole owner of approximately 33% of the blocks included in our portfolio. See “Item 4. Information
on the Company—B. Business Overview—Operations in Colombia, Operations in Chile, Operations in Brazil, Operations in
Peru and Operations in Argentina”.



In addition, the terms of the joint venture
agreements or association agreements governing our other partners’ interests in almost all of the blocks that are not wholly-owned
or operated by us require that certain actions be approved by supermajority vote. The terms of our other current or future license
or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have
limited ability to exercise influence over operations or prospects in the blocks operated by our partners, or in blocks that are
not wholly-owned or operated by us. A breach of contractual obligations by our partners who are the operators of such blocks could
eventually affect our rights in exploration and production contracts in some of our blocks in Colombia and Brazil. Our dependence
on our partners could prevent us from realizing our target returns for those discoveries or prospects.



Moreover, as we are not the sole owner
or operator of all of our properties, we may not be able to control the timing of exploration or development activities or the
amount of capital expenditures and may therefore not be able to carry out our key business strategies of minimizing the cycle time
between discovery and initial production at such properties. The success and timing of exploration and development activities operated
by our partners will depend on a number of factors that will be largely outside of our control, including:



| | · | the timing and amount of capital expenditures;
| | - | ----------------------------------------------



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| | · | the operator’s expertise and financial resources;
| | - | -------------------------------------------------



| | · | approval of other block partners in drilling wells;
| | - | ---------------------------------------------------



| | · | the scheduling, pre-design, planning, design and approvals of activities and processes;
| | - | ---------------------------------------------------------------------------------------



| | · | selection of technology; and
| | - | ----------------------------



| | · | the rate of production of reserves, if any.
| | - | -------------------------------------------



This limited ability to exercise control
over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of
operations.



LGI, our strategic partner in Chile and
Colombia, may not consent to our taking certain actions or may eventually decide to sell its interest in our Chilean and Colombian
operations to a third party.



We have a strategic partnership with LGI,
which has a 20% equity interest in GeoPark Chile S.A., (a sociedad anónima cerrada incorporated under the laws of
Chile; hereinafter “GeoPark Chile”), a 14% direct equity interest in GeoPark TdF S.A. (“GeoPark TdF”) (31.2%
taking into account direct and indirect participation through GeoPark Chile) and a 20% equity interest in GeoPark Colombia SAS,
through its equity interest in GeoPark Colombia Coöperatie. Our shareholders’ agreements with LGI in each of Chile and
Colombia provides that we have a right of first offer if LGI decides to sell any of its interest in GeoPark Chile or GeoPark Colombia
Coöperatie. There can be no assurance, however, that we will have the funds to purchase LGI’s interest in Chile and/or
Colombia and that LGI will not decide to sell its shares to a third party whose interests may not be aligned with ours.



In addition, our shareholders’ agreements
with LGI in Chile and Colombia contain provisions that require GeoPark Chile and GeoPark Colombia Coöperatie, the sole shareholder
of GeoPark Colombia SAS, to obtain LGI’s consent before undertaking certain actions. For example, under the terms of the
shareholders’ agreement with LGI in Colombia, LGI must approve GeoPark Colombia’s annual budget and work programs and
mechanisms for funding any such budget or program, the entering into any borrowings other than those provided in an approved budget
or incurred in the ordinary course of business to finance working capital needs, the granting of any guarantee or indemnity to
secure liabilities of parties other than those of our Colombian subsidiary and disposing of any material assets other than those
provided for in an approved budget and work program.



Additionally, pursuant to our agreement with LGI in Colombia, we and LGI have agreed to vote our common shares or otherwise cause GeoPark
Colombia Coöperatie to declare dividends only after allowing for retentions of cash for approved work programs and budgets
capital adequacy requirements, working capital requirements, banking covenants associated with any loan entered into by GeoPark
Colombia Coöperatie and GeoPark Colombia SAS and operational requirements. Our inability or failure to obtain LGI’s
consent or a delay by LGI in granting its consent may restrict or delay the ability of GeoPark Chile, GeoPark TdF or GeoPark Colombia
to take certain actions, which may have an adverse effect on our operations in such countries and on our business, financial condition
and results of operations.



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Acquisitions that we have completed and
any future acquisitions, strategic investments, partnerships or alliances could be difficult to integrate and/or identify, could
divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial
results, including impairment of goodwill and other intangible assets.



One of our principal business strategies
includes acquisitions of properties, prospects, reserves and leaseholds and other strategic transactions, including in jurisdictions
in which we do not currently operate. The successful acquisition and integration of producing properties requires an assessment
of several factors, including:



| | · | recoverable reserves;
| | - | ---------------------



| | · | future oil and natural gas prices;
| | - | ----------------------------------



| | · | development and operating costs; and
| | - | ------------------------------------



| | · | potential environmental and other liabilities.
| | - | ----------------------------------------------



The accuracy of these assessments is inherently
uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally
consistent with industry practices. Our review and the review of advisors and independent reserves engineers will not reveal all
existing or potential problems nor will it permit us or them to become sufficiently familiar with the properties to fully assess
their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental
conditions are not necessarily observable even when an inspection is undertaken. We, advisors or independent reserves engineers
may apply different assumptions when assessing the same field. Even when problems are identified, the seller may be unwilling or
unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual
indemnification for environmental liabilities and acquire properties on an “as is” basis. Even in those circumstances
in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be
able to fulfill its contractual obligations. There can be no assurance that problems related to the assets or management of the
companies and operations we have acquired, or operations we may acquire or add to our portfolio in the future, will not arise in
future, and these problems could have a material adverse effect on our business, financial condition and results of operations.



Significant acquisitions and other strategic
transactions may involve other risks, including:



| | · | diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic
transactions;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------



| | · | challenge and cost of integrating acquired operations, information management and other technology systems and business cultures
with ours while carrying on our ongoing business;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | contingencies and liabilities that could not be or were not identified during the due diligence process, including with respect
to possible deficiencies in the internal controls of the acquired operations; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | challenge of attracting and retaining personnel associated with acquired operations.
| | - | ------------------------------------------------------------------------------------



If we fail to realize the benefits we anticipate
from an acquisition, our results of operations may be adversely affected.



It is also possible that we may not identify
suitable acquisition targets or strategic investment, partnership or alliance candidates. Our inability to identify suitable acquisition
targets, strategic investments, partners or alliances, or our inability to complete such transactions, may negatively affect our
competitiveness and growth opportunities. Moreover, if we fail to properly evaluate acquisitions, alliances or investments, we
may not achieve the anticipated benefits of any such transaction and we may incur costs in excess of what we anticipate.



Future acquisitions financed with our own
cash could deplete the cash and working capital available to adequately fund our operations. We may also finance future transactions
through debt financing, the issuance of our equity securities, existing cash, cash equivalents or investments, or a combination
of the foregoing. Acquisitions financed with the issuance of our equity securities could be dilutive, which could affect the market
price of our stock. Acquisitions financed with debt could require us to dedicate a substantial portion of our cash flow to principal
and interest payments and could subject us to restrictive covenants.



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The PN-T-597 Concession Agreement in
Brazil may not close.



In Brazil, GeoPark
Brasil is a party to a class action filed by the Federal Prosecutor’s Office regarding a concession agreement of exploratory
Block PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and gas bidding round held in November 2013. The
Brazilian Federal Court issued an injunction against the ANP and GeoPark Brasil in December 2013 that prohibited GeoPark Brasil’s
execution of the concession agreement until the ANP conducted studies on whether drilling for unconventional resources would contaminate
the dams and aquifers in the region. On July 17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession agreement,
which included a clause prohibiting GeoPark Brasil from conducting unconventional exploration activity in the area. Despite the
clause containing the prohibition, the judge in the case concluded that the concession agreement should not be executed. Thus,
GeoPark Brasil requested that the ANP comply with the decision and annul the concession agreement, which the ANP’s Board
did on October 9, 2015. The annulment reverted the status of all parties to the status quo ante, which maintains GeoPark
Brasil’s right to the block.



There is no assurance
that we will be able to enter into a concession agreement in the PN-T-597 Block that would be favorable to our exploration goals.
See “Item 8—Financial Information—A. Consolidated statements and other financial information—Legal proceedings.”



The present value of future net revenues
from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.



You should not assume that the present
value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves.
For the year ended December 31, 2016, we have based the estimated discounted future net revenues from our proved reserves on the
12 month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues
from our oil and natural gas properties will be affected by factors such as:



| | · | actual prices we receive for oil and natural gas;
| | - | -------------------------------------------------



| | · | actual cost of development and production expenditures;
| | - | -------------------------------------------------------



| | · | the amount and timing of actual production; and
| | - | -----------------------------------------------



| | · | changes in governmental regulations, taxation or the taxation invariability provisions in our CEOPs.
| | - | ----------------------------------------------------------------------------------------------------



The timing of both our production and our
incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing
and amount of actual future net revenues from proved reserves, and thus their actual value. In addition, the 10% discount factor
we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with us or the oil and natural gas industry in general.



The development of our proved undeveloped
reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved
undeveloped reserves ultimately may not be developed or produced.



As of December 31, 2016, approximately
41% of our net proved reserves are developed. Development of our undeveloped reserves may take longer and require higher levels
of capital expenditures than we currently anticipate. Additionally, delays in the development of our reserves or increases in costs
to drill and develop such reserves will reduce the standardized measure value of our estimated proved undeveloped reserves and
future net revenues estimated for such reserves, and may result in some projects becoming uneconomic, causing the quantities associated
with these uneconomic projects to no longer be classified as reserves. This was due to the uneconomic status of the reserves, given
the proximity to the end of the concessions for these blocks, which does not allow for future capital investment in the blocks.
There can be no assurance that we will not experience similar delays or increases in costs to drill and develop our reserves in
the future, which could result in further reclassifications of our reserves.



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We are exposed to the credit risks of
our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results
of operations.



Our customers may experience financial
problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our
customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under
contractual arrangements.



The combination of declining cash flows
as a result of declines in commodity prices, a reduction in borrowing basis under reserves-based credit facilities and the lack
of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their
ability to make payments or perform on their obligations to us.



Furthermore, some of our customers may
be highly leveraged, and, in any event, are subject to their own operating expenses. Therefore, the risk we face in doing business
with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of
defaulting on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets,
a decrease in our operating cash flows and may also reduce or curtail our customers’ future use of our products and services,
which may have an adverse effect on our revenues and may lead to a reduction in reserves.



We may not have the capital to develop
our unconventional oil and gas resources.



We have identified opportunities for analyzing
the potential of unconventional oil and gas resources in some of our blocks and concessions. Our ability to develop this potential
depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of
agreements with third parties, commodity prices, costs, access to and availability of equipment, services and personnel and drilling
results. In addition, as we have no previous experience in drilling and exploiting unconventional oil and gas resources, the drilling
and exploitation of such unconventional oil and gas resources depends on our ability to acquire the necessary technology, to hire
personnel and other support needed for extraction or to obtain financing and venture partners to develop such activities. Because
of these uncertainties, we cannot give any assurance as to the timing of these activities, or that they will ultimately result
in the realization of proved reserves or meet our expectations for success.



Our operations are subject to operating
hazards, including extreme weather events, which could expose us to potentially significant losses.



Our operations are subject to potential
operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic registration, exploration, production,
development and transportation and storage of crude oil, such as explosions, fires, car and truck accidents, floods, labor disputes,
social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures and spills and mechanical
failure of equipment at our or third-party facilities. Any of these events could have a material adverse effect on our exploration
and production operations, or disrupt transportation or other process-related services provided by our third-party contractors.



We are highly dependent on certain members
of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified
personnel.



The ability, expertise, judgment and discretion
of our management and our technical and engineering teams are key in discovering and developing oil and natural gas resources.
Our performance and success are dependent to a large extent upon key members of our management and exploration team, and their
loss or departure would be detrimental to our future success. In addition, our ability to manage our anticipated growth depends
on our ability to recruit and retain qualified personnel. Our ability to retain our employees is influenced by the economic environment
and the remote locations of our exploration blocks, which may enhance competition for human resources where we conduct our activities,
thereby increasing our turnover rate. There is strong competition in our industry to hire employees in operational, technical and
other areas, and the supply of qualified employees is limited in the regions where we operate and throughout Latin America generally.
The loss of any of our executive officers or other key employees of our technical team or our inability to hire and retain new
qualified personnel could have a material adverse effect on us.



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We and our operations are subject to
numerous environmental, health and safety laws and regulations which may result in material liabilities and costs.



We and our operations are subject to various
international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things,
the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation
and disposal of regulated materials; and human health and safety. Our operations are also subject to certain environmental risks
that are inherent in the oil and gas industry and which may arise unexpectedly and result in material adverse effects on our business,
financial condition and results of operations. Breach of environmental laws could result in environmental administrative investigations
and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal or
civil environmental actions. For instance, non-governmental organizations seeking to preserve the environment may bring actions
against us or other oil and gas companies in order to, among other things, halt our activities in any of the countries in which
we operate or require us to pay fines. Additionally, in Colombia, recent rulings have provided that environmental licenses are
administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts
on our E&P Contracts.



We have not been and may not be at all
times in complete compliance with environmental permits that we are required to obtain for our operations and the environmental
and health and safety laws and regulations to which we are subject. If we fail to comply with such requirements, we could be fined
or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our
operations. If we fail to obtain, maintain or renew permits in a timely manner or at all, our operations could be adversely affected,
impeded, or terminated, which could have a material adverse effect on our business, financial condition or results of operations.
Some environmental licenses related to operation of the Manati Field production system and natural gas pipeline have expired. However,
the operator submitted in a timely manner a request for renewal of those licenses and as such this operation is not in default
as long as the regulator does not state its final position on the renewal.



We have contracted with and intend to continue
to hire third parties to perform services related to our operations. We could be held liable for some or all environmental, health
and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors,
predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy
our obligations, our operations could be suspended, terminated or otherwise adversely affected. There is a risk that we may contract
with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable
to cover any losses associated with their acts and omissions.



Releases of regulated substances may occur
and can be significant. Under certain environmental laws and regulations applicable to us in the countries in which we operate,
we could be held responsible for all of the costs relating to any contamination at our past and current facilities and at any third-party
waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices
might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could be held liable for any
and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous
substances to the environment, property or to natural resources, or affecting endangered species or sensitive environmental areas.
We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in each of the countries
in which we operate, which could result in substantial costs.



In addition, we expect continued and increasing
attention to climate change issues. Various countries and regions have agreed to regulate emissions of greenhouse gases including
methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation
of greenhouse gases and the physical impacts of climate change in the areas in which we, our customers and the end-users of our
products operate could adversely impact our operations and the demand for our products.



Environmental, health and safety laws and
regulations are complex and change frequently, and our costs of complying with such laws and regulations may adversely affect our
results of operations and financial condition. See “Item 4. Information on the Company—B. Business Overview—Health,
safety and environmental matters” and “Item 4. Information on the Company—B. Business Overview—Industry
and regulatory framework.”



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Legislation and regulatory initiatives
relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future
costs of doing business, cause delays or impede our plans, and materially adversely affect our operations.



Hydraulic fracturing of unconventional
oil and gas resources is a process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture
the hydrocarbon-bearing rock thousands of feet below the surface to facilitate a higher flow of hydrocarbons into the wellbore.
We are contemplating such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs, especially
shale formations. We currently are not aware of any proposals in Colombia, Chile, Brazil, Argentina or Peru to regulate hydraulic
fracturing beyond the regulations already in place. However, various initiatives in other countries with substantial shale gas
resources have been or may be proposed or implemented to, among other things, regulate hydraulic fracturing practices, limit water
withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement
temporary or permanent bans on hydraulic fracturing. If any of the countries in which we operate adopts similar laws or regulations,
which is something we cannot predict right now, such adoption could significantly increase the cost of, impede or cause delays
in the implementation of any plans to use hydraulic fracturing for unconventional oil and gas resources.



Our indebtedness and other commercial
obligations could adversely affect our financial health and our ability to raise additional capital, and prevent us from fulfilling
our obligations under our existing agreements and borrowing of additional funds.



As of December 31, 2016, we had US$358.7
million of total indebtedness outstanding on a consolidated basis, which is 100% secured. As of December 31, 2016, our annual debt
service obligation was approximately US$30.6 million, which mainly includes the interest payments under the Notes due 2020 and
the credit facility with Itaú BBA International plc. See “Item 5. Operating and Financial Review and Prospects—B.
Liquidity and Capital Resources—Indebtedness.” We are also restricted from entering into financial arrangements in
some circumstances such as in Colombia where LGI must approve GeoPark Colombia’s financial arrangements. See “Item
4. Information on the Company—B. Business Overview—Significant Agreements—Agreements with LGI—LGI Colombia
Agreements” for more information.



We have also entered into a prepayment
agreement with Trafigura, which allows us to receive up to US$100 million in advance payments from Trafigura on future oil deliveries.



Our indebtedness could:



| | · | limit our capacity to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations
of any of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under
the agreements governing our indebtedness;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, thereby
reducing the availability of our cash flow to fund acquisitions, working capital, capital expenditures and other general corporate
purposes;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | place us at a competitive disadvantage compared to certain of our competitors that have less debt;
| | - | --------------------------------------------------------------------------------------------------



| | · | limit our ability to borrow additional funds;
| | - | ---------------------------------------------



| | · | in the case of our secured indebtedness, lose assets securing such indebtedness upon the exercise of security interests in
connection with a default;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------



| | · | make us more vulnerable to downturns in our business or the economy; and
| | - | ------------------------------------------------------------------------



| | · | limit our flexibility in planning for, or reacting to, changes in our operations or business and the industry in which we operate.
| | - | ----------------------------------------------------------------------------------------------------------------------------------



The indenture governing our Notes due 2020
includes covenants restricting dividend payments. For a description, see “Item 5. Operating and Financial Review and Prospects—B.
Liquidity and Capital Resources—Indebtedness—Notes due 2020.”



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As a result of these restrictive covenants,
we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities
or finance future operations or capital needs. In the year ended December 31, 2016, we did not achieve an Adjusted EBITDA (as defined
in the indenture governing our Notes due 2020) that was sufficient to allow us to incur additional financial indebtedness, other
than certain categories and baskets of permitted debt, as specified in the indenture. Failure to comply with the restrictive covenants
included in our Notes due 2020 would not trigger an event of default.



Similar restrictions could apply to us
and our subsidiaries when we refinance or enter into new debt agreements which could intensify the risks described above.



Our business could be negatively impacted
by security threats, including cybersecurity threats as well as other disasters, and related disruptions.



Our business processes depend on the availability,
capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update
this infrastructure in response to our changing needs. It is critical to our business that our facilities and infrastructure remain
secure. Although we have implemented internal control procedures to assure the security of our data, we cannot guarantee that these
measures will be sufficient for this purpose. The ability of the information technology function to support our business in the
event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected
interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address
immediately the repercussions of a breach. In the event of a breach, key information and systems may be unavailable for a number
of days leading to an inability to conduct our business or perform some business processes in a timely manner. We have implemented
strategies to mitigate the impact from these types of events.



Our employees have been and will continue
to be targeted by parties using fraudulent “spam” and “phishing” emails to misappropriate information or
to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate
emails sent by us but direct recipients to fake websites operated by the sender of the email or request that the recipient send
a password or other confidential information through email or download malware. Despite our efforts to mitigate “spoof”
and “phishing” emails through education, “spoof” and “phishing” activities remain a serious
problem that may damage our information technology infrastructure.



Risks relating to the countries in which we operate



Our operations may be adversely affected
by political and economic circumstances in the countries in which we operate and in which we may operate in the future.



All of our current operations are located
in South America. If local, regional or worldwide economic trends adversely affect the economy of any of the countries in which
we have investments or operations, our financial condition and results from operations could be adversely affected.



Oil and natural gas exploration, development
and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies
or the personnel administering them), changes in laws and policies governing operations of foreign-based companies, expropriation
of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals
from regulators, foreign exchange restrictions, price controls, currency fluctuations, royalty increases and other risks arising
out of foreign governmental sovereignty, as well as to risks of loss due to civil strife, acts of war and community-based actions,
such as protests or blockades, guerilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition,
we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes
in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks are
higher in developing countries, such as those in which we conduct our activities.



The main economic risks we face and may
face in the future because of our operations in the countries in which we operate include the following:



| | · | difficulties incorporating movements in international prices of crude oil and exchange rates into domestic prices;
| | - | ------------------------------------------------------------------------------------------------------------------



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| | · | the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s or Brazil’s
relations with multilateral credit institutions, such as the IMF, will impact negatively on capital controls, and result in a deterioration
of the business climate;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | inflation, exchange rate movements (including devaluations), exchange control policies (including restrictions on remittance
of dividends), price instability and fluctuations in interest rates;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | liquidity of domestic capital and lending markets;
| | - | --------------------------------------------------



| | · | tax policies; and
| | - | -----------------



| | · | the possibility that we may become subject to restrictions on repatriation of earnings from the countries in which we operate
in the future.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------



In addition, our operations in these areas
increase our exposure to risks of guerilla activities, social unrest, local economic conditions, political disruption, civil disturbance,
community protests or blockades, expropriation, piracy, tribal conflicts and governmental policies that may: disrupt our operations;
require us to incur greater costs for security; restrict the movement of funds or limit repatriation of profits; lead to U.S. government
or international sanctions; limit access to markets for periods of time; or influence the market’s perception of the risk
associated with investments in these countries. Some countries in the geographic areas where we operate have experienced, and may
experience in the future, political instability, and losses caused by these disruptions may not be covered by insurance. Consequently,
our exploration, development and production activities may be substantially affected by factors which could have a material adverse
effect on our results of operations and financial condition. We cannot guarantee that current programs and policies that apply
to the oil and gas industry will remain in effect.



Our operations may also be adversely affected
by laws and policies of the jurisdictions, including Bermuda, Colombia, Chile, Brazil, Peru, Argentina, the Netherlands and other
jurisdictions in which we do business, that affect foreign trade and taxation, and by uncertainties in the application of, possible
changes to (or to the application of) tax laws in these jurisdictions. For example, in 2016 the Colombian government introduced
tax reforms with provisions that are effective January 1, 2017. See Note 15 to our Consolidated Financial Statements. With regards
to Chile, although our CEOPs have protection against tax changes through invariability tax clauses, potential issues may arise
on certain aspects not clearly defined in current or future tax reforms.



Changes in any of these laws or policies
or the implementation thereof, and uncertainty over potential changes in policy or regulations affecting any of the factors mentioned
above or other factors in the future may increase the volatility of domestic securities markets and securities issued abroad by
companies operating in these countries, which could materially and adversely affect our financial position, results of operations
and cash flows. Furthermore, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be
successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the
outcome of such dispute. Changes in tax laws may result in increases in our tax payments, which could materially adversely affect
our profitability and increase the prices of our products and services, restrict our ability to do business in our existing and
target markets and cause our results of operations to suffer. There can be no assurance that we will be able to maintain our projected
cash flow and profitability following any increase in taxes applicable to us and to our operations.



The political and economic uncertainty
in Brazil along with the ongoing “Lava Jato” investigations regarding corruption at Petrobras may hinder the growth
of the Brazilian economy and could have an adverse effect on our business.



Our Brazilian operations represent approximately
15% of our revenues as of December 31, 2016. The Brazilian economy has been experiencing a slowdown. Inflation, unemployment and
interest rates have increased more recently and the Brazilian reais has weakened significantly in comparison to the US$. Our results
of operations and financial condition may be adversely affected by the economic conditions in Brazil.



Petrobras and certain other Brazilian companies
in the energy and infrastructure sectors are facing investigations by the Securities Commission of Brazil (Comissão de
Valores Mobiliários), the U.S. Securities and Exchange Commission (“SEC”), the Brazilian Federal Police
and the Brazilian Federal Prosecutor’s Office in connection with corruption allegations (the “Lava Jato” investigations).
Depending on the duration and outcome of such investigations, the companies involved may face downgrades from rating agencies,
funding restrictions and a reduction in their revenues. Given the significance of the companies under investigation including Petrobras,
this could adversely affect Brazil’s growth prospects and could have a protracted effect on the oil and gas industry. In
addition to the recent economic crisis, protests, strikes and corruption scandals have led to a fall in confidence.



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We depend on maintaining good relations
with the respective host governments and national oil companies in each of our countries of operation.



The success of our business and the effective
operation of the fields in each of our countries of operation depend upon continued good relations and cooperation with applicable
governmental authorities and agencies, including national oil companies such as Ecopetrol, ENAP, Petrobras, or Petroperu. For instance,
for the year ended December 31, 2016, 100% of our crude oil and condensate sales in Chile were made to ENAP, the Chilean state-owned
oil company. In addition, our Brazilian operations in BCAM-40 Concession provide us with a long-term off-take contract with Petrobras,
the Brazilian state-owned company that covers approximately 100% of net proved gas reserves in the Manati Field, one of the largest
non-associated gas fields in Brazil. If we, the respective host governments and the national oil companies are not able to cooperate
with one another, it could have an adverse impact on our business, operations and prospects.



Oil and natural gas companies in Colombia,
Chile, Brazil, Peru and Argentina do not own any of the oil and natural gas reserves in such countries.



Under Colombian, Chilean, Brazilian, Peruvian
and Argentine law, all onshore and offshore hydrocarbon resources in these countries are owned by the respective sovereign. Although
we are the operator of the majority of the blocks and concessions in which we have a working and/or economic interest and generally
have the power to make decisions as how to market the hydrocarbons we produce, the Chilean, Colombian, Brazilian, Peruvian and
Argentine governments have full authority to determine the rights, royalties or compensation to be paid by or to private investors
for the exploration or production of any hydrocarbon reserves located in their respective countries.



If these governments were to restrict or
prevent concessionaires, including us, from exploiting oil and natural gas reserves, or otherwise interfered with our exploration
through regulations with respect to restrictions on future exploration and production, price controls, export controls, foreign
exchange controls, income taxes, expropriation of property, environmental legislation or health and safety, this could have a material
adverse effect on our business, financial condition and results of operations.



Additionally, we are dependent on receipt
of government approvals or permits to develop the concessions we hold in some countries. There can be no assurance that future
political conditions in the countries in which we operate will not result changes to policies with respect to foreign development
and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to
undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds
to further such activities. Any delays in receiving government approvals in such countries may delay our operations or may affect
the status of our contractual arrangements or our ability to meet contractual obligations.



Oil and gas operators are subject to
extensive regulation in the countries in which we operate.



The Colombian, Chilean, Brazilian, Peruvian
and Argentine hydrocarbons industries are subject to extensive regulation and supervision by their respective governments in matters
such as the environment, social responsibility, tort liability, health and safety, labor, the award of exploration and production
contracts, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls,
capital expenditures and required divestments. In some countries in which we operate, such as Colombia, we are required to pay
a percentage of our expected production to the government as royalties. See “Item 4. Information on the Company—B.
Business Overview—Industry and regulatory framework—Columbia” and see Note 31 (a) to our Consolidated Financial
Statements.



For example, in Brazil there is potential
liability for personal injury, property damage and other types of damages. Failure to comply with these laws and regulations also
may result in the suspension or termination of operations or our being subjected to administrative, civil and criminal penalties,
which could have a material adverse effect on our financial condition and expected results of operations. We expect to also operate
in a consortium in some of our concessions, which, under the Brazilian Petroleum Law, establishes joint and strict liability among
consortium members, and failure to maintain the appropriate licenses may result in fines of R$10 to R$500 million. In addition,
there is a contractual requirement in Brazilian concession agreements regarding local content, which has become a significant issue
for oil and natural gas companies operating in Brazil given the penalties related with breaches thereof. The local content requirement
will also apply to the production sharing contract regime. See “Item 4. Information on the Company—B. Business
Overview—Our operations—Operations in Brazil.”



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Significant expenditures may be required
to ensure our compliance with governmental regulations related to, among other things, licenses for drilling operations, environmental
matters, drilling bonds, reports concerning operations, the spacing of wells, unitization of oil and natural gas accumulations,
local content policy and taxation.



Colombia has experienced and continues
to experience internal security issues that have had or could have a negative effect on the Colombian economy.



Colombia has experienced internal security
issues, primarily due to the activities of guerrillas, including the Revolutionary Armed Forces of Colombia (Fuerzas Armadas
Revolucionarias de Colombia or FARC). In the past, guerrillas have targeted the crude oil pipelines, including the Oleoducto
Transandino, Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure disrupting the activities
of certain oil and natural gas companies and have resulted in unscheduled shut-downs of transportation systems. These activities,
their possible escalation and the effects associated with them have had and may have in the future a negative impact on the Colombian
economy or on our business, which may affect our employees or assets.



In 2016, the Colombian government and the
FARC signed a peace agreement, pursuant to which the FARC agreed to demobilize its troops and to hand over its weapons to a United
Nations mission within 180 days. Our business, financial condition and results of operations could be adversely affected by rapidly
changing economic or social conditions, including the Colombian government’s response to current peace agreements and negotiations
with other groups, including the ELN, which may result in legislation that increases our tax burden or that of other Colombian
companies.



In addition, from time to time, community
protests and blockades may arise near our operations in Colombia, which could adversely affect our business, financial condition
or results of operations.



Risks related to our common shares



An active, liquid and orderly trading
market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell
our common shares.



Our common shares began to trade on the
New York Stock Exchange (“NYSE”) on February 7, 2014, and as a result have a limited trading history. We cannot predict
the extent to which investor interest in our company will maintain an active trading market on the NYSE, or how liquid that market
will be in the future.



The market price of our common shares may
be volatile and may be influenced by many factors, some of which are beyond our control, including:



| | · | our operating and financial performance and identified potential drilling locations, including reserve estimates;
| | - | -----------------------------------------------------------------------------------------------------------------



| | · | quarterly variations in the rate of growth of our financial indicators, such as net income per common share, net income and
revenues;
| | - | -------------------------------------------------------------------------------------------------------------------------------------



| | · | changes in revenue or earnings estimates or publication of reports by equity research analysts;
| | - | -----------------------------------------------------------------------------------------------



| | · | fluctuations in the price of oil or gas;
| | - | ----------------------------------------



| | · | speculation in the press or investment community;
| | - | -------------------------------------------------



| | · | sales of our common shares by us or our shareholders, or the perception that such sales may occur;
| | - | --------------------------------------------------------------------------------------------------



| | · | involvement in litigation;
| | - | --------------------------



| | · | changes in personnel;
| | - | ---------------------



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| | · | announcements by the company;
| | - | -----------------------------



| | · | domestic and international economic, legal and regulatory factors unrelated to our performance.
| | - | -----------------------------------------------------------------------------------------------



| | · | variations in our quarterly operating results;
| | - | ----------------------------------------------



| | · | volatility in our industry, the industries of our customers and the global securities markets;
| | - | ----------------------------------------------------------------------------------------------



| | · | changes in our dividend policy;
| | - | -------------------------------



| | · | risks relating to our business and industry, including those discussed above;
| | - | -----------------------------------------------------------------------------



| | · | strategic actions by us or our competitors;
| | - | -------------------------------------------



| | · | actual or expected changes in our growth rates or our competitors’ growth rates;
| | - | --------------------------------------------------------------------------------



| | · | investor perception of us, the industry in which we operate, the investment opportunity associated with our common shares and
our future performance;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------



| | · | adverse media reports about us or our directors and officers;
| | - | -------------------------------------------------------------



| | · | addition or departure of our executive officers;
| | - | ------------------------------------------------



| | · | change in coverage of our company by securities analysts;
| | - | ---------------------------------------------------------



| | · | trading volume of our common shares;
| | - | ------------------------------------



| | · | future issuances of our common shares or other securities;
| | - | ----------------------------------------------------------



| | · | terrorist acts;
| | - | ---------------



| | · | the release or expiration of transfer restrictions on our outstanding common shares.
| | - | ------------------------------------------------------------------------------------



We have never declared or paid, and do
not intend to pay in the foreseeable future, cash dividends on our common shares, and, consequently, your only opportunity to achieve
a return on your investment is if the price of our stock appreciates.



We have never paid, and do not intend to
pay in the foreseeable future, cash dividends on our common shares. Any decision to pay dividends in the future, and the amount
of any distributions, is at the discretion of our board of directors and our shareholders, and will depend on many factors, such
as our results of operations, financial condition, cash requirements, prospects and other factors. Due to losses resulting from
the oil price decline, accumulated losses amount to US$260.5 million as of December 31, 2016.



We are also subject to Bermuda legal constraints
that may affect our ability to pay dividends on our common shares and make other payments. Under the Companies Act, 1981 (as amended)
of Bermuda (“Bermuda Companies Act”), we may not declare or pay a dividend if there are reasonable grounds for believing
that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our
assets would thereafter be less than our liabilities. We are also subject to contractual restrictions under certain of our indebtedness.



We are a holding company dependent upon
dividends from our subsidiaries, which may be limited by law and by contract from making distributions to us, which would affect
our financial condition, including the ability to pay dividends on the common shares.



As a holding company, our only material
assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenues and
cash flow is distributions from our subsidiaries. Thus, our ability to pay dividends on the common shares will be contingent upon
the financial condition of our subsidiaries. Our subsidiaries are and will be separate legal entities, and although they may be
wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends,
distributions or otherwise. The ability of our subsidiaries to distribute cash to us is also subject to, among other things, restrictions
that are contained in our and our subsidiaries’ financing (including our Notes due 2020 and GeoPark Brasil’s loan to
finance Rio das Contas) and joint venture agreements (principally our agreements with LGI), availability of sufficient funds in
such subsidiaries and applicable state laws and regulatory restrictions. Claims of creditors of our subsidiaries generally will
have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent
the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our business, financial
condition and results of operations, as well as our ability to pay dividends on the common shares, could be materially adversely
affected.



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Additionally, we may not be able to fully
control the operations and the assets of our joint ventures and we may not be able to make major decisions or take timely actions
with respect to our joint ventures unless our joint venture partners agree. For example, we have entered into shareholder agreements
with LGI in Chile and Colombia that limit the amount of dividends that can be declared or returned to us, certain aspects related
to the management of our Chilean and Colombian businesses, the incurrence of indebtedness, liens and our ability to sell certain
assets. See “—Risks relating to our business—LGI, our strategic partner in Chile and Colombia, may not consent
to our taking certain actions or may eventually decide to sell its interest in our Chilean and Colombian operations to a third
party.” We may, in the future, enter into other joint venture agreements imposing additional restrictions on our ability
to pay dividends.



Sales of substantial amounts of our common
shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to
decline.



We may issue additional common shares or
convertible securities in the future, for example, to finance potential acquisitions of assets, which we intend to continue to
pursue. Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could
cause the market price of our common shares to decline. This could also impair our ability to raise additional capital through
the sale of our equity securities. Under our memorandum of association, we are authorized to issue up to 5,171,949,000 common shares,
of which 59,940,881 common shares were outstanding as of December 31, 2016. We cannot predict the size of future issuances of our
common shares or the effect, if any, that future sales and issuances of shares would have on the market price of our common shares.



Provisions of the Notes due 2020 could
discourage an acquisition of us by a third party.



Certain provisions of the Notes due 2020
could make it more difficult or more expensive for a third party to acquire us, or may even prevent a third party from acquiring
us. For example, upon the occurrence of a fundamental change, holders of the Notes due 2020 will have the right, at their option,
to require us to repurchase all of their notes at a purchase price equal to 101% of the principal amount thereof plus any accrued
and unpaid interest (including any additional amounts, if any) to the date of purchase. By discouraging an acquisition of us by
a third party, these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their
common shares at a premium over prevailing market prices.



Variations in interest rates and exchange
rate on our current and/or future financing arrangements may result in significant increases in our borrowing costs.



As of December 31, 2016, a
portion of our total debt is sensitive to changes in interest rates. At December 31, 2016, the outstanding long-term
borrowing affected by variable rates amounted to US$54.5 million, representing 15% of total borrowings, which was mainly
composed of the loan from Itaú Bank that has a floating interest rate based on LIBOR (the “Rio das Contas Credit
Facility”). For more information, see “Item 4. Information on the Company—B. Business
Overview—Marketing and delivery commitments—Brazil,” and Note 3 in our Consolidated Financial Statements.
Consequently, variations in interest rates could result in significant changes in the amount required to cover our debt
service obligations and our interest expense.



In addition, interest and principal amounts
payable pursuant to debt obligations denominated in or indexed to US$ are subject to variations in the foreign currency exchange
rates that could result in a significant increase in the amount of the interest and principal payments in respect of such debt
obligations.







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Certain
shareholders have substantial control over us and could limit your ability to influence the outcome of key transactions, including
a change of control.



Mr. Gerald E. O’Shaughnessy, our
Chairman, Mr. James F. Park, our Chief Executive Officer, and Mr. Juan Cristóbal Pavez, director, control approximately
30% of our outstanding common shares as of December 31, 2016, holding the shares either directly or through privately held funds.
As a result, these shareholders, if acting together, would be able to influence or control matters requiring approval by our shareholders,
including the election of directors and the approval of amalgamations, mergers or other extraordinary transactions. They may also
have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests.
The concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could
deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might
ultimately affect the market price of our common shares. See “Item 7. Major Shareholders and Related Party Transactions—A. Major
shareholders” for a more detailed description of our share ownership.



As a foreign private issuer, we are subject
to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to
holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed
to receiving or in a manner in which you are accustomed to receiving it.



As a foreign private issuer, the rules
governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities Exchange Act
of 1934, as amended (“Exchange Act”). Although we intend to report quarterly financial results and report certain material
events, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant
events within four days of their occurrence and our quarterly or current reports may contain less information than required under
U.S. filings. In addition, we are exempt from the Section 14 proxy rules, and proxy statements that we distribute will not be subject
to review by the SEC. Our exemption from Section 16 rules regarding sales of common shares by insiders means that you will have
less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have
all the data that you are accustomed to having when making investment decisions. For example, our officers, directors and principal
shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange
Act and the rules thereunder with respect to their purchases and sales of our common shares. The periodic disclosure required of
foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available
information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Information—H.
Documents on display.”



As a foreign private issuer, we will be
exempt from complying with certain corporate governance requirements of the NYSE applicable to a U.S. issuer, including the requirement
that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve
any equity issuance by us which represents 20% or more of our outstanding common shares. As the corporate governance standards
applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under
U.S. law and the NYSE rules as shareholders of companies that do not have such exemptions.



We are an “emerging growth company,”
and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common shares
less attractive to investors.



We are an “emerging growth company,”
as defined in the Jumpstart our Business Startups Act of 2012 (“JOBS Act”), and for as long as we continue to be an
“emerging growth company” we may choose to take advantage of certain exemptions from various reporting requirements
that are applicable to other public companies that are not “emerging growth companies,” including, but not limited
to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes Oxley Act. We cannot
predict if investors will find our common shares less attractive because we will rely on these exemptions. If some investors find
our common shares less attractive as a result, there may be a less active trading market for our common shares and our share price
may be more volatile.



Under the JOBS Act, emerging growth companies
can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably
elected not to avail ourselves of this exemption from new or revised accounting standards, and, therefore, we will be subject to
the same new or revised accounting standards as other public companies that are not emerging growth companies.







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Our internal controls over financial
reporting may not be effective which could have a significant and adverse effect on our business and reputation.



We have evaluated our internal controls
for our financial reporting and have determined our controls were effective for the fiscal year ended December 31, 2016. As long
as we qualify as an “emerging growth company” as defined by the JOBS Act, we will not be required to obtain an auditor’s
attestation report on our internal controls in future annual reports on Form 20-F as otherwise required by Section 404(b)
of the Sarbanes-Oxley Act. Accordingly, our independent registered public accounting firm did not perform an audit of our internal
control over financial reporting for the fiscal year ended December 31, 2016. Had our independent registered public accounting
firm performed an attestation on our internal control over financial reporting, it is possible that their opinion on our internal
controls could have differed from ours which could harm our reputation and share value.



There are regulatory limitations on the
ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make.



The Bermuda Monetary Authority (“BMA”),
must specifically approve all issuances and transfers of securities of a Bermuda exempted company like us unless it has granted
a general permission. We are able to rely on a general permission from the BMA to issue our common shares, and to freely transfer
our common shares as long as the common shares are listed on the NYSE and/or other appointed stock exchange, to and among persons
who are non-residents of Bermuda for exchange control purposes. Any other transfers remain subject to approval by the BMA and such
approval may be denied or delayed.



We are a Bermuda company, and it may
be difficult for you to enforce judgments against us or against our directors and executive officers.



We are incorporated as an exempted company
under the laws of Bermuda and substantially all of our assets are located in Colombia, Chile, Argentina, Brazil and Peru. In addition,
most of our directors and executive officers reside outside the United States and all or a substantial portion of the assets of
such persons are located outside the United States. As a result, it may be difficult or impossible to effect service of process
within the United States upon us, or to recover against us on judgments of U.S. courts, including judgments predicated upon the
civil liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda against us or our directors
and officers in the first instance for violation of U.S. federal securities laws because these laws have no extraterritorial application
under Bermuda law and do not have force of law in Bermuda. However, a Bermuda court may impose civil liability, including the possibility
of monetary damages, on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause
of action under Bermuda law.



There is no treaty in force between the
United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters.
As a result, whether a United States judgment would be enforceable in Bermuda against us or our directors and officers depends
on whether the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors
and officers, as determined by reference to Bermuda conflict of law rules. A judgment debt from a U.S. court that is final and
for a sum certain based on U.S. federal securities laws will not be enforceable in Bermuda unless the judgment debtor had submitted
to the jurisdiction of the U.S. court, and the issue of submission and jurisdiction is a matter of Bermuda (not U.S.) law.



In addition, and irrespective of jurisdictional
issues, the Bermuda courts will not enforce a U.S. federal securities law that is either penal or contrary to Bermuda public policy.
An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the
instance of the state in its sovereign capacity, will not be entertained by a Bermuda court. Certain remedies available under the
laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, would not be available under Bermuda
law or enforceable in a Bermuda court, as they would be contrary to Bermuda public policy.



The transfer of our common shares may
be subject to capital gains taxes pursuant to indirect transfer rules in Chile.



In September 2012, Chile established “indirect
transfer rules,” which impose taxes, under certain circumstances, on capital gains resulting from indirect transfers of shares,
equity rights, interests or other rights in the equity, control or profits of a Chilean entity, as well as on transfers of other
assets and property of permanent establishments or other businesses in Chile (“Chilean Assets”). As we indirectly own
Chilean Assets, the indirect transfer rules would apply to transfers of our common shares provided certain conditions outside of
our control are met. If such conditions were present and as a result the indirect transfer rules were to apply to sales of our
common shares, such sales would be subject to indirect transfer tax on the capital gain that may be determined in each transaction.
For a description of the indirect transfer rules and the conditions of their application see “Item 10. Additional Information—E. Taxation—Chilean
tax on transfers of shares.”



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ITEM 4. INFORMATION ON THE COMPANY



| | A. | History and development of the company
| | -- | --------------------------------------



General



We were incorporated as an exempted company
pursuant to the laws of Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our shareholders approved a change
in our name to GeoPark Limited, effective from July 31, 2013. We maintain a registered office in Bermuda at Cumberland House, 9th
Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. Our principal executive offices are located at Nuestra Señora de los
Ángeles 179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, and Florida 981, 1st floor, Buenos Aires, Argentina,
telephone number +5411 4312 9400. Our website is www.geo-park.com. The information on our website does not constitute part of this
annual report.



Our company



We are a leading independent oil and natural
gas exploration and production (“E&P”) company with operations in Latin America and a proven track record of growth
in production and reserves since 2006. We operate in Colombia, Chile, Brazil, Peru and Argentina.



We produced a net average of 22.4
mboepd during the year ended December 31, 2016, of which 70%, 17% and, 13% were, respectively, in Colombia, Chile, and
Brazil, and of which 75% was oil. Currently, we are ranked as the third largest private oil and gas operator in Colombia and
the first private oil and gas operator in Chile.



We have built our company around three
principal capabilities:



| | · | as an Explorer, which is our ability, experience, methodology and creativity to find and develop oil and gas reserves in the
subsurface, based on the best science, solid economics and ability to take the necessary managed risks.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | as an Operator, which is our ability to execute in a timely manner and to have the know-how to profitably drill for, produce,
treat, transport and sell our oil and gas – with the drive and persistence to find solutions, overcome obstacles, seize opportunities
and achieve results.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | as a Consolidator, which is our ability and initiative to assemble the right balance and portfolio of upstream assets in the
right hydrocarbon basins in the right regions with the right partners and at the right price – coupled with the visions and
skills to transform and improve value above ground.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We believe that our risk and capital management
policies have enabled us to compile a geographically diverse portfolio of properties that balances exploration, development and
production of oil and gas. These attributes have also allowed us to raise capital and to partner with premier international companies.
Finally, we believe we have developed a distinctive culture within our organization that promotes and rewards partnership, entrepreneurship
and merit. Consistent with this approach, all of our employees are eligible to participate in our long-term incentive program,
which is the Performance-Based Employee Long-Term Incentive Program. See “Item 6. Directors, Senior Management and Employees—B.
Compensation—Equity Incentive Compensation—Performance-Based Employee Long-Term Incentive Program.”



Our regional platform and risk-balanced
portfolio has been built following a proactive but conservative long term technical approach, converting projects into successful
value-generating assets.



History



We were founded in 2002 by Gerald E. O’Shaughnessy
and James F. Park, who have over 30 years of international oil and natural gas experience, respectively, and who collectively hold
approximately 25% of our common shares as of the date of this annual report. Mr.
O’Shaughnessy currently serves as our Chairman and Mr. Park currently serves as our Chief Executive Officer and Deputy Chairman.



33


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Our history commenced with the purchase
of AES Corporation’s upstream oil and natural gas assets in Chile and Argentina. Those assets included a non-operating working
interest in the Fell Block in Chile, which at that time was operated by ENAP, the Chilean state-owned hydrocarbon company, and
operating working interests in the Del Mosquito, Cerro Doña Juana and Loma Cortaderal Blocks in Argentina. Since 2002, our
business has grown significantly.



In 2006, after demonstrating our technical
expertise and committing to an exploration and development plan, we obtained a 100% operating working interest in the Fell Block
from the Republic of Chile. Also in 2006, the International Finance Corporation (“IFC”), a member of the World Bank
Group, became one of our principal shareholders, and we listed our common shares on AIM, a market operated by the London Stock
Exchange plc, in an initial public offering of common shares outside the United States. Subsequently, in 2008 and 2009, we issued
and sold additional common shares outside the United States.



In 2008 and 2009, we continued our growth
in Chile by acquiring operating working interests in each of the Otway and Tranquilo Blocks, and by forming partnerships with Pluspetrol,
Wintershall, Methanex and IFC.



In 2010, we formed a strategic partnership
with LGI, a Korean conglomerate, to jointly acquire and develop upstream oil and gas projects in Latin America. LGI’s business
includes a portfolio of energy and raw material projects, including oil and gas projects in the Middle East and in Southeast and
Central Asia.



In 2011, ENAP awarded us the opportunity
to obtain operating working interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra del Fuego, Chile, which
we refer to collectively as the Tierra del Fuego Blocks, and in 2012, jointly with ENAP, we entered into CEOPs with Chile for the
exploration and exploitation of hydrocarbons within these blocks.



Also in 2011, LGI acquired a 20% equity
interest in GeoPark Chile and a 14% equity interest in GeoPark TdF for US$148.0 million. LGI also provided GeoPark TdF with US$84.0
million in standby letters of credit to partially secure the US$101.4 million performance bond required by the Chilean government
to guarantee GeoPark TdF’s obligations with respect to the minimum work program under the Tierra del Fuego CEOPs. Our agreement
with LGI in the Tierra del Fuego Blocks allows us to earn back up to 12% equity participation in GeoPark TdF, depending on the
success of our operations in Tierra del Fuego. See “Item 10. Additional Information—C. Material contracts.”



In the first quarter of 2012, we moved
into Colombia by acquiring three privately held E&P companies: (i) Winchester Oil and Gas S.A. (now GeoPark Colombia PN S.A.
Sucursal Colombia), a Colombian branch of a sociedad anónima incorporated under the laws of Panama, which merged
into GeoPark Colombia SAS (“Winchester”), (ii) La Luna Oil Company Limited S.A., a sociedad anónima incorporated
under the laws of Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) GeoPark Cuerva LLC, formerly known
as Hupecol Caracara LLC, a limited liability company incorporated under the laws of the state of Delaware, which merged into GeoPark
Colombia SAS (“Cuerva”). These acquisitions provided us with an attractive platform in Colombia that currently includes
working interests and/or economic interests in 9 blocks located in the Llanos and Magdalena Basins.



In December 2012, LGI acquired a 20% equity
interest in GeoPark Colombia for US$20.1 million, including the assumption of existing debt and the commitment to provide additional
funding to cover LGI’s share of required future investments in Colombia. Our agreement with LGI in Colombia allows us to
earn back up to 12% equity participation in GeoPark Colombia, depending on the success of our operations in Colombia. See “Item
10. Additional Information—C. Material contracts”. We believe our partnership with LGI represents a positive independent
assessment and validation of the quality of our Chilean and Colombian asset inventory, the extent of our technical and operational
expertise and the ability of our management to structure and effect significant transactions.



In May 2013, we entered into agreements
to expand our operations to Brazil. See “—B. Business Overview—Our operations—Operations in Brazil.”



In February 2014, we commenced trading
on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted
to and exercised by the underwriters, through the issuance of 13,999,700 common shares.



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In July 2014, we were awarded a new exploratory
license, the VIM-3 Block, during the 2014 Colombia Bidding Round, carried out by the ANH.



In August 2014, we and Pluspetrol were
awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding Round in Argentina.
The blocks are located in the Neuquén Basin, Argentina’s largest producing hydrocarbon basin.



In October 2014, we entered into an agreement
to expand our footprint into Peru through the acquisition of Morona Block in a joint venture with Petroperu. Petroperu awarded
a 75% working interest in and operatorship of the Morona Block to us. The agreement was subject to regulatory approval, which was
completed in December 2016, as described below.



In July 2015, we signed a farm-in agreement
with Wintershall for the CN-V Block in Argentina. In October 2015, we were awarded four exploratory blocks in the Brazilian ANP
Bid Round 13 in the Reconcavo and Potiguar Basins.



In December 2015, as part of our long term
effort to build an upstream platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo Alfa for onshore projects,
however, no blocks were awarded.



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



See “Item 3. Key Information—D. Risk
factors—Risks relating to our business.”



| | B. | Business Overview
| | -- | -----------------



We are a leading independent oil and natural
gas exploration and production (“E&P”), company with operations in Latin America and a proven track record of growth
in production and reserves since 2006. We operate in Colombia, Chile, Brazil, Peru and Argentina.



We have grown our business through
drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. Since
our inception, we have supported our growth through our prospect development efforts, drilling program, long-term
strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing
and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and
gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and
engineers, including professionals with specialized expertise in the geology of Colombia, Chile, Brazil, Peru and
Argentina.



Oil industry situation and the impact on our operations



As a consequence of the oil price decline
which started in the second half of 2014 (WTI and Brent, the main international oil price markers, fell by more than 60% between
August 2014 and March 2016), the Company has undertaken decisive measures to ensure its ability to both maximize the work program
and preserve its cash. For more information see “Item 3. Key Information—D. Risk Factors—Risks Relating to our
Business—The current oil price crisis has impacted  our operations and corporate strategy” and “Item 4. Information
on the Company –B. Business Overview—2017 Strategy and Outlook.”



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The following map shows the countries in
which we have blocks with working and/or economic interests as of December 31, 2016. For information on our working interests in
each of these blocks, see “—Our assets” below.










| | (1) | The PN-T-57 is still subject to the entry into the concession agreement and absence of legal impediments, by the ANP in the
Parnaíba Basin. See “—Our operations—Operations in Brazil.”
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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The following table sets forth our net
proved reserves and other data as of and for the year ended December 31, 2016.



|         |  | For
    the year ended December 31, 2016
|-------- |  | ----------------------------------------
|Country  |  | Oil
    (mmbbl)                         
|Colombia |  |                                         
|Chile    |  |                                         
|Brazil   |  |                                         
|Peru     |  |                                         
|Total    |  |                                         



Our commitment
to growth has translated into a strong compounded annual growth rate (“CAGR”), of 19% for production in the period
from 2012 to 2016, as measured by boepd in the table below.



|                                |  | For the year ended December 31,
|------------------------------- |  | -------------------------------
|                                |  | 2016                           
|Average net production (mboepd) |  |                                
|% oil                           |  |                                





The following
table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of
December 31, 2016.



|                                             |  | Average daily production            
|-------------------------------------------- |  | ------------------------------------
|                                             |  | For the year ended December 31, 2016
|                                             |  | Colombia                            
|Oil production                               |  |                                     
|Total crude oil production (bopd)            |  |                                     
|Natural gas production                       |  |                                     
|Total natural gas production (mcf/day)       |  |                                     
|Oil and natural gas production               |  |                                     
|Total oil and natural gas production (mboed) |  |                                     



Our assets



According to the D&M Reserves Report,
as of December 31, 2016, the blocks in Colombia, Chile, Brazil and Peru in which we have a working interest had 73.6 mmboe of net
proved reserves, with 51%, 17%, 7% and 25% of such net proved reserves located in Colombia, Chile, Brazil and Peru, respectively.



We produced a net average of 22.4 mboepd
during the year ended December 31, 2016 of which 70%, 17%, and 13%, were in Colombia, Chile and Brazil, respectively, and of which
75% was oil.



We are the operator of a majority of the
blocks in which we have a working interest.



Our strengths



We believe that we benefit from the following
competitive strengths:



High quality and diversified asset base
built through a successful track record of organic growth and acquisitions



Our assets include a diverse portfolio
of oil- and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys. Throughout
our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited
assets and turn them into valuable, productive assets as illustrated below.



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| | · | In 2002, we acquired a non-operating working interest in the Fell Block in Chile, which at the time had no material oil and
gas production or reserves despite having been actively explored and drilled over the course of more than 50 years. Since 2006,
when we became the operator of the Fell Block we performed active exploration and development drilling that resulted in multiple
oil and gas discoveries.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | In 2012, the acquisitions of Winchester, Luna and Cuerva in Colombia gave us access to attractive exploratory and
                                                                                                             productive acres. In the
                                                                                                             Llanos Basin, we pioneered a new play type combining structural and stratigraphic traps. Since we started activity in the
                                                                                                             Llanos 34 Block, we were able to perform an active exploration and development drilling campaign, which resulted in multiple
                                                                                                             new discoveries including the Tigana and Jacana fields.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | In 2013, the acquisition of Rio das Contas, which closed on March 31, 2014, gave us a 10% working interest in the BCAM-40 Concession,
including the shallow-depth offshore Manati and Camarão Norte Fields in the Camamu-Almada Basin in the State of Bahia. The
Manati Field is operated by Petrobras (with a 35% working interest), the Brazilian national company and the largest oil and gas
operator in Brazil. Our Rio das Contas acquisition in Brazil provides us with a long-term off-take contract with Petrobras that
covers approximately 100% of net proved gas reserves in the Manati Field, a valuable relationship with Petrobras and an established
local platform and presence.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | In 2014, we entered into an agreement to expand our footprint into Peru through the acquisition of the Morona Block in a joint
venture with Petroperu. The Morona Block contains the Situche Central oil field, and offers a large exploration potential with
several high impact prospects and plays. The joint venture agreement was subject to regulatory approval, which we received in December
2016. See “—Our operations—Operations in Peru.”
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Significant drilling inventory and resource
potential from existing asset base



Our portfolio includes large land holdings
in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological formations,
which provide a number of attractive opportunities with varying levels of risk. Our drilling inventory and our development plans
target locations that provide attractive economics and support a predictable production profile.



Our geoscience team continues to identify
new potential accumulations and expand our inventory of prospects and drilling opportunities.



Funding Platform



We have historically
benefited from consistent cash flows and access to debt and equity capital markets, as well as other funding sources, which have
provided us with funds to finance our organic growth and the pursuit of potential new opportunities. The significant decline in oil prices since
the end of 2014 significantly impacted our revenues and results from operations for the year ended December 31, 2016. We generated US$82.9 million,
US$25.9 million and US$230.7 million in cash from operations in the years ended December 31, 2016, 2015 and 2014, respectively,
and had US$73.6 million and US$82.7 million in cash and cash equivalents as of December 31, 2016 and 2015, respectively. As of
December 31, 2016 we had US$358.7 million of total financial debt with over 80% of our debt maturing in 2020. Our short-term objectives
are to preserve cash. See “—Our long-term strategy” below.



In February 2013, we issued US$300.0 million
aggregate principal amount of 7.50% senior secured notes due 2020 (“Notes due 2020”). The Notes due 2020 contain incurrence-based
limitations on the amount of indebtedness we can incur See “Item 5. Operating and Financial Review and Prospects—Liquidity
and capital resources—Indebtedness—Notes due 2020—Covenants.”



In February 2014, we commenced trading
on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted
to and exercised by the underwriters, through the issuance of 13,999,700 common shares.



In March 2014, we borrowed US$70.5 million
pursuant to a five-year term variable interest secured loan, secured by the benefits we receive under the Purchase and Sale Agreement
for Natural Gas with Petrobras, equal to 6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das Contas acquisition.
In March 2015, we reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting to approximately
US$15 million), which were divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) to increase
the variable interest rate equal to the 6-month LIBOR + 4.0%.



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In December 2015, we entered into an offtake
and prepayment agreement with Trafigura under which we sell and deliver a portion of our Colombian crude oil production to Trafigura.
The offtake agreement also provides us with prepayment of up to US$100 million, subject to applicable volumes corresponding to
the terms of the agreement, in the form of prepaid future oil sales. Following subsequent amendments in February 2017, the availability
period under the prepayment agreement was extended until June 30, 2017.



Highly committed founding shareholders
and technical and management teams with proven industry expertise and technically-driven culture



Our founding shareholders, management and
operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record
in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition
and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture,
which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success
of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus
its knowledge, skills and experience on finding and developing oil and gas fields.



In addition, we strive to provide a safe
and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace
for capable energy professionals.



Our CEO, Mr. James Park, has been involved
in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, drilling and
production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and
capital raising for the industry. As of March 15, 2017, Mr. Park held 13.2% of our outstanding common shares.



Our Chairman, Mr. Gerald O’Shaughnessy,
has been actively involved in the oil and gas business internationally and in North America since 1976. As of March 15, 2017, Mr.
O’Shaughnessy held 12.1% of our outstanding common shares.



Our management and operating team has an
average experience in the energy industry of approximately 25 years in companies such as Chevron, San Jorge, Petrobras, Total,
Pluspetrol, ENAP and YPF, among others. Throughout our history, our management and operating team has had success in unlocking
unexploited value from previously underdeveloped assets.



In addition, as of March 15, 2017, our
executive directors, management and employees (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy and Mr. James
F. Park) owned approximately 1.7% of our outstanding common shares, aligning their interests with those of our shareholders and
helping retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management
and Employees—B. Compensation.” Our founding shareholders are also involved in our daily operations and strategy.



Long-term strategic partnerships and
strong strategic relationships, such as with LGI, provide us with additional funding flexibility to pursue further acquisitions



We benefit from a number of strong partnerships
and relationships. In March 2010, we entered into a framework agreement with LGI to establish a strategic growth partnership to
jointly acquire and invest in oil and natural gas projects throughout Latin America. In May 2011, our partnership with LGI was
strengthened by LGI’s acquisition of a 10% equity interest in our existing Chilean operations. In October 2011, LGI acquired
an additional 10% equity interest in GeoPark Chile and a 14% equity interest in GeoPark TdF, and agreed to provide additional financial
support for the further development of the Tierra del Fuego Blocks. In December 2012, LGI acquired a 20% equity interest in our
Colombian business. As of the date of this annual report, we are the only independent E&P company in which LGI has equity investments
in Latin America. See “—Significant Agreements—Agreements with LGI” for additional information relating
to these agreements.



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In addition, the IFC has been one of our
shareholders since 2006, holding an 5.8% equity interest in us as of December 31, 2016. In Chile, we have strong long-term commercial
relationships with Methanex and ENAP, and in Colombia, we have developed a strong relationship with Ecopetrol, the Colombian state-owned
oil and gas company. In Brazil, we believe we will continue to derive benefit from the long-term relationship GeoPark Brasil (formerly
Rio das Contas) has with Petrobras.



2017 Strategy and Outlook



Oil prices were volatile since the end
of 2014. In preparation for continued volatility, we have developed multiple scenarios for our 2017 capital expenditure program.



Our preliminary base capital program for
2017 considers a reference oil price assumption of US$45-US$50 per barrel and calls for approximately US$80 million-US$90 million
to fund our exploration and development, which we intend to fund through cash flows from operations and cash-in-hand, to be allocated
approximately as follows:



| | · | Colombia: US$60-65 million. Focus on Llanos 34 Block to develop, appraise and further explore potential of the Tigana/Jacana
oil play
| | - | -------------------------------------------------------------------------------------------------------------------------------------



| | · | Chile: US$10-12 million. Focus on gas growth opportunities and business optimization at the Fell Block
| | - | ------------------------------------------------------------------------------------------------------



| | · | Brazil: US$5-7 million. Initiate exploration drilling in onshore blocks. Work program also includes maintenance activities
at Manati production platform
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Argentina: US$5-7 million. Initiate exploration drilling in CN-V, Sierra del Nevado and Puelen blocks in the Neuquen Basin
| | - | --------------------------------------------------------------------------------------------------------------------------



In addition, we have developed downside
and upside work program scenarios based on different oil prices and project performance. The downside scenario work program considers
a reference oil price assumption below US$40 per barrel and consists of an alternative capital expenditure program of approximately
US$50 million-US$60 million consisting mainly of certain low risk and quick cash flow generating projects. The upside scenario
work program considers a reference oil price assumption of US$50 per barrel or higher and consists of an alternative capital expenditure
program of approximately US$110 million-US$120 million to be selected from identified projects designed to increase reserves and
production.



During the year ended December 31, 2016,
we entered into derivative financial instruments to manage our exposure to oil price risk. These derivatives were zero-premium
collars and were placed with major financial institutions and commodity traders. We entered into the derivatives under ISDA Master
Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs
under the instruments and protect the Company from potential non-performance risk by its counterparties. See Note 36 to our Consolidated
Financial Statements for details regarding Commodity Risk Management Contracts.



Our long-term strategy



Continue to grow a risk-balanced asset
portfolio



We intend to continue to focus on maintaining
a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing
production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In
general, when we enter a new country we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term
possibility of production, to generate cash flows; (ii) an inventory of adjacent prospects that can offer medium-term upside for
steady growth; and (iii) a periphery of higher-risk projects which have a potential to generate significant upside in the long
run.



For example, in Colombia, we
acquired three companies simultaneously to pursue a risk-balanced approach: one company had mainly proven production and
reserves to provide us with a steady cash flow base, and the remaining had highly prospective exploration license blocks.
Within four years of entering Colombia, we made multiple oil discoveries in block Llanos 34 that allowed us to increase
production and cash flows.



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We believe this approach will allow us
to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside potential. See
“—Our operations.”



Maintain conservative financial policies



We seek to maintain a prudent and sustainable
capital structure and a strong financial position to allow us to maximize the development of our assets and capitalize on business
opportunities as they arise. We intend to remain financially disciplined by limiting substantially all our debt incurrence to identified
projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers
in addition to the international capital markets.



Pursue strategic acquisitions in Latin
America



We have historically benefited from, and
intend to continue to grow through, strategic acquisitions. Our Colombian acquisitions highlight our ability to identify
and execute opportunities. These acquisitions have provided us with an additional attractive platforms in those countries. Our
enhanced regional portfolio, primarily in investment-grade countries, and strong partnerships position us as a regional consolidator.
We intend to continue to grow through strategic acquisitions and potentially in other countries in Latin America. Our acquisition
strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside
potential, keeping a balanced mix of oil- and gas-producing assets (though we expect to remain weighted towards oil) and focusing
on both assets and corporate targets. For example, during 2015, as part of our long term effort to build an upstream platform in
Mexico, we participated in the Mexican Bid Round 1.3 with Grupo Alfa for onshore projects, however, no blocks were awarded.



Continue to foster a technically-driven
culture and to capitalize on local knowledge



We intend to continue to deliberately and collectively pursue
strategies that maximize value. For this purpose, we intend to continue expanding our technical teams and to foster a culture that
rewards talent according to results. For example, we have been able to maintain the technical teams we inherited through our Colombian
and Brazilian acquisitions. We believe local technical and professional knowledge is key to operational and long-term success and
intend to continue to secure local talent as we grow our business in different locations.



Maintain a high degree of operatorship



As of the date of this Annual Report, we
are and intend to continue to be, the operator of a majority of the blocks and concessions in which we have working interests.
Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically
and efficiently. We believe that this strategy has allowed, and will continue to allow, us to leverage our unique culture and our
talented technical, operating and management teams.



Maintain our commitment to environmental
and social responsibility



A major component of our business strategy
is our focus on our environmental and social responsibility. We are committed to minimizing the impact of our projects on the environment.
We also aim to create mutually beneficial relationships with the local communities in which we operate in order to enhance our
ability to create sustainable value in our projects. In line with the IFC’s standards, our commitment to our environmental
and social responsibilities is a major component of our business strategy. These commitments are embodied in our in-house designed
Environmental, Health, Safety and Security management program, which we refer to as “S.P.E.E.D.” (Safety, Prosperity,
Employees, Environment and Community Development). Our S.P.E.E.D. program was developed in accordance with several international
quality standards, including ISO 14001 for environmental management issues, OHSAS 18001 for occupational health and safety management
issues, SA 8000 for social accountability and workers’ rights issues, and applicable World Bank standards. See “—Health,
safety and environmental matters.”



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Our operations



We have a well-balanced portfolio of assets
that includes working and/or economic interests in 26 hydrocarbons blocks, 25 of which are onshore blocks, including 6 in production
as of December 31, 2016, as well as in an additional shallow-offshore concession in Brazil that includes the Manati Field. In addition,
we have one concession in Brazil, the PN-T-597 Block that is subject to the entry into the concession agreement by the ANP.



Operations in Colombia



Our Colombian assets currently give us
access to more than 600,000 gross exploratory and productive acres across 8 blocks in what we believe to be one of South America’s
most attractive oil and gas geographies.



Since we entered Colombia in 2012, we have
achieved consistent growth in our oil production and proved reserves in Colombia, mainly achieved through successful exploration
and development activities we made at our operated Llanos 34 Block, which as of December 31, 2016 accounts for 93% of our production
and 99% of our proved reserves in Colombia.



The table below shows average production
and proved oil reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, 2016, 2015 and 2014:



|                                        | 2016 | 2015 | 2014
|--------------------------------------- | ---- | ---- | ----
|Average net production (mboepd)         | 15.5 | 13.2 | 10.7
|Net proved reserves at year-end (mmbbl) | 37.3 | 30.4 | 24.7



Highlights of the year ended December 31,
2016 related to our operations in Colombia included:



| | · | Successful drilling campaign with 6 gross wells drilled and put into production in the Jacana and Tigana oil fields in the
Llanos 34 Block;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------



| | · | Average net production increased by 17%, to 15.5 mboepd in 2016 from 13.2 mboepd in 2015;
| | - | -----------------------------------------------------------------------------------------



| | · | Proved oil reserves increased by 23% to 37.3 mmbbls at year-end 2016, from 30.4 mmbbls at year-end 2015 after producing 5.7
mmbbl;
| | - | ----------------------------------------------------------------------------------------------------------------------------------



| | · | Capital expenditures were reduced by 15% to US$26.2 million in 2016 from US$30.7 million in 2015; and
| | - | -----------------------------------------------------------------------------------------------------



| | · | Successful cost reduction efforts impacting Production and operating costs that represented a 25% reduction, to US$36.6 million
in 2016 as compared to US$48.8 million in 2015.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Our interests in Colombia include working
interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to
an E&P Contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues
from a given block based on bilateral agreements with the concessionaires.



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The map below shows the location of the
blocks in Colombia in which we have working and/or economic interests.







43


Table of Contents


The table summarizes information about
the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2016.



|Block          | Gross
        acres
        (thousand
        acres) | Working
        interest(1) | Partners(2) | Operator | Net
        proved
        reserves
        (mmboe)(3) | Production
        (boepd) | Basin     | Concession
        expiration year                   
|-------------- | ---------------------------------------------------- | --------------------------- | ----------- | -------- | ------------------------------------------------------ | -------------------------- | --------- | -----------------------------------------------------
|Llanos 34      | 82.2                                                 | 45.0%                       | Parex       | GeoPark  | 37.1                                                   | 14,890                     | Llanos    | Exploration: 2017Exploitation: 2039                  
|La Cuerva      | 47.8                                                 | 100.0%                      | —           | GeoPark  | —                                                      | 388                        | Llanos    | Exploration: 2014Exploitation: 2038                  
|Yamú           | 11.2                                                 | 89.5/100%(4)                | —           | GeoPark  | 0.1                                                    | 7                          | Llanos    | Exploration: 2013
        
        Production: 2036  
|Llanos 17      | 108.8                                                | 36.8%                       | Parex       | Parex    | —                                                      | —                          | Llanos    | Exploration: 2015Exploitation: 2039                  
|Llanos 32      | 100.3                                                | 10%                         | APCO; Parex | Parex    | 0.1                                                    | 250                        | Llanos    | Exploration: 2015Exploitation: 2039                  
|Jagüeyes 3432A | 61.0                                                 | 5.0%                        | Columbus    | Columbus | —                                                      | —                          | Llanos    | Exploration: 2014Exploitation: 2038                  
|VIM-3          | 225.0                                                | 100%                        | —           | GeoPark  | —                                                      | —                          | Magdalena | Exploration: 2021
        
        Exploitation: 2045




| | (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working
interests held by other parties in such block. LGI currently has a 20% direct equity interest in our Colombian operations through
GeoPark Colombia SAS. However, we can earn back up to 12% additional equity interests in GeoPark Colombia depending on the success
of our Colombian operations. See “—Significant Agreements—Agreements with LGI—LGI Colombia Agreements.”
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Partners with working interests.
| | --- | --------------------------------



| | (3) | As of December 31, 2016.
| | --- | ------------------------



| | (4) | Although we are the sole title holder of the working interest in the Yamú Block, other parties have been granted economic
interests in fields in this block. Taking those other parties’ interests into account, we have a 89.5% interest in the Carupana
Field and a 100% interest in the Yamú and Potrillo Fields, both located in the Yamú Block.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The table summarizes information about
the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 2016.



|Block   | Gross
        acres
        (thousand acres) | Economic
        interest(1) | Operator | Production
        (boepd) | Basin    
|------- | -------------------------------------------- | ---------------------------- | -------- | -------------------------- | ---------
|Abanico | 32.1                                         | 10%                          | Pacific  | 55                         | Magdalena




| | (1) | Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant
to a joint operating agreement.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



Eastern Llanos Basin: (Llanos 34, La Cuerva,
Yamú, Llanos 32, Llanos 17, Jagüeyes 3432A, Abanico, and VIM-3 Blocks)



The Eastern Llanos Basin is a Cenozoic
Foreland basin in the eastern region of Colombia. Two giant fields (Caño Limón and Castilla), three major fields
(Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had been discovered. The source rock for the basin is located
beneath the east flank of the Eastern Cordillera, as a mixed marine-continental shaly basinal facies of the Gachetá formation.
The main reservoirs of the basin are represented by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous sequence,
several sandstones are also considered to have good reservoirs.



Llanos 34 Block. We are the operator
of, and have a 45% working interest in, the Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq. km). We acquired
an interest in and took operatorship of the block in the first quarter of 2012, which at the time had no production, reserves or
wells drilled on it, and with 210 sq. km of existing 3D seismic data on which our team had mapped multiple exploration prospects.
From 2012 to 2016 we engaged in exploration and development activities that resulted in multiple new oil fields discovered and
increased production and proved reserves year by year until 2016. Average net production in 2016 was 14,890 bopd and net reserves
of 37.1 mmbbl. The remaining commitment amounts to US$6.3 million at our working interest. As of the date of this Annual Report,
we are awaiting the ANH’s approval of US$3.6 million related to one well already drilled that was presented as fulfilment
of the commitment to be performed before September 2019.



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Our partner in the Llanos 34 Block is Parex,
which has a 55% interest. See “—Our operations.” We operate in the block pursuant to an E&P Contract with
the ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34 Block E&P Contract.”



La Cuerva Block. We are the operator
of, and have a 100% working interest in, the La Cuerva Block, which covers approximately 47,800 gross acres (190 sq. km). Since
we acquired an interest in the La Cuerva Block, we have drilled a total of 15 wells in the block, 10 of which were productive at
year-end 2016. Due to the impact of low oil prices, the block was temporarily shut in 2015 and 2016. Average net oil production
in 2016 was 388 bopd. We operate in the block pursuant to an E&P Contract with the ANH.



Yamú Block. We are the operator
of, and have a 100% working interest in, the Yamú Block, which covers approximately 11,200 gross acres (45.5 sq. km). Economic
rights to certain fields in the Yamú Block have been granted to other parties. In May 2013, we successfully drilled and
completed the Potrillo 1 well. For the year ended December 31, 2016, our average net production at the Yamú Block was 7
bopd, resulting from the temporary shutdown of our operations in this block.



Llanos 17 Block. We have a 40% working
interest in the Llanos 17 Block, which covers approximately 108,800 gross acres (440 sq. km). Parex is the operator of, and has
a 60% working interest in, the Llanos 17 Block. Since we acquired a working interest in the block, two wells have been drilled,
one of which was productive. We maintain our 40% working interest in the Llanos 17 Block pursuant to an E&P Contract with the
ANH. There are no pending commitments in this block. Consequently, the contract is now entering liquidation.



Llanos 32 Block. We have a 10% working
interest in the Llanos 32 Block, which covers approximately 100,300 gross acres (406 sq. km) Parex is the operator of, and has
a 70% working interest in this block. Pluspetrol has a 20% working interest. Since 2015, the operator focused on the commissioning
of a gas facility on this block to produce natural gas and light crude oil from the Une formation and to facilitate shipment of
processed gas south to the adjacent Llanos 34 Block. For the year ended December 31, 2016, our average net production in the Llanos
32 Block was 250 bopd. The remaining commitment related to this block is to drill one exploratory well before August 2018 amounting
to US$0.6 million at our working interest.



Jagüeyes 3432A Block. We have
a 5% working interest in the Jagüeyes 3432A Block, which covers approximately 61,000 acres (247 sq. km). Our partner in the
block is Columbus Energy, who maintains a 95% working interest in and is the operator of the Jagüeyes 3432A Block.



Abanico Block. In October 1996,
Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific is the operator of, and
has a 100% working interest in, the Abanico Block, which covers an area of approximately 32.1 gross acres. We do not maintain a
direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant
to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Pacific, who subsequently assigned
its participation interest to Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral
Finance Corporation and Getionar S.A.



VIM-3 Block.On July 23, 2014 we
were awarded a new exploratory license during the 2014 Colombia Bidding Round, carried out by the ANH. We will operate and have
a 100% working interest in the block. The VIM-3 Block is located in the Lower Magdalena Basin, covering an area of approximately
225,000 acres. Our winning bid consisted of committing to a Royalty X Factor of 3% and a minimum investment program of carrying
out 200 sq. km of 2D seismic data and drilling one exploratory well, with a total estimated investment of US$22.3 million during
the initial three-year exploratory period ending September 2018.



Operations in Chile



Our Chilean assets currently give us access
to 936,000 of gross exploratory and productive acres across 6 blocks in a large fully-operated land base across the Magallanes
Basin, with existing reserves, production and cash flows.



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Our Chilean blocks are located in the provinces
of Ultima Esperanza, Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and gas-producing area. As of December
31, 2016, the Magallanes Basin accounted for all of Chile’s oil and gas production. Although this basin has been in production
for over 60 years, we believe that it remains relatively underdeveloped.



Substantial technical data (seismic, geological,
drilling and production information), developed by us and by ENAP, provides an informed base for new hydrocarbon exploration and
development. Shut-in and abandoned fields may also have the potential to be put back in production by constructing new pipelines
and plants. Our geophysical analyses suggest additional development potential in known fields and exploration potential in undrilled
prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera and Estratos con Favrella formations.
The Springhill formation has historically been the source of production in the Fell Block, though the Estratos con Favrella shale
formation is the principal source rock of the Magallanes Basin, and we believe it contains unconventional resource potential.



Highlights of the year ended December 31,
2016 related to our operations in Chile included:



| | · | Average net oil and gas production remained flat at 3,874 boepd in 2016 as compared to 3,816 boepd in 2015;
| | - | -----------------------------------------------------------------------------------------------------------



| | · | Proved oil and gas reserves increased by 4% to 12.6 mmboe at year-end 2016, from 12.1 mmboe at year-end 2015 after producing
1.4 mmboe;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------



| | · | Capital expenditures were reduced by 37% to US$7.8 million in 2016 from US$12.4 million in 2015; and
| | - | ----------------------------------------------------------------------------------------------------



| | · | Successful cost reduction efforts impacting Production and operating costs that represented a 23% reduction, to US$22.2 million
in 2016 as compared to US$28.7 million in 2015.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



46


Table of Contents




The map below shows the location of the
blocks in Chile in which we have working interests.







47


Table of Contents


The table below summarizes information
about the blocks in Chile in which we have working interests as of and for the year ended December 31, 2016.



|Block      | Gross
        acres
        (thousand acres) | Working
        interest (1) | Partners
        (2) | Operator | Net
        proved
        reserves
        (mmboe)(3) | Production
        (boepd) | Basin      | Concession
        expiration year                   
|---------- | -------------------------------------------- | ---------------------------- | -------------------- | -------- | ------------------------------------------------------ | -------------------------- | ---------- | -----------------------------------------------------
|Fell       | 367.8                                        | 100%                         | —                    | GeoPark  | 12.4                                                   | 3,816                      | Magallanes | Exploitation: 2032                                   
|Tranquilo  | 92.4                                         | 50%                          | Pluspetrol           | GeoPark  | —                                                      | —                          | Magallanes | Exploitation: 2043                                   
|Otway      | 49.4(4)                                      | 100%                         | —                    | GeoPark  | —                                                      | —                          | Magallanes | Exploitation: 2044                                   
|Isla Norte | 130.2                                        | 60%(5)                       | ENAP                 | GeoPark  | —                                                      | —                          | Magallanes | Exploration: 2019
        
        Exploitation: 2044
|Campanario | 192.2                                        | 50%(5)                       | ENAP                 | GeoPark  | —                                                      | —                          | Magallanes | Exploration: 2020
        
        Exploitation: 2045
|Flamenco   | 105.9                                        | 50%(5)                       | ENAP                 | GeoPark  | 0.2                                                    | 58                         | Magallanes | Exploration: 2019
        
        Exploitation: 2044




| | (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working
interests held by other parties in such block. LGI has a 20% direct equity interest in our Chilean operations through GeoPark Chile.
See “—Significant Agreements—Agreements with LGI—LGI Chile Shareholders’ Agreements.”
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Partners with working interests.
| | --- | --------------------------------



| | (3) | As of December 31, 2016.
| | --- | ------------------------



| | (4) | In April 2013, we voluntarily relinquished to the Chilean government all of our acreage in the Otway Block, except for 49,421
acres. In May 2013, our partners under the joint operating agreement governing the Otway Block decided to withdraw from such joint
operating agreement, and applied for an assignment of rights permit on August 5, 2013. In September 2014, the Chilean Ministry
of Energy approved that we will be the sole participant with a working interest of 100%. See “—Otway and Tranquilo
Blocks.”
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (5) | LGI has a 14% direct equity interest in our Tierra del Fuego operations through GeoPark TdF and a 20% direct equity interest
in GeoPark Chile, for a total effective equity interest of 31.2% in our Tierra del Fuego operations. See “—Tierra del
Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)” and “—Significant Agreements—Agreements with
LGI—LGI Chile Shareholders’ Agreements.”
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Fell Block



In 2006, we became the operator and 100%
interest owner of the Fell Block. When we first acquired an interest in the Fell Block in 2002, it had no material oil and gas
production. Since then, we have completed more than 1,100 sq. km of 3D seismic surveys and drilled 114 exploration and development
wells. In the year ended December 31, 2016, we produced an average of approximately 3,816 boepd, in the Fell Block, consisting
of 36% oil.



The Fell Block has an area of approximately
368,000 gross acres (1,488 sq. km) and its center is located approximately 140 km northeast of the city of Punta Arenas. It is
bordered on the north by the international border between Argentina and Chile and on the south by the Magellan Strait.



The first exploration efforts began on
the Fell Block in the 1950s. Through 2005, ENAP carried out seismic surveys and drilled numerous wells in the block. From 2006
through August 2011, we successfully explored and developed the Fell Block, which allowed us to transition approximately 84% of
the Fell Block’s area from an exploration phase into an exploitation phase, which we expect will last through 2032. During
the exploration phase, we exceeded the minimum work and investment commitment required under the Fell Block CEOP by more than 75
times. There are no minimum work and investment commitments under the Fell Block CEOP associated with the exploitation phase.



The Fell Block is located in the north-eastern
part of the Magallanes Basin. The principal producing reservoir is composed of sandstones in the Springhill formation, at depths
of 2,200 to 3,500 meters. Additional reservoirs have been discovered and put into production in the Fell Block—namely, Tobífera
formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous sandstones, at depths
of 700 to 2,000 meters.



Our geosciences team identified and developed
an attractive inventory of prospects and drilling opportunities for both exploration and development in the Fell Block. Previous
oil discoveries in the Konawentru, Yagán, Yagán Norte, Copihue and Guanaco fields have opened up new oil and gas
potential in the Fell Block. An important discovery during 2011 was the Konawentru 1 well, which we initially tested to have in
excess of 2,000 bopd from the Tobífera formation, and which has opened up additional potentially attractive opportunities
(workovers, well-deepening’s and new exploration and development wells) in the Tobífera formation throughout the Fell
Block.



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From 2012 to 2014, we focused our exploration
and development plan in the Tobífera formation by drilling wells in Konawentru, Yagán and Yagán Norte fields,
as well as deepening existing wells in Ovejero and Molino. Exploration efforts in 2014 resulted in the discoveries of the Ache
gas field and the Loij oil field.



During 2015, although there were no wells
drilled, we put into production a new gas field, Ache, that was discovered in 2014. During 2016, we successfully drilled the Pampa
Larga 16 well and continued focusing on maintaining production levels and reducing production and operating costs.



The Fell Block also contains the Estratos
con Favrella shale reservoir, which we believe represents a high-potential, unconventional resource play for shale oil, as a broad
area within Fell Block (1,000 sq. km) which appears to be in the oil window for this play.



Tierra del Fuego Blocks (Isla Norte, Campanario
and Flamenco Blocks)



In the first and second quarters of 2012,
we entered into three CEOPs with ENAP and Chile granting us working interests in the Isla Norte, Campanario and Flamenco Blocks,
located in the center-north of the Tierra del Fuego province of Chile. We are the operator of all three of these blocks, with
working interests of 60%, 50% and 50%, respectively. We believe that these three blocks, which collectively cover 463,700 gross
acres (1,877 sq. km) and are geologically contiguous to the Fell Block, represent strategic acreage with resource potential. We
have committed to paying 100% of the required minimum investment under the CEOPs covering these blocks, in an aggregate amount
of US$101.4 million through the end of the first exploratory periods for these blocks, which occurred in November 2015 for the
Flamenco Block and is expected to occur by May 2017 for the Isla Norte Block and by July 2017 for the Campanario Block, which
includes our covering of ENAP’s investment commitment corresponding to its working interest in the blocks.



Isla Norte Block. We are the operator
of, and have a 60% working interest in partnership with ENAP in the Isla Norte Block, which covers approximately 130,200 gross
acres (527 sq. km). As of March 2017, we had completed 100% of the committed 350 sq. km of 3D seismic surveys and drilled one exploratory
well, which represents the first oil discovery within the block. As of the date of this Annual Report, outstanding investment commitments
of approximately US$6.6 million related to this block correspond to two exploratory wells until May 7, 2019.



Campanario Block. We are the operator
of, and have a 50% working interest in, the Campanario Block, in partnership with ENAP. The block covers approximately 192,200
gross acres (778 sq. km). As of March 31, 2017, we had completed 100% of the committed 578 sq. km of 3D seismic surveys and have
also drilled five exploratory wells, including the Primavera Sur 1 well that marks the first discovery of an oil field on the Campanario
Block in addition to one development well. As of the date of this annual report, outstanding investment commitments of approximately
US$11.9 million related to this block correspond to three exploratory wells until July 10, 2019.



49


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Flamenco Block. We are the operator
of, and have a 50% working interest in, the Flamenco Block, in partnership with ENAP. The block covers approximately 141,300 gross
acres (582 sq. km). In June 2013, we discovered a new oil and gas field in the block following the successful testing of the Chercán
1 well, the first well drilled by us in Tierra del Fuego. As of March 31, 2017, we had completed 100% of the committed 570 sq.
km of 3D seismic surveys. We have also committed to drilling ten wells during the first exploration period under the CEOP governing
the Flamenco Block. In the year ended December 31, 2016, we produced an average of approximately 58 boepd in the Flamenco Block.



The first exploration period of the Flamenco
Block ended in November 2015, and we and ENAP notified the Ministry of Energy of our decision to continue with the second exploration
period, which will last for 2 years. As of the date of this annual report, outstanding investment commitments related to this block
correspond to 1 exploratory well until November 7, 2017 for approximately US$2.1 million, to be assumed 100% by us. On January
6, 2017, we proposed to extend the second exploratory period for an additional period of 18 months. As of the date of this Annual
Report, the Chilean Ministry has not replied.



Otway and Tranquilo Blocks



We are the operator of the Otway and Tranquilo
Blocks.



In the Otway Block, we have a 100%
working interest. On April 10, 2013, we voluntarily and formally announced to the Chilean Ministry of Energy our decision not
to proceed with the second exploratory period and to terminate the exploratory phase under the Otway Block CEOP, such that we
relinquished all areas of the Otway Block, except for two areas totaling 49,421 gross acres in which we declared the
discovery of hydrocarbons, in the Cabo Negro and Tatiana prospect areas.



In the Tranquilo Block, as of December
31, 2016, we had a 50% working interest alongside our partner Pluspetrol. In 2014, Methanex and Wintershall announced their decision
to exit the Consortium, which was approved by the Ministry of Energy and formalized in 2016.



In the Tranquilo Block we completed a seismic
program consisting of 163 sq. km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four wells, including the
Palos Quemados and Marcou Sur well. The Marcou Sur well is under evaluation and we discovered gas in the El Salto formation of
the Palos Quemado well. At the Palos Quemados well, we completed a 22-week commercial feasibility test aimed at defining its productive
potential. As the test was not conclusive, we were granted permission by the Chilean Ministry of Energy to extend the testing period
for an additional six months. Upon such testing period, we kept 4 provisional protection areas, which enabled continued analysis
of the area prior the declaration of its commercial viability for a period of 5 years. On January 17, 2013, we formally announced
to the Chilean Ministry of Energy our decision not to proceed with the second exploratory period and to terminate the exploratory
phase of the Tranquilo Block CEOP. Subsequently, we relinquished all areas of the Tranquilo Block, except for a remaining area
of 92,417 gross acres, for the exploitation of the Renoval, Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which
we have identified as the areas with the most potential for prospects in the block.



As of December 31, 2016, we had completed
our minimum work commitments for the Otway and Tranquilo Blocks, with a total investment of approximately US$24 million for the
first exploratory period. The Otway Block’s seismic commitment program was completed in 2011 and included 270 sq. km of 3D
seismic and 127 km of 2D seismic survey work.



Operations in Brazil



Our Brazilian assets currently give us
access to 242,000 of gross exploratory and productive acres across 9 blocks (8 exploratory blocks and the BCAM-40 Concession, which
is in production phase) in an attractive oil and gas geography.



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Highlights of the year ended December 31,
2016 related to our operations in Brazil included:



| | · | Average net oil and gas production of 2,930 boepd (99% gas) in the year ended December 31, 2016, as compared to 3,342 boepd,
mainly impacted by lower industrial demand affecting production in the Manati Field;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Capital expenditures were reduced by 37%, to US$3.6 million in 2016, from US$5.6 in 2015; and
| | - | ---------------------------------------------------------------------------------------------



| | · | Seismic interpretation and other preliminary studies in our onshore exploratory blocks, in preparation to drill our first operated
well during 2017.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------



The map below shows the location of our
concessions in Brazil in which we have a current or future working interest, including the BCAM-40 Concession and the concessions
from bidding rounds 11, 12 and 13.










| | (1) | The PN-T-597 Block is subject to an injunction and our bid for the concession has been suspended. See “Item 3. Key
Information—D. Risk factors—Risks relating to our business—The PN-T-597 Concession Agreement in Brazil may not
close.”
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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The following table sets forth information
as of December 31, 2016 on our concessions in Brazil in which we have a current or future working interest, including the BCAM-40
Concession and the concessions from bidding rounds 11, 12 and 13.



|Concession  | Gross
        acres
        (thousand
        acres) | Working
        interest(1) | Partners                 | Operator  | Net
        proved
        reserves
        (mmboe) | Production
        (boepd) | Basin           | Concession
        expiration year 
|----------- | ---------------------------------------------------- | --------------------------- | ------------------------ | --------- | --------------------------------------------------- | -------------------------- | --------------- | -----------------------------------
|REC-T 94    | 7.7                                                  | 100%                        | —                        | GeoPark   | —                                                   | —                          | Recôncavo       | Exploration: 2018Exploitation: 2045
|POT-T 619   | 7.9                                                  | 100%                        | —                        | GeoPark   | —                                                   | —                          | Potiguar        | Exploration: 2018Exploitation: 2045
|PN-T-597(4) | 188.7                                                | 100%                        | —                        | GeoPark   | —                                                   | —                          | Parnaíba        | —                                  
|SEAL-T-268  | 7.8                                                  | 100%                        | —                        | GeoPark   | —                                                   | —                          | Sergipe Alagoas | Exploration: 2019Exploitation: 2046
|REC-T-93    | 7.8                                                  | 100%(5)                     | —                        | GeoPark   | —                                                   | —                          | Recôncavo       | Exploration: 2020Exploitation: 2047
|REC-T-128   | 7.6                                                  | 70%                         | Geosol                   | GeoPark   | —                                                   | —                          | Recôncavo       | Exploration: 2020Exploitation: 2047
|POT-T-747   | 6.9                                                  | 100%(5)                     | —                        | GeoPark   | —                                                   | —                          | Potiguar        | Exploration: 2020Exploitation: 2047
|POT-T-882   | 7.9                                                  | 100%(5)                     | —                        | GeoPark   | —                                                   | —                          | Potiguar        | Exploration: 2020Exploitation: 2047
|BCAM-40     | 22.8                                                 | 10%                         | Petrobras; QGEP; Brasoil | Petrobras | 5.0                                                 | 2,930                      | Camamu-Almada   | Exploitation:2029(2) - 2034(3)     




| | (1) | Working interest corresponds to the working interests held by our respective subsidiaries, net of any working interests held
by other parties in such concession. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—The
PN-T-597 Concession Agreement in Brazil may not close.”
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Corresponds to Manati Field.
| | --- | ----------------------------



| | (3) | Corresponds to Camarão Norte Field.
| | --- | -----------------------------------



| | (4) | PN-T-597 Block subject to the entry into the concession agreement by the ANP and absence of any legal impediments to signing.
As of the date of this annual report, confirmation remains subject to final signing and local authority approval. See “Item
3. Key Information—D. Risk factors—Risks relating to our business—The PN-T-597 Concession Agreement in Brazil
may not close.”
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (5) | A 30% working interest of proposed partners is subject
to ANP approval.
| | --- | -----------------------------------------------------------------------



BCAM-40 Concession



As a result of the Rio das Contas acquisition,
we have a 10% working interest in the BCAM-40 Concession, which includes interests in the Manati Field and the Camarão Norte
Field, and which is located in the Camamu-Almada Basin. Petrobras is the operator, and has a 35% working interest in, the BCAM-40
Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In addition to us, Petrobras’ partners in the block
are Brasoil and QGEP, with 10% and 45% working interests, respectively. Petrobras operates the BCAM-40 Concession pursuant to a
concession agreement with the ANP, executed on August 6, 1998. See “—Significant Agreements—Brazil—Overview
of concession agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras announced the relinquishment of
BCAM-40’s exploration area within the concession to the ANP, except for the Manati Field and the Camarão Norte Field.



The Manati Field is located 65 km south
of Salvador, offshore at a 35 meter water depth. The field was discovered in October 2000, and, in 2002, Petrobras declared the
field commercially viable. Production began in January 2007. As of December 31, 2016, 11 wells had been drilled in the Manati Field,
six of which are productive and connected to a fixed production platform installed at a depth of 35 meters, located 9 km from the
coast of the State of Bahia. From the platform, the gas flows by sea and land through a 125 km pipeline to the Estação
Vandemir Ferreira or EVF gas treatment plant. The gas is sold to Petrobras up to a maximum volume as determined in the existing
Petrobras Gas Sales Agreement (as defined below). In July 2015, we signed an amendment to the existing Gas Sales Agreement with
Petrobras that covers 100% of the remaining gas reserves of the Manati Field.



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Also in 2015, in order to improve the field
gas recovery and production, Manatì’s consortium built an onshore compression plant that started operating in August
2015. The compression plant involved capital expenditures of approximately US$3.7 million at our working interest and allowed us
to classify all existing proved undeveloped reserves as proved developed as of December 31, 2016.



The acquisition of Rio das Contas provides
us with a long-term off-take contract with Petrobras that covers 100% of net proved gas reserves in the Manati Field, a valuable
relationship with Petrobras and an established local platform and presence, with a seasoned and experienced geoscience and administrative
team to manage the assets and to seek new growth opportunities.



Some environmental licenses related to
operation of the Manati Field production system and natural gas pipeline are expired. However, the operator submitted, in a timely
manner, the request for renewal of those licenses and as such this operation is not in default as long as the regulator does not
state its final position on the renewal. The Camarão Norte Field is in the development phase and is not yet subject to the
environmental licensing requirement.



Round 11 Concessions



During ANP’s 11th bidding
round, held in May 14th, 2013, we were awarded 7 exploratory blocks, of which 2 were in the Reconcavo Basin in the state of Bahia
and 5 were in the Potiguar Basin in the state of Rio Grande do Norte. The exploratory phase for these concessions is divided into
two exploratory periods, the first of which lasts for three years and the second of which is non-obligatory and can last for up
to two years.



In 2016, after fulfilling the committed
exploratory commitments and further reevaluation of commercial potential, five exploratory blocks were relinquished to the ANP
(REC T 85, POT T 620, POT T 663, POT T 664 and POT T 665).



REC-T 94 Concession



In the REC-T 94 we committed R$17.6 million
(approximately US$5.35 million, at the December 31, 2016 exchange rate of R$3.3 to US$1.00) during the first exploratory period
consisting of drilling two exploratory wells and 31 sq. km of 3D seismic surveys.



During the year 2014 we executed a 3D seismic
survey. Seismic data interpretation in 2015 and 2016 defined two well locations which we plan to drill in 2017.



POT-T 619 Concession



In the POT-T 619 Concession we committed
investments of R$2.3 million (approximately US$0.7 million at the December 31, 2016 exchange rate of R$3.3 to US$1.00) during the
first exploratory period, equivalent to 46 km of 2D seismic work.



During the year 2014 we executed a 2D seismic
survey. Seismic data processing was concluded in 2015. After seismic interpretation, we decided to continue to the second exploratory
period, which lasts for two years with a commitment to drill one exploratory well.



Round 12 Concessions



On November 28, 2013, in the 12th
oil and gas bidding round, the ANP awarded us two new concessions (the PN-T-597 Concession in the Parnaíba Basin in the
State of Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in the State of Alagoas.



For more information, see “Item 3.
Key information—D. Risk factors—Risks relating to our business—The PN-T-597 Concession Agreement in Brazil may
not close.”



PN-T-597 Concession



The Parnaiba Basin, which covers an area
of approximately 148 million gross acres (600,000 sq. km), is a basin with large underexplored areas. As of December 31, 2016,
the basin had two fields in production in the basin.



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In the PN-T-597 Concession we committed
R$7.7 million (approximately US$2.3 million, at the December 31, 2016 exchange rate of R$3.3 to US$1.00) for the first exploratory
period, equivalent to 180 km of 2D seismic.



The exploratory phase for this concession
is divided into two exploratory periods. Given that Parnaiba Basin is considered as a “new frontier” area by the ANP,
the first exploratory period lasts four years, and the second exploratory period, which is optional, can last for up to two years.



See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—The PN-T-597 may not close” and “—D. Risk factors—Risks
relating to the countries in which we operate—Our operations may be adversely affected by political and economic circumstances
in the countries in which we operate and in which we may operate in the future” for more information.



SEAL-T-268 Concession



In the SEAL-T-268 Concession we committed
R$1.6 million (approximately US$0.5 million, at the December 31, 2016 exchange rate of R$3.3 to US$1.00) for the first exploratory
period. The exploratory phase for this concession is divided into two exploratory periods, the first lasting three years, and the
second, which is optional, can last for up to two years. During 2016, an electromagnetic survey acquisition of 70 stations and
reprocessing of 58 km of vintage 2D seismic was performed and, after ANP approval, will fulfill part of the committed work program.
Interpretation of the new data is currently ongoing.



Round 13 Concessions



During ANP’s 13th round of bidding
held on October 7, 2015, we were awarded four exploratory concessions, of which two were in the Potiguar Basin in the state of
Rio Grande do Norte and two were in the Reconcavo Basin in the state of Bahia. The exploratory phase for these concessions is divided
into two exploratory periods, the first of which lasts for three years and the second of which is non-obligatory and can last for
up to two years.



POT-T-747 and POT-T-882



The POT-T-747 and POT-T-882 blocks are
located in the Potiguar Basin and encompass an area of 14,829 acres (60 square km). Total commitment to the ANP was of R$8.5 million
(approximately US$2.6 million, at the December 31, 2016 exchange rate of R$3.3 to US$1.00) during the first exploratory period
and is equivalent to acquiring 70 km of 2D seismic, and drilling one well.



REC-T-128 and REC-T-93



Both blocks are part of the Reconcavo
Basin and have a combined area of 15,405 acres (62.3 square km). The block REC-T-128 was bid for in partnership with Geosol with
a 70% working interest for us and 30% working interest for Geosol. The total commitment to the ANP was R$7.9 million (approximately
2.4 million at the December 31st, 2016 exchange rate of R$3.3 to US$1.00) during the first exploratory period and consists of
acquiring 9 km2 of 3D seismic, drilling one well and performing geochemical analysis
at two levels.



During 2016, regional interpretation studies
were performed in the area. Part of the minimum exploratory program of Block REC-T-93 has been fulfilled and approved by ANP with
the 3D regional seismic acquisition which also covered Block REC T 94 (Round 11).



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Table of Contents


Operations in Peru



In October 2014, we entered into an agreement
to expand our footprint into Peru (our fifth country platform in Latin America) through the acquisition of Morona Block in a joint
venture with Petroperu.



The Morona Block has DeGolyer and MacNaughton
certified net proved reserves of 18.6 mmboe as of December 31, 2016, composed of 100% oil.



The map below shows the location of the
Morona Block in Peru.







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Table of Contents


The table below summarizes information
about the block in Peru.



|Block  | Gross
        acres
        (thousand
        acres) | Working
        interest(1) | Operator | Net
        proved
        reserves
        (mmboe)(2) | Production
        (boepd) | Basin   | Expiration
        concession year
|------ | ---------------------------------------------------- | --------------------------- | -------- | ------------------------------------------------------ | -------------------------- | ------- | ----------------------------------
|Morona | 1,881                                                | 75%                         | GeoPark  | 18.6                                                   | —                          | Marañon | Exploitation: 2038 (3)            




| | (1) | Corresponds to the initial working interest. Petroperu will have the right to increase its working interest in the block by
up to 50%, subject to the recovery of our investments in the block through agreed terms in the Petroperu SPA. See “Item 4.
Information on the Company—B. Business Overview—Our operations—Operations in Peru—Morona Block.”
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Certified by DeGolyer and MacNaughton as of December 31, 2016.
| | --- | --------------------------------------------------------------



| | (3) | The concession year expiration is related to approval of an environmental impact assessment (EIA) study for project development.
The concession will expire twenty (20) years after EIA approval.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Morona Block



The Morona Block covers an area of approximately
1,881 thousand gross acres (7,600 sq. km). More than 1 billion barrels of oil have been produced from the surrounding blocks in
this basin.



On October 1, 2014,
we entered into an agreement to acquire a 75% working interest in the Morona Block in Northern Peru. As stated above, this agreement
includes a work program to be executed by us. This program includes 3 phases, and we may decide whether to continue or not at the
end of each phase. On December 1, 2016, through Supreme Decree N° 031-2016-MEN, the Peruvian government approved the amendment
to the License Contract of Morona Block appointing GeoPark as operator and holder of 75% of the License-Contract.



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. 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 area has undergone oil and gas exploration activities
for the past 40 years, and there exist ongoing association agreements and cooperation projects with the local communities.



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
two stages is to put the field into production through a long term test of the two wells already drilled in the field, in order
to determine the most effective overall development plan and to begin to generate cash flow. These initial stages require an investment
of approximately US$100 million to US$150 million and are expected to be completed within 24 to 36 months after closing. We have
committed to cover Petroperu, by paying its portion of the required investment in these initial phases. In addition, we are required
to cover any capital or operational expenditures of Petroperu associated with the project until December 31, 2020. We expect these
expenditures to be substantially reimbursed by Petroperu from revenues associated to future sales.



In accordance with
the agreement between us and Petroperu, commitments assumed by GeoPark are subject to certain economical and technical conditions
being met.



The third stage, which will be initiated
once production has been established, is expected to focus on carrying out the full development of the Situche Central field, including
transportation infrastructure and new exploration drilling of the block.



The exploratory program entails drilling
one exploratory well. Exploratory program capital expenditures will be borne exclusively by us. Expected capital expenditures in
2017 for the Morona Block are mainly related to facility maintenance and environmental and engineering studies.



Initially we will have a 75% working interest.
However, according to the terms of the agreement, Petroperu will have the right to increase its working interest in the block by
up to 50%, subject to the recovery of our investments in the block by certain agreed factors.



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See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—“Our inability to access needed equipment and infrastructure in a
timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our
oil and natural gas production” and “—We may suffer delays or incremental costs due to difficulties in negotiations
with landowners and local communities, including native communities, where our reserves are located.”



Operations in Argentina



The map below shows the location of the
blocks in Argentina in which we have working interests as of December 31, 2016.







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Table of Contents


The table below summarizes information
about the blocks in Argentina in which we have working interests as of December 31, 2016.



|Block                 | Gross
        acres
        (thousand
        acres) | Working
        interest (1) | Operator   | Net
        proved
        reserves
        (mmboe)(2) | Production
        (boepd) | Basin   | Expiration
        concession year
|--------------------- | ---------------------------------------------------- | ---------------------------- | ---------- | ------------------------------------------------------ | -------------------------- | ------- | ----------------------------------
|Puelen (3)            | 305.4                                                | 18%                          | Pluspetrol | —                                                      | —                          | Neuquén | Exploration: 2017                 
|Sierra del Nevado (3) | 1,433.2                                              | 18%                          | Pluspetrol | —                                                      | —                          | Neuquén | Exploration: 2017                 
|CN-V                  | 117.0                                                | 50%                          | GeoPark    | —                                                      | —                          | Neuquén | Exploration: 2017                 




| | (1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working
interests held by other parties in each block.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | As of December 31, 2016.
| | --- | ------------------------



| | (3) | Blocks awarded in the 2014 Mendoza Bidding Round.
| | --- | -------------------------------------------------



2014 Mendoza Bidding Round



On August 20, 2014, the consortium of Pluspetrol
and us 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 Energía S.A. (“EMESA”).



The consortium consists of Pluspetrol (operator
with a 72% working interest), EMESA (non-operator with a 10% working interest) and us (non-operator with an 18% working interest).
In accordance with the terms of the bidding, all of the expenditures related to EMESA’s working interest will be carried
by Pluspetrol and us proportionately to our respective working interests, and will be recovered through EMESA’s participation
in future potential production.



Puelen Block: the Puelen Block covers
an area of approximately 305.4 thousand gross acres, and is located in the Neuquén Basin in southern Argentina. During 2016,
200 square kilometers of 3D seismic was registered, amounting to US$1.6 million at our working interest.



Sierra del Nevado Block: the Sierra
del Nevado Block covers an area of approximately 1,433.2 thousand gross acres, and is located in the Neuquén Basin in southern
Argentina.



We have committed to a minimum aggregate
investment of US$6.2 million for this working interest, which includes the work program commitment on both blocks during the first
three years of the exploratory period.



CN-V Block Farm-in Agreement



On July 22, 2015, we signed a farm-in agreement
with Wintershall for the CN-V Block in Argentina, which complements our existing acreage in the basin. Wintershall is Germany's
largest oil and gas producer and a subsidiary of BASF Group. We will operate during the exploratory phase and receive a 50% working
interest in the CN-V Block in exchange for our commitment to drill one exploratory well before the end of the second quarter of
2017 and to drill another exploratory well before the end of the second exploration period, for a total of US$10 million.



The CN-V Block covers an area of approximately
117,000 acres and is located in the Neuquén Basin in southern Argentina. The block has 3D seismic coverage of 180 sq. km
and is adjacent to the producing Loma Alta Sur oil field, a region and play-type well known to our team. The block includes upside
potential in the developing Vaca Muerta unconventional play.



Del Mosquito Block



On April 2016 the concession of the Del
Mosquito expired and we relinquished the entire remaining acreage to provincial authorities. As of the date of this Annual Report,
the approval of the abandonment plan for remediation and restoration of the block is still pending.



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Oil and natural gas reserves and production



Overview



We have achieved consistent growth in oil
and gas reserves from our investment activities since 2007, when we began production in the Fell Block, followed by successful
acquisition, exploration and development activities in other countries in which we have a presence, including Colombia, Brazil
and Peru.



The following table summarizes DeGolyer
and MacNaughton reported net proved reserves in Colombia, Chile, Brazil and Peru as of December 31, 2016.



|Country  |  | Oil (mmbbl) |      | Gas (bcf) |  | Total net proved reserves (mmboe)(1) |      | % Oil
|-------- |  | ----------- | ---- | --------- |  | ------------------------------------ | ---- | -----
|Colombia |  |             | 37.3 |           |  |                                      | -    |      
|Chile    |  |             | 6.6  |           |  |                                      | 36.3 |      
|Brazil   |  |             | 0.1  |           |  |                                      | 29.6 |      
|Peru     |  |             | 18.6 |           |  |                                      | -    |      
|Total    |  |             | 62.6 |           |  |                                      | 65.9 |      




| | (1) | We calculate one barrel of oil equivalent as six mcf of natural gas.
| | --- | --------------------------------------------------------------------



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Our reserves



The following table sets forth our oil
and natural gas net proved reserves as of December 31, 2016, which is based on the D&M Reserves Report.



|                                                 |  | Net proved reserves    
|------------------------------------------------ |  | -----------------------
|                                                 |  | As of December 31, 2016
|                                                 |  | Oil (mmbbl)            
|Net proved developed                             |  |                        
|Colombia                                         |  |                        
|Chile                                            |  |                        
|Peru                                             |  |                        
|Brazil                                           |  |                        
|Total net proved developed                       |  |                        
|                                                 |  |                        
|Net proved undeveloped                           |  |                        
|Colombia                                         |  |                        
|Chile                                            |  |                        
|Peru                                             |  |                        
|Brazil                                           |  |                        
|Total net proved undeveloped                     |  |                        
|                                                 |  |                        
|Total net proved (Colombia, Chile, Peru, Brazil) |  |                        




| | (1) | We calculate one barrel of oil equivalent as six mcf of natural gas.
| | --- | --------------------------------------------------------------------



For further information relating to the
reconciliation of our net proved reserves for the years ended December 31, 2016, 2015 and 2014, please see Table 5 included
in Note 37 (unaudited) to our Consolidated Financial Statements.



Internal controls over reserves estimation
process



We maintain an internal staff of petroleum
engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy
and timeliness of data furnished to our independent reserves engineers in their estimation process and who have knowledge of the
specific properties under evaluation. Our Director of Development, Carlos Alberto Murut, is primarily responsible for overseeing
the preparation of our reserves estimates and for the internal control over our reserves estimation. He has more than 30 years
of industry experience as an E&P geologist, with broad experience in reserves assessment, field development, exploration portfolio
generation and management and acquisition and divestiture opportunities evaluation. See “Item 6. Directors, Senior
Management and Employees—A. Directors and senior management.”



In order to ensure the quality and consistency
of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following
key control objectives:



| | · | estimates are prepared using generally accepted practices and methodologies;
| | - | ----------------------------------------------------------------------------



| | · | estimates are prepared objectively and free of bias;
| | - | ----------------------------------------------------



| | · | estimates and changes therein are prepared on a timely basis;
| | - | -------------------------------------------------------------



| | · | estimates and changes therein are properly supported and approved; and
| | - | ----------------------------------------------------------------------



| | · | estimates and related disclosures are prepared in accordance with regulatory requirements.
| | - | ------------------------------------------------------------------------------------------



Throughout each fiscal year, our technical
team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information
pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally-generated
reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free
of preparer and management bias.



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Recognizing that reserves estimates are
based on interpretations and judgments, differences between the proved reserves estimates prepared by us and those prepared by
an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences.
Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified
Reserves Engineer sends a preliminary copy of the reserves report to be reviewed by the Technical Committee and Directors of each
Business Unit. A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be approved and signed
by the Technical Committee and our CEO and CFO. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees
of our board of directors.”



Independent reserves engineers



Reserves estimates as of December 31, 2016
for Colombia, Chile, Brazil and Peru included elsewhere in this annual report are based on the D&M Reserves Report, dated April
11, 2017 and effective as of December 31, 2016. The D&M Reserves Report, a copy of which has been filed as an exhibit to this
annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines at our request in order to estimate
reserves and for the areas and period indicated therein.



DeGolyer and MacNaughton, a Delaware corporation
with offices in Dallas, Houston, Calgary, Moscow and Algiers, has been providing consulting services to the oil and gas industry
for more than 75 years. The firm has more than 150 professionals, including engineers, geologists, geophysicists, petrophysicists
and economists that are engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects,
basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer
and MacNaughton restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating
interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional
conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered
Engineering Firm.



The D&M Reserves Report covered 100%
of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its
own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton did not independently
verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production,
well test data, historical costs of operation and development, product prices, or any agreements relating to current and future
operations of the fields and sales of production. However, if in the course of the examination something came to the attention
of DeGolyer and MacNaughton that brought into question the validity or sufficiency of any such information or data, DeGolyer and
MacNaughton did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had
independently verified such information or data. DeGolyer and MacNaughton independently prepared reserves estimates to conform
to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about
the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition
in Rule 4-10(a)(2) of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation. D&M’s
primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures
and other economic assumptions (including interests, royalties and taxes) as provided by us. The assumptions, data, methods and
procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the D&M Reserves
Report were appropriate for the purpose served by such report, and DeGolyer and MacNaughton used all methods and procedures as
it considered necessary under the circumstances to prepare such reports.



However, uncertainties are inherent in
estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves
engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an
exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation.
As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results
of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or
development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession
terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning
the oil and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves.
Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates.



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Technology used in reserves estimation



According to SEC guidelines, proved reserves
are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable
certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation.



The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The
term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually
recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective
by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology
that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods)
that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability
in the formation being evaluated or in an analogous formation.



There are various generally accepted methodologies
for estimating reserves including volumetrics, decline analysis, material balance, simulation models and analogies. Estimates may
be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence)
methods. The particular method chosen should be based on the evaluator’s professional judgment as being the most appropriate,
given the geological nature of the property, the extent of its operating history and the quality of available information. It may
be appropriate to employ several methods in reaching an estimate for the property.



Estimates must be prepared using all available
information (open and cased hole logs, core analyses, geologic maps, seismic interpretation, production/injection data and pressure
test analysis). Supporting data, such as working interest, royalties and operating costs, must be maintained and updated when such
information changes materially.



Proved undeveloped reserves



As of December 31, 2017, we had 48.1 mmboe
in proved undeveloped reserves, an increase of 15.6 mmboe, or 47%, over our December 31, 2016 proved undeveloped reserves of 33.0
mmboe. The increase in proved undeveloped oil reserves is mainly due to net additions in Colombia related to appraisal success
in Jacana Oil Field, and the incorporation of proved undeveloped reserves in Peru. This was partially offset by proved undeveloped
reserves being converted to proved reserves in Colombia for approximately 4.7 mmboe and Chile for approximately 0.6 mmboe, as stated
in the table below.



Of our 48.1 mmboe of net proved undeveloped
reserves, 27.8 mmboe (58%), 11.0 mmboe (23%), and 9.3 mmboe (19%) were located in Colombia, Chile and Peru, respectively.



During 2016, we incurred approximately
US$10.1 million in capital expenditures to convert such proved undeveloped reserves to proved developed reserves, of which approximately
US$7.3 million, and US$3.1 million were made in Colombia and Chile, respectively.



No net proved undeveloped reserves were
located in Argentina and Brazil as of December 31, 2016.



The following table shows the evolution
of total net proved undeveloped (“PUD”) reserves in the year ended December 31, 2016.



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|Total Net Proved Undeveloped (“PUD”) Reserves
        at December 31, 2015
        
        (All amounts shown in mmboe) | 33.0 
|------------------------------------------------------------------------------------------------------------------------ | -----
|                                                                                                                         |      
|Plus: Extensions, discoveries and acquisitions:                                                                          |      
|-Colombia                                                                                                                | 6.3  
|-Chile                                                                                                                   | –    
|-Brazil                                                                                                                  | –    
|-Peru(1)                                                                                                                 | 9.3  
|Less: PUD Reserves converted to proved developed reserves:                                                               |      
|-Colombia                                                                                                                | (4.7)
|-Chile                                                                                                                   | (0.6)
|-Brazil                                                                                                                  | –    
|Plus/less: PUD Reserves revisions and movement to/from other categories:                                                 |      
|-Colombia                                                                                                                | 4.0  
|-Chile                                                                                                                   | 0.8  
|-Brazil                                                                                                                  | –    
|Total Net Proved Undeveloped Reserves at December
31, 2016                                                               | 48.1 




| | (1) | On December 1, 2016, through Supreme Decree N° 031-2016-MEN, the Peruvian government approved the amendment to the License
Contract of Morona Block appointing GeoPark as operator and holder of 75% of the License-Contract. See “Item 4. Information
on the Company—B. Business Overview—Our operations—Operations in Peru.”
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Production, revenues and price history



The following
table sets forth certain information on our production of oil and natural gas in Colombia, Chile, Brazil for each of the years
ended December 31, 2016, 2015 and 2014.







|                                                 | Average
daily production(1) |       
|------------------------------------------------ | --------------------------- | ------
|                                                 | As
of December 31,          |       
|                                                 | 2016                        | 2015  
|                                                 | Colombia                    | Chile 
|Oil production                                   |                             |       
|Average crude oil production (bopd)              | 15,536                      | 1,380 
|Average sales price of crude oil (US$/bbl) (3)   | 24.4                        | 37.0  
|Natural gas                                      |                             |       
|Average natural gas production (mcfpd)           | -                           | 14,964
|Average sales price of natural gas (US$/mcf) (3) | -                           | 3.8   
|Oil and gas production cost                      |                             |       
|Average operating cost (US$/boe)                 | 5.4                         | 15.8  
|Average royalties and Other (US$/boe)            | 1.4                         | 1.1   
|Average production cost (US$/boe)(2)             | 6.7                         | 16.9  
|                                                 |                             |       






| | (1) | We present production figures net
                                         of interests due to others, but before deduction of royalties, as we believe that net
                                         production before royalties is more appropriate in light of our foreign operations and
                                         the attendant royalty regimes.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Calculated pursuant to FASB ASC
                                         932.
| | --- | -----------------------------------------------------------------------------



| | (3) | Averaged realized sales price for
                                         oil does not include our Argentine blocks because our Argentine operations were not material
                                         during such periods. Averaged realized sales price for gas does not include our Argentine
                                         and Colombian blocks because our gas operations in those countries were not material
                                         during such period.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Drilling activities



The following table sets forth the exploratory
wells we drilled as operators during the years ended December 31, 2016, 2015 and 2014.



|              | Exploratory
        wells(1)
|------------- | ----------------------------
|              | As
        of December 31,  
|              | 2016                        
|              | Colombia                    
|Productive(2) |                             
|Gross         | 3.0                         
|Net           | 1.4                         
|Dry(3)        |                             
|Gross         | -                           
|Net           | -                           
|Total         |                             
|Gross         | 3.0                         
|Net           | 1.4                         




| | (1) | Includes appraisal wells.
| | --- | -------------------------



| | (2) | A productive well is an exploratory, development, or extension well that is not a dry well.
| | --- | -------------------------------------------------------------------------------------------



| | (3) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The following table sets forth the development
wells we drilled as operators during the years ended December 31, 2016, 2015 and 2014.



|              | Development
        wells(1)
|------------- | ----------------------------
|              | As
        of December 31,  
|              | 2016                        
|              | Colombia                    
|Productive(2) |                             
|Gross         | 3.0                         
|Net           | 1.4                         
|Dry(3)        |                             
|Gross         | -                           
|Net           | -                           
|Total         |                             
|Gross         | 3.0                         
|Net           | 1.4                         
|              |                             




| | (1) | A productive well is an exploratory, development, or extension well that is not a dry well.
| | --- | -------------------------------------------------------------------------------------------



| | (2) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Developed and undeveloped acreage



The following table sets forth certain
information regarding our total gross and net developed and undeveloped acreage in Colombia, Chile, Brazil and Peru as of December
31, 2016.









|                                        | Acreage(1)             
|--------------------------------------- | -----------------------
|                                        | Colombia               
|                                        | (in thousands of acres)
|Gross                                   | 7.3                    
|Net                                     | 4.6                    
|Total undeveloped acreage               |                        
|Gross                                   | 8.0                    
|Net                                     | 3.9                    
|Total developed and undeveloped acreage |                        
|Gross                                   | 15.3                   
|Net                                     | 8.5                    
|                                        |                        








| | (1) | Defined as acreage assignable to productive wells. Net acreage based on our working interest.
| | --- | ---------------------------------------------------------------------------------------------



Productive wells



The following table sets forth our total
gross and net productive wells as of March 31, 2017. Productive wells consist of producing wells and wells capable of producing,
including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production
facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our
fractional working interests owned in gross wells.



|          | Productive
        wells(1)
|--------- | ---------------------------
|          | Colombia
        (2)       
|Oil wells |                            
|Gross     | 63.0                       
|Net       | 36.0                       
|Gas wells |                            
|Gross     | -                          
|Net       | -                          




| | (1) | Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are
not the operator. A productive well is an exploratory, development, or extension well that is not a dry well.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | We acquired Winchester and Luna in February 2012 and Cuerva in March 2012. Figures include wells drilled by Winchester, Luna
and Cuerva prior to their acquisition by us.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Present activities



Our average oil and gas production in
the first quarter of 2017 totaled 25.2 mboepd, with oil production of 20.5 mbopd and gas production of 4.7 mboepd, of which
total production 77%, 13% and 10% were in Colombia, Chile and Brazil, respectively.



During the first quarter of 2017 we drilled
and put into production three wells in Colombia in the Llanos 34 Block, as follows:



| | · | Chiricoca 1 exploration well was drilled to a total depth of 11,966 feet. A production test resulted in a production rate of
approximately 1,000 bopd.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Tigana Sur 6 development well was drilled to a total depth of 11,645 feet. A production test resulted in a production rate
of approximately 1,600 bopd.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Jacana 11 appraisal well was drilled to a total depth of 11,618 feet. A production test resulted in a production rate of approximately
2,100 bopd.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------



Also, during the first quarter
of 2017 we started drilling an exploratory well in Brazil in the Reconcavo Basin, which as of the date of this Annual Report,
we decided to plug and abandon following an in-depth geological and geophysical analysis. Drilling costs for this exploratory
well amounted to $2.3 million.



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Additional production history is required
to determine stabilized flow rates of the above mentioned wells.



As of December 31, 2016, there were two
exploratory wells that have been capitalized for a period of less than one year amounting to US$8.2 million. See Note 19 to our
Consolidated Financial Statements.



Marketing and delivery commitments



Colombia



Our production in Colombia consists primarily
of crude oil. Sales for the year ended December 31, 2016 were made under a combination of short-term agreements and long term sales
agreements as described below.



Evacuation of the oil produced is structured
under two types of sales: wellhead and pipeline. For wellhead sales, delivery point is at the loading station at fields. For pipeline
sales, delivery point is at the uploading station that discharges to the national pipeline network. In Colombia, pipelines have
minimum quality conditions that restrict access to the system. Consequently, and because we are mid to heavy oil producers, our
entrance to the pipeline requires the use of diluents which are blended into our crude. For the year ended December 31, 2016, we
sold approximately 89% of our production directly at the wellhead and approximately 11% to the major oil companies that own capacity
in the pipelines. Since 2014, access to the pipeline network has improved due to the commencement of the Bicentenario pipeline,
which added transportation capacity and opened up additional supply opportunities involving reduced trucking costs.



Oil sales are structured under a price
formula based on a market reference Index (Brent or Vasconia) and discounts that consider market fees, quality, handling fees and
transportation among other associated costs.



For the year ended December 31, 2016, we
made 90% of our oil sales to Trafigura, accounting for 59% of our consolidated revenues for the same period.



Under the Trafigura Agreement, we followed
agreed priorities for the volumes to be transported through the ODL Pipeline. For the period from March 1, 2016 to September 1,
2016, Trafigura received 10,000 bopd of our production. In 2016 and 2017, the Trafigura Agreement was amended setting the current
volumes to be delivered to Trafigura to 12,000 bopd until December 2018.



Nonperformance of our obligations of delivery
in terms, amounts and quality of the crude to Trafigura may require us to pay Trafigura’s fare commitments in ODL Pipeline
for the transport, dilution and download of crude, and may lead to early termination of the crude sales agreement as well as the
immediate repayment of any amounts outstanding under the prepayment agreement, as well as compensation for other damages.



If we were to lose our key customers, the
loss could temporarily delay production and sale of our oil in the corresponding block. However, given the wide availability of
customers for Colombian crude, we believe we could identify a substitute customer to purchase the impacted production volumes.



Chile



Our customer base in Chile is limited in
number and primarily consists of ENAP and Methanex. For the year ended December 31, 2016 we sold 100% of our oil production in
Chile to ENAP and 95% of our gas production to Methanex, with sales to ENAP and Methanex accounting for 10% and 9%, respectively,
of our total revenues in the same period.



Under our oil sales agreement
with ENAP, or the ENAP Oil Sales Agreement, ENAP has committed to purchase our oil production in the Fell Block, in the
amounts that we produce, and with the limitation being storage capacity at the Gregorio Terminal. The sales contract with
ENAP is commonly revised every year to reflect changes in the global oil market and to adjust to logistics costs of ENAP in
the Gregorio oil terminal. As of the date of this annual report, we are negotiating a new agreement,  that we expect
will take effect in April 2017, which allows for sales to ENAP to be periodically interrupted if conditions in the export
markets allow for more competitive price levels.



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Commercial conditions of the new agreement
are similar to the previous one in effect. We deliver the oil we produce in the Fell Block to ENAP at the Gregorio Terminal, where
ENAP assumes responsibility for the oil transferred. ENAP owns two refineries in Chile in the north central part of the country
and must ship any oil from the Gregorio Terminal to these refineries unless it is consumed locally.



We signed the Methanex Gas Supply Agreement
in Chile in 2009, which expires in April 30, 2017.



In March 2017, we executed a new gas supply
agreement with Methanex effective from May 1, 2017 to December 31, 2026. Under the agreement, Methanex commits to purchase up to
400,000 SCM/d of gas produced by us. We also hold an option to deliver up to 15% above this volume.



On April 1, 2016, we executed a seventh
amendment to the Gas Supply Agreement with Methanex, valid until April 30, 2017, which modified some terms of sixth amendment and
defined new conditions for September 2015 to August 2016 and for September 2016 to April 2017. The seventh amendment left required
reasonable efforts to take and deliver and giving our gas first priority over any third party supplies to Methanex.



We gather the gas we produce in several
wells through our own flow lines and inject it into several gas pipelines owned by ENAP. The transportation of the gas we sell
to Methanex through these pipelines is pursuant to a private contract between Methanex and ENAP. We do not own any principal natural
gas pipelines for the transportation of natural gas.



If we were to lose any one of our key customers
in Chile, the loss could temporarily delay production and sale of our oil and gas in Chile. For a discussion of the risks associated
with the loss of key customers, See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We
sell almost all of our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility”
and “—We derive a significant portion of our revenues from sales to a few key customers.”



Brazil



Our production in Brazil consists of natural
gas and condensate oil. Natural gas production is sold through a long-term, extendable agreement with Petrobras, which provides
for the delivery and transportation of the gas produced in the Manati Field to the EVF gas treatment plant in the State of Bahia.
The contract is in effect until delivery of the maximum committed volume or June 2030, whichever occurs first. The contract allows
for sales above the maximum committed volume if mutually agreed by both seller and buyer. The price for the gas is fixed in reais
and is adjusted annually in accordance with the Brazilian inflation index. In July 2015, we signed an amendment to the existing
Gas Sales Agreement with Petrobras that covers 100% of the remaining gas reserves in the Manati Field.



The Manati Field is developed via a PMNT-1
production platform, which is connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant through an
offshore and onshore pipeline with a capacity of 335.5 mmcfpd (9.5 mm3 per day). The existing pipeline connects the field’s
platform to the EVF gas treatment plant, which is owned by the field’s current concession holders. During 2015, in order
to improve the field gas recovery and production, Manatì’s consortium built an onshore compression plant that started
operating in August 2015, which allowed us to classify all existing proved undeveloped reserves as proved developed as of December
31, 2016.



The BCAM-40 Concession, which includes
the Manati Field, also benefits from the advantages of Petrobras’ size. As the largest onshore and offshore operator in Brazil,
Petrobras has the ability to mobilize the resources necessary to support its activities in the concession.



The condensate produced in the Manati Field
is subject to a condensate purchase agreement with Petrobras, pursuant to which Petrobras has committed to purchase all of our
condensate production in the Manati Field, but only in the amounts that we produce, without any minimum or maximum deliverable
commitment from us. The agreement is valid through December 31, 2017, but can be renewed upon an amendment signed by Petrobras
and the seller.



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Peru



In Peru, oil production is generally traded
on a free market basis and commercial conditions generally follow international markers, normally WTI and Brent. As per the Petroperu
SPA, Petroperu has the first option to acquire oil produced by us in the Morona Block by matching any offer received by third parties
regarding such production.



If we are not able to sell our production
share at the block or in Morona Station, we will have to use the North Peruvian Pipeline. This transportation system is owned and
operated by Petroperu, and regulated and supervised by OSINERGMIN, the regulatory body in the hydrocarbons sector. Transportation
rates are negotiated with Petroperu. However, if an agreement cannot be reached between Petroperu and us, transportation rates
will be determined by OSINERGMIN. The North Peruvian pipeline is currently out of service due to technical issues. The Peruvian
government has enacted a law declaring that resuming the pipeline’s operation is a matter of national interest, and is implementing
a maintenance program accordingly. See “Item 3. Risk factors—Risks relating to our business—Our inability to
access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate
significant incremental costs or delays in our oil and natural gas production.”



Argentina



In Argentina, we currently do not have
any producing blocks as of the date of this Annual Report.



Significant Agreements



Colombia



E&P Contracts



We have entered into E&P Contracts
granting us the right to explore and operate, as well as working interests in, eight blocks in Colombia. Additionally, we have
applied to the ANH to recognize our economic interest in a ninth Colombian block as a working interest. These E&P Contracts
are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and
(2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable.
Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties
to the relevant E&P Contract. The exploitation period for an area may be extended until such time as such area is no longer
commercially viable and certain other conditions are met.



Pursuant to our E&P Contracts, we are
required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the
Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002,
as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated
on a field-by-field basis. See Note 31 (a) to our Consolidated Financial Statements.



Additionally, in the event that an exploitation
area has produced amounts in excess of an aggregate amount established in the E&P Contract governing such area, the ANH is
entitled to receive a “windfall profit,” to be paid periodically, calculated pursuant to such E&P Contract.



In each of the exploration and exploitation
periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on
the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied
by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right
to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P
Contract.



Our E&P Contracts are generally subject
to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral
termination clauses or termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the
immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian
law, if certain conditions are met, the anticipated termination declared by the ANH may also result in a restriction on the ability
to engage contracts with the Colombian government during a certain period of time. See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—Our contracts in obtaining rights to explore and develop oil and natural
gas reserves are subject to contractual expiration dates and operating conditions, and our CEOPs, E&P Contracts and concession
agreements are subject to early termination in certain circumstances.”



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Llanos 34 Block E&P Contract.
Pursuant to an E&P Contract between Unión Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil and Gas
- now GeoPark Colombia SAS) and the ANH that became effective as of March 13, 2009 (“Llanos 34 Block E&P Contract”),
Unión Temporal Llanos 34 was granted the right to explore and operate the Llanos 34 Block, and we and Ramshorn were granted
a 40% and a 60% working interest, respectively, in the Llanos 34 Block. We were also granted the right to operate the Llanos 34
Block. On December 16, 2009, Winchester Oil and Gas (now GeoPark Colombia) entered into a joint operating agreement with Ramshorn
and P1 Energy with respect to our operations in the block. As of the date of this annual report, the members of the Union Temporal
Llanos 34 are GeoPark Colombia SAS with 45%, and Parex Verano Limited with 55% working interest.



We are currently in an additional exploration
period (the contract provides for two optional exploratory phases of 18 months each, in which the operator carries out exploratory
activities in order to retain areas to explore) of the Llanos 34 Block E&P Contract with an exploitation program in execution
over certain areas. The contract also provides for a six-year exploration period consisting of two three-year phases. It also provides
for a 24-year exploitation period for each commercial area, which begins on the date on which such area is declared commercially
viable. The exploitation period may be extended for periods of up to 10 years at a time until such time as the area is no longer
commercially viable and certain conditions are met. We have presented evaluation programs to the ANH for the Tilo Field. We presented
the declaration of commerciality of Max, Túa, Tarotaro, Tigana, Jacana and Chachalaca, respectively.



Pursuant to the Llanos 34 Block E&P
Contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block.
See Note 31 (a) to our Consolidated Financial Statements.



Additionally, we are required to pay a
subsoil use fee to the ANH. ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be,
exceed the prices set forth in the Llanos 34 Block E&P Contract. The ANH also has an additional economic right equivalent to
1% of production, net of royalties.



In accordance with the Llanos 34 Block
operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels
and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance
with an established formula. See Note 31 (a) to our Consolidated Financial Statements.



Winchester and Luna Stock Purchase Agreement



Pursuant to the stock purchase agreement
entered into on February 10, 2012 (the “Winchester Stock Purchase Agreement”), we agreed to pay the Sellers a total
consideration of US$30.0 million, adjusted for working capital. Additionally, under the terms of the Winchester Stock Purchase
Agreement, we are obligated to make certain payments to the Sellers based on the production and sale of hydrocarbons discovered
by exploration wells drilled after October 25, 2011. Once the maximum earn-out amount is reached, we pay the Sellers quarterly
overriding royalties in an amount equal to 4% of our net revenues from any new discoveries of oil. For the year ended December
31, 2016, we accrued and paid US$5.4 million and US$3.8 million with regards to this agreement.



Trafigura offtake and prepayment agreement



In December 2015, we entered into an offtake
and prepayment agreement with Trafigura. The agreement provides that we sell and deliver a portion of our Colombian crude oil production
to Trafigura. This benefits us by (i) improving crude oil sales prices; (ii) improving operating netbacks by reducing transportation
costs; (iii) simplifying logistics and reducing risks; and (iv) improving working capital. Pricing is determined at future spot
market prices, net of transportation costs. The agreement has given us access to funding up to US$100 million from Trafigura, subject
to applicable volumes corresponding to the terms of the agreement, in the form of prepaid future oil sales. Funds committed by
Trafigura will be made available to us upon request and will be repaid by us through future oil deliveries over the period of the
contract, until December 31, 2018, with a 6-month grace period.



During 2016 and 2017 we executed successive
amendments to the Trafigura offtake and prepayment agreement which increased volumes delivered, improved pricing and extended the
availability period for funding.



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Chile



CEOPs



We have entered into six CEOPs with Chile,
one for each of the blocks in which we operate, which grant us the right to explore and exploit hydrocarbons in these blocks, determine
our working interests in the blocks and appoint the operator of the blocks. These CEOPs are divided into two phases: (1) an exploration
phase, which is divided into two or more exploration periods, and which begins on the effectiveness date of the relevant CEOP,
and (2) an exploitation phase, which is determined on a per-field basis, commencing on the date we declare a field to be commercially
viable and ending with the term of the relevant CEOP. In order to transition from the exploration phase to an exploitation phase,
we must declare a discovery of hydrocarbons to the Ministry of Energy. This is a unilateral declaration, which grants us the right
to test a field for a limited period of time for commercial viability. If the field proves commercially viable, we must make a
further unilateral declaration to the Ministry of Energy. In the exploration phase, we are obligated to fulfill a minimum work
commitment, which generally includes the drilling of wells, the performance of 2D or 3D seismic surveys, minimum capital commitments
and guaranties or letters of credit, as set forth in the relevant CEOP. We also have relinquishment obligations at the end of each
period in the exploration phase in respect of those areas in which we have not made a declaration of discovery. We can also voluntarily
relinquish areas in which we have not declared discoveries of hydrocarbons at any time, at no cost to us. In the exploitation phase,
we generally do not face formal work commitments, other than the development plans we file with the Chilean Ministry of Energy
for each field declared to be commercially viable.



Our CEOPs provide us with the right to
receive a monthly remuneration from Chile, payable in petroleum and gas, based either on the amount of petroleum and gas production
per field or according to Recovery Factor, which considers the ratio of hydrocarbon sales to total cost of production (capital
expenditures plus operating expenses). Pursuant to Chilean law, the rights contained in a CEOP cannot be modified without consent
of the parties.



Our CEOPs are subject to early termination
in certain circumstances, which vary depending upon the phase of the CEOP. During the exploration phase, Chile may terminate a
CEOP in circumstances including a failure by us to comply with minimum work commitments at the termination of any exploration period,
or a failure to communicate our intention to proceed with the next exploration period 30 days prior to its termination, a failure
to provide the Chilean Ministry of Energy the performance bonds required under the CEOP, a voluntary relinquishment by us of all
areas under the CEOP or a failure by us to meet the requirements to enter into the exploitation phase upon the termination of the
exploration phase. In the exploitation phase, Chile may terminate a CEOP if we stop performing any of the substantial obligations
assumed under the CEOP without cause and do not cure such nonperformance pursuant to the terms of the concession, following notice
of breach from the Chilean Ministry of Energy. Additionally, Chile may terminate the CEOP due to force majeure circumstances (as
defined in the relevant CEOP). If Chile terminates a CEOP in the exploitation phase, we must transfer to Chile, free of charge,
any productive wells and related facilities, provided that such transfer does not interfere with our abandonment obligations and
excluding certain pipelines and other assets. Other than as provided in the relevant CEOP, Chile cannot unilaterally terminate
a CEOP without due compensation. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our
contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and
operating conditions, and our CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances.”



Fell Block CEOP. On November 5,
2002, we acquired a percentage of rights and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and on
May 10, 2006, we became the sole owners, with 100% of the rights and interest in the Fell Block CEOP. Chile had originally entered
into a CEOP for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997, which had an effective date of
August 25, 1997. The Fell Block CEOP grants us the exclusive right to explore and exploit hydrocarbons in the Fell Block and has
a term of 35 years, beginning on the effective date. The Fell Block CEOP provided for a 14-year exploration period, composed of
numerous phases that ended in 2011, and an up-to-35-year exploitation phase for each field.



The Fell Block CEOP provides us with a
right to receive a monthly retribution from Chile payable in petroleum and gas, based on the following per-field formula: 95% of
the oil produced in the field, for production of up to 5,000 bopd, ring fenced by field, and 97% of gas produced in the field,
for production of up to 882.9 mmcfpd. In the event that we exceed these levels of production, our monthly retribution from Chile
will decrease based on a sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the oil and 60% of the gas that
we produce per field.



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TDF Blocks CEOPs. After an international
bidding process led by ENAP and the Chilean Ministry of Energy, in March and April, 2012, we, together with ENAP, signed 3 new
CEOPs for the Isla Norte, Campanario and Flamenco Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes
region. Our working interest is 60% in Isla Norte and 50% in Campanario and Flamenco Blocks. The CEOPs have a term of 32 years,
with an initial exploration phase which last for 7 years, including a first exploration period of 3 years in which we are committed
to developing several exploration activities including 1,500 square kilometers of 3D seismic registration, and the drilling of
21 exploratory wells.



The hydrocarbon discoveries opened up an
exploitation phase that lasts up to 32 years. We discovered hydrocarbon fields in the 3 blocks, starting 2013 in the Flamenco Block,
and in 2014 in both Campanario and Isla Norte Blocks. The CEOPs provide us with a right to receive a remuneration payable by means
of a fraction of the production sold, which in the TDF Blocks is based on a formula depending on the recovery of the total accumulated
expenses incurred (capital expenditure plus operational expenditure plus administrative and general expenses). While the recovery
factor is less than 1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas. If the recovery factor surpasses
1.0, a formula applies reducing gradually the remuneration fraction to a minimum of 75% when the recovery factor is 2.5 times the
total accumulated expenses.



Brazil



Rio das Contas Quota Purchase Agreement



Pursuant to the Rio das Contas Quota Purchase
Agreement we entered into on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued by Rio das Contas for a purchase
price of US$140 million (subject to working capital adjustments at closing and further earn-out payments, if any) upon satisfaction
of certain conditions. With respect to the earn-out payments, the Rio das Contas Quota Purchase Agreement provides that during
the calendar periods beginning on January 1, 2013 and ending as late as December 31, 2017, we will make annual earn-out payments
to Panoro in an amount equal to 45% of “net cash flow,” calculated as EBITDA less the aggregate of capital expenditures
and corporate income taxes, with respect to the BCAM-40 Concession of any amounts in excess of US$25.0 million, up to a maximum
cumulative earn-out amount of US$20.0 million in a five-year period. Once the maximum earn-out amount is reached or the five-year
period has elapsed, no further earn-out amounts will be payable. For the year ended December 31, 2016, there were no earn-out payments
with regards to this agreement.



We financed our Rio das Contas acquisition
in part through our Brazilian subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas Credit
Facility”) with Itaú BBA International plc, which is secured by the benefits we receive under the Purchase and Sale
Agreement for Natural Gas with Petrobras. See “Item 5. Operating and Financial Review and Prospects—B.  Liquidity
and capital resources—Indebtedness—Rio das Contas Credit Facility.”



Overview of concession agreements



The Brazilian oil and gas industry is governed
mainly by the Brazilian Petroleum Law, which provides for the granting of concessions to operate petroleum and gas fields in Brazil,
subject to oversight by the ANP. A concession agreement is divided into two phases: (1) exploration and (2) development and production.
The exploration phase, which is further divided into two subsequent exploratory periods, the first of which begins on the date
of execution of the concession agreement, can last from three to eight years (subject to earlier termination upon the total return
of the concession area or the declaration of commercial viability with respect to a given area), while the development and production
phase, which begins for each field on the date a declaration of commercial viability is submitted to the ANP, can last up to 27
years. Upon each declaration of commercial viability, a concessionaire must submit to the ANP a development plan for the field
within 180 days. The concessions may be renewed for an additional period equal to their original term if renewal is requested with
at least 12 months’ notice, and provided that a default under the concession agreement has not occurred and is then continuing.
Even if obligations have been fulfilled under the concession agreement and the renewal request was appropriately filed, renewal
of the concession is subject to the discretion of the ANP.



The main terms and conditions of a concession
agreement are set forth in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the concession area; (2) validity
and terms for exploration and production activities; (3) conditions for the return of concession areas; (4) guarantees to be provided
by the concessionaire to ensure compliance with the concession agreement, including required investments during each phase; (5)
penalties in the event of noncompliance with the terms of the concession agreement; (6) procedures related to the assignment of
the agreement; and (7) rules for the return and vacancy of areas, including removal of equipment and facilities and the return
of assets. Assignments of participation interests in a concession are subject to the approval of the ANP, and the replacement of
a performance guarantee is treated as an assignment.



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The main rights of the concessionaires
(including us in our concession agreements) are: (1) the exclusive right of drilling and production in the concession area; (2)
the ownership of the hydrocarbons produced; (3) the right to sell the hydrocarbons produced; and (4) the right to export the hydrocarbons
produced. However, a concession agreement set forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire
must fulfill the needs of the domestic market. In order to ensure the domestic supply, the Brazilian Petroleum Law granted the
ANP the power to control the export of oil, natural gas and oil products.



Among the main obligations of the concessionaire
are: (1) the assumption of costs and risks related to the exploration and production of hydrocarbons, including responsibility
for environmental damages; (2) compliance with the requirements relating to acquisition of assets and services from domestic suppliers;
(3) compliance with the requirements relating to execution of the minimum exploration program proposed in the winning bid; (4)
activities for the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments for government participation; and
(7) responsibility for the costs associated with the deactivation and abandonment of the facilities in accordance with Brazilian
law and best practices in the oil industry.



A concessionaire is required to pay to
the Brazilian government the following:



| | · | a license fee;
| | - | --------------



| | · | rent for the occupation or retention of areas;
| | - | ----------------------------------------------



| | · | a special participation fee;
| | - | ----------------------------



| | · | royalties; and
| | - | --------------



| | · | taxes.
| | - | ------



Rental fees for the occupation and maintenance
of the concession areas are payable annually. For purposes of calculating these fees, the ANP takes into consideration factors
such as the location and size of the relevant concession, the sedimentary basin and the geological characteristics of the relevant
concession.



A special participation fee is an extraordinary
charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according
to criteria established by applicable regulations, and is payable on a quarterly basis for each field from the date on which extraordinary
production occurs. This participation fee, whenever due, varies between 0% and 40% of net revenues depending on (1) the volume
of production and (2) whether the concession is onshore or in shallow water or deep water. Under the Brazilian Petroleum Law and
applicable regulations issued by the ANP, the special participation fee is calculated based on the quarterly net revenues of each
field, which consist of gross revenues calculated using reference prices established by the ANP (reflecting international prices
and the exchange rate for the period) less:



| | · | royalties paid;
| | - | ---------------



| | · | investment in exploration;
| | - | --------------------------



| | · | operational costs; and
| | - | ----------------------



| | · | depreciation adjustments and applicable taxes.
| | - | ----------------------------------------------



The Brazilian Petroleum Law also requires
that the concessionaire of onshore fields pay to the landowners a special participation fee that varies between 0.5% to 1.0% of
the net operational income originated by the field production.



BCAM-40 Concession Agreement. On
August 6, 1998, the ANP and Petrobras executed the concession agreement governing the BCAM-40 Concession, or the BCAM-40 Concession
Agreement, following the first round of bidding, referred to as Bid Round Zero, under the regime established by the Brazilian Petroleum
Law. The exploitation phase will end in November 2029. On September 11, 2009, Petrobras announced the termination of BCAM-40 Concession’s
exploration phase and the return of the exploratory area of the concession to the ANP, except for the Manati Field and the Camarão
Norte Field.



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Under the BCAM-40 Concession Agreement,
the ANP is entitled to a monthly royalty payment equal to 7.5% of the production of oil and natural gas in the concession area.
In addition, in case the special participation fee of 10% shall be applicable for a field in any quarter of the calendar year,
the concessionaire is obliged to make qualified research and development investments equivalent to one percent of the field’s
gross revenue. Area retention payments are also applicable under the concession agreement. We acquired Rio das Contas’s 10%
participation interest in the BCAM-40 Concession on March 31, 2014.



Rounds 11, 12 and 13 Concession Agreements.



Under the Rounds 11, 12 and 13 Concession
Agreements, the ANP is entitled to a monthly royalty corresponding to 10% of the production of oil and natural gas in the concession
area, in addition to the special participation fee described above, the payment for the occupation of the concession area of approximately
R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and natural gas
produced in the concession area.



During bidding, a work program offer is
made in the form of work units and the ANP asks for a guarantee of a monetary amount proportional to the offered units. However,
depending on the work performed by the operator, the actual work program investment might have a different value to the guaranteed
value.



Overview of consortium agreements



A consortium agreement is a standard document
describing consortium members’ respective percentages of participation and appointment of the operator. It generally provides
for joint execution of oil and natural gas exploration, development and production activities in each of the concession areas.
These agreements set forth the allocation of expenses for each of the parties with respect to their respective participation interests
in the concession. The agreements are supplemented by joint operating agreements, which are private instruments that typically
regulate the aggregation of funds, the sharing of costs, mitigation of operational risks, preemptive rights and the operator’s
activities.



An important characteristic of the consortia
for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, of the Brazilian
Corporate Law) is the joint liability among consortium members as established in the Brazilian Petroleum Law (Article 38, item
II).



BCAM-40 Consortium Agreement



On January 14, 2000, Petrobras, QG Perfurações
and Petroserv entered into a consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession
Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. QGEP, Brasoil and Rio das Contas
have a 45%, 10% and 10% participation interest, respectively. The BCAM-40 Consortium Agreement has a specified term of 40 years,
terminating on January 14, 2040 and, at the time the obligations undertaken in the agreement are fully completed, the parties will
have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets
out the rights and obligations of the parties in respect of the operations in the concession.



Petrobras Natural Gas Purchase Agreement



QGEP, GeoPark Brasil, Brasoil and Petrobras
are party to a natural gas purchase agreement providing for the sale of natural gas by QGEP, GeoPark Brasil and Brasoil to Petrobras,
in an amount of 812 billion cubic feet (“bcf”) over the term of agreement. The Petrobras Natural Gas Purchase Agreement
is valid until the earlier of Petrobras’ receipt of this total contractual quantity or June 30, 2030. The agreement may not
be fully or partially assigned except upon execution of an assignment agreement with the written consent of the other parties,
which consent may not be unreasonably withheld provided that certain prerequisites have been met.



The agreement provides for the provision
of “daily contractual quantities” to Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until 2030.
The parties may agree to lower volumes as dictated by Manati Field’s depletion. Pursuant to the agreement, the base price
is denominated in reais and is adjusted annually for inflation pursuant to the general index of market prices (IGPM). Additionally,
the gas price applicable on a given day is subject to reduction as a result of the gas quantity acquired by Petrobras above the
volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase
Agreement provides that all of the Manati Field’s daily production be sold to Petrobras.



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Peru



Morona Block



On October 1, 2014,
we entered into an agreement with Petroperu to acquire an interest in and operate the Morona Block, located in Northern Peru. We
will assume a 75% working interest of the Morona Block, with Petroperu retaining a 25% working interest. On December 1, 2016, through
Supreme Decree N° 031-2016-MEN the Peruvian government approved the amendment to the License Contract of Block 64 (Morona Block)
appointing GeoPark as operator and holder of 75% of the Contract.



In Peru, there is a 5-20% sliding scale
royalty rate, depending on production levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For production
between 5,000 and 100,000 bopd there is a linear sliding scale between 5% and 20%. Production over 100,000 bopd has a flat royalty
of 20%.



See “Item 4. Information on the Company—B. Business
Overview—Our operations—Operations in Peru—Morona Block.”



Argentina



Overview of exploration permits



Our exploration permits grant to us and
our partners the exclusive right to explore for hydrocarbons and declare a commercial discovery within the acreage of our permits.
Our exploration permits are made up of three subperiods, each lasting 3, 2 and 1 year(s), respectively, plus an extension period
of up to 5 years.



We are bound to pursue specific minimum
work or investment commitments during each of the subperiods of each exploration permit. Such exploration works are valued in work
units assigned to each particular type of work under the applicable bidding conditions.



Work and investment programs for the permits
are required to be assured by issuing a performance bond for the value of the committed work plan.



Under the terms of our exploration permits
and concession agreements, we are entitled to our proportionate share of the hydrocarbons production lifted from each block. The
Province of Mendoza’s state owned company, EMESA, has a 10% carried interest in each of the Puelen and Sierra del Nevado
permits and any future exploitation concessions, while there is no governmental participation in the CN-V Block. During the term
of our exploration permits, we are also required, under Argentine law, to pay a 15% royalty to the province on both oil and gas
sales. In case we progress to an exploitation concession, the applicable royalty rate will reduce to a 12% royalty. We also pay
annual surface rental fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and Resolution 588/98 of
the Argentine Secretariat of Energy and Decree 1454/2007, and certain landowner fees.



Our Argentine exploration permits have
no change of control provisions, though any assignment of these concessions is subject to the prior authorization by the executive
branch of the Province of Mendoza and rights of first refusal in favor of our partners and EMESA, in the case of the Puelen and
Sierra del Nevado permits. Each of these permits or future concessions can be terminated for default in payment obligations and/or
breach of material statutory or regulatory obligations. We are subject to the obligation to relinquish at least 50% of the acreage
of each exploration permit at the end of each exploration subperiod. We may also voluntarily relinquish acreage to the provincial
authorities.



Our Argentine exploration permits are governed
by the laws of Argentina and the resolution of any disputes must be sought in the Mendoza Provincial Courts.



If and when we make a commercial discovery
in one or more of our exploration permits, we will have the right to request and obtain an exploitation concession to produce hydrocarbons
in the block for 25 years, with an optional extension of up to 10 years. We also receive the right to be granted a 35-year oil
transport concession to build and make use of pipelines or other transport facilities beyond the boundaries of the concession.



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Additionally, oil and gas producers in
Argentina must grant a privilege to the domestic market to the detriment of the export market, including hydrocarbon export restrictions,
domestic price controls, export duties and domestic market supplier obligations.



Agreements with LGI



LGI Colombia Agreements



In December 2012, we agreed with LGI to
extend our strategic partnership to build a portfolio of upstream oil and gas assets throughout Latin America. On December 18,
2012, LGI agreed to acquire a 20% equity interest in GeoPark Colombia SAS for a total consideration of US$20.1 million composed
of a US$14.9 million capital contribution, a US$4.9 million loan to GeoPark Colombia SAS and miscellaneous reimbursements. Concurrently,
we entered into a shareholders’ agreement with LGI (“LGI Colombia Shareholders’ Agreement”) setting forth
LGI’s and our respective obligations in connection with LGI’s investment in our Colombian oil and gas business through
GeoPark Colombia SAS. Furthermore, LGI and Winchester (now GeoPark Colombia SAS) entered into a loan agreement, whereby, upon the
closing of LGI’s subscription of shares in GeoPark Colombia SAS, LGI granted a credit line (of which US$4.9 million was drawn
at closing) to Winchester of up to US$12.0 million, to be used for the acquisition, development and operation of oil and gas assets
in Colombia. Further, on January 8, 2014, following an internal corporate reorganization of our Colombian operations, GeoPark Colombia
Coöperatie U.A. and GeoPark Latin America entered into a new members’ agreement with LGI, or the LGI Colombia Members’
Agreement, that sets out substantially similar rights and obligations to the LGI Colombia Shareholders’ Agreement in respect
of our oil and gas business through GeoPark Colombia SAS only. We refer to the LGI Colombia Shareholders’ Agreement and the
LGI Colombia Members’ Agreement collectively as the LGI Colombia Agreements.



Under the LGI Colombia Agreements, LGI
agreed to assume its share of the existing debt of GeoPark Colombia SAS and to provide additional funding to cover LGI’s
share of required future investments in Colombia through GeoPark Colombia SAS. In addition, we can earn back up to 12% additional
equity interests in GeoPark Colombia depending on the success of our Colombian operations.



Currently, GeoPark Colombia Coöperatie
has four directors, out of which one Director is elected by LGI. The LGI Colombia Agreements require the consent of LGI or the
LGI-appointed director for GeoPark Colombia SAS to take certain actions, including, among others:



| | · | making any decision to terminate or permanently or indefinitely suspend operations in or surrender our blocks in Colombia (other
than as required under the terms of the relevant concessions for such blocks);
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | creating of a security interest over our blocks in Colombia;
| | - | ------------------------------------------------------------



| | · | approving of GeoPark Colombia’s annual budget and work programs and the mechanisms for funding any such budget or program;
| | - | --------------------------------------------------------------------------------------------------------------------------



| | · | entering into of any borrowings other than those provided in an approved budget or incurred in the ordinary course of business
to finance working capital needs;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | granting any guarantee or indemnity to secure liabilities of parties other than those of our Colombian subsidiaries;
| | - | --------------------------------------------------------------------------------------------------------------------



| | · | changing the dividend, voting or other rights that would give preference to or discriminate against the shareholders of GeoPark
Colombia;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



| | · | entering into certain related party transactions; and
| | - | -----------------------------------------------------



| | · | disposing of any material assets other than those provided for in an approved budget and work program.
| | - | ------------------------------------------------------------------------------------------------------



We have also agreed to ensure that the
board of directors and rules and management of our other subsidiaries engaged in our Colombian oil and gas business are subject
to the same principles and restrictions outlined above.



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The LGI Colombia Agreements provide that
if either we or LGI decide to sell our respective participation in GeoPark Colombia Coöperatie, the transferring party must
make an offer to sell its participation to the other party before selling those shares to a third party. In addition, any sale
to a third party is subject to tag-along and drag-along rights, and the non-transferring party has the right to object to a sale
to the third-party if it considers such third-party to be not of a good reputation or one of our direct competitors.



Under the LGI Colombia Agreements, we have
agreed, along with LGI, to vote or otherwise cause GeoPark Colombia SAS to declare dividends only after allowing for retentions
for approved work programs and budgets and capital adequacy requirements of GeoPark Colombia Coöperatie, working capital requirements,
banking covenants associated with any loan entered into by GeoPark Colombia Coöperatie and its subsidiary. See “Item
3. Key Information—D. Risk factors—Risks relating to our business—LGI, our strategic partner in Chile and Colombia,
may not consent to our taking certain actions or may eventually decide to sell its interest in our Chilean and Colombian operations
to a third party.”



LGI Chile Shareholders’ Agreements



In 2010, we formed a strategic partnership
with LGI to jointly acquire and develop upstream oil and gas projects in Latin America. In 2011, LGI acquired a 20% equity interest
in GeoPark Chile and a 14% equity interest in GeoPark TdF, for a total consideration of US$148.0 million, plus additional equity
funding of US$18.0 million over the following three years. On May 20, 2011, in connection with LGI’s investment in GeoPark
Chile, we entered into a shareholders’ agreement with LGI (as amended on July 4, 2011 and October 4, 2011, the “GeoPark
Chile Shareholders’ Agreement”) and a subscription agreement (as amended on July 4, 2011 and October 4, 2011), On October
2011, in connection with LGI’s investment in GeoPark TdF, we entered into a shareholder ́s agreement with LGI (the “GeoPark
TdF Shareholders Agreement”, and together with the GeoPark Chile Shareholders’ Agreement, the “LGI Chile Shareholders’
Agreements”), setting forth LGI’s and our respective rights and obligations in connection with LGI’s investment
in our Chilean oil and gas business.



The respective boards of each of GeoPark
Chile and GeoPark TdF supervise their day-to-day operations. Each of these boards has four directors. As long as LGI holds at least
5% of the voting shares of GeoPark Chile, LGI has the right to elect one director and such director’s alternate, and the
remaining directors, and alternates, are elected by us. As long as LGI holds at least 5% of the voting shares of GeoPark TdF, LGI
has the right to elect one director and such director’s alternate, and the remaining directors, and alternates, are elected
by GeoPark Chile.



The LGI Chile Shareholders’ Agreements
require the consent of LGI or the LGI appointed director in order for GeoPark Chile and GeoPark TdF, as the case may be, to take
certain actions, including, among others:



| | · | making any decision to terminate or permanently or indefinitely suspend operations in or surrender our blocks in Chile (other
than as required under the terms of the relevant CEOP for such blocks or required by law);
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | selling our blocks in Chile to our affiliates;
| | - | ----------------------------------------------



| | · | any change to the dividend, voting or other rights that would give preference to or discriminate against the shareholders of
GeoPark Chile and GeoPark TdF;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | entering into certain related party transactions; and
| | - | -----------------------------------------------------



| | · | creating a security interest over our blocks in Chile (other than in connection with a financing that benefits our Chilean
subsidiaries).
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



The LGI Chile Shareholders’ Agreements
provide that if LGI or either Agencia or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark TdF, as the case
may be, the transferring shareholder must make an offer to sell those shares to the other shareholder before selling those shares
to a third party. In addition, any sale to a third party is subject to tag-along and drag-along rights, and the non-transferring
shareholder has the right to object to a sale to the third-party if it considers such third-party to be not of a good reputation
or one of our direct competitors. Under the LGI Chile Shareholders’ Agreements, we and LGI have also agreed to vote our common
shares or otherwise cause GeoPark Chile or GeoPark TdF, as the case may be, to declare dividends only after allowing for retentions
to meet anticipated future investments, costs and obligations. See “Item 3. Key Information—D. Risk factors—Risks
relating to our business—LGI, our strategic partner in Chile and Colombia, may not consent to our taking certain actions
or may eventually decide to sell its interest in our Chilean and Colombian operations to a third party.”



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Title to properties



In each of the countries in which we operate,
the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights,
royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. In Chile,
the Republic of Chile grants such rights through a CEOP. In Colombia, the Republic of Colombia grants such rights through E&P
Contracts or contracts of association. In Argentina, the Argentine Republic grants such rights through exploitation concessions.
In Brazil, the Federative Republic of Brazil grants such rights pursuant to concession agreements. See “Item 3. Key Information—D.
Risk factors—Risks relating to the countries in which we operate—Oil and natural gas companies in Colombia, Chile,
Brazil, Peru and Argentina do not own any of the oil and natural gas reserves in such countries.” Other than as specified
in this annual report, we believe that we have satisfactory rights to exploit or benefit economically from the oil and gas reserves
in the blocks in which we have an interest in accordance with standards generally accepted in the international oil and gas industry.
Our CEOPs, E&P Contracts, contracts of association, exploitation concessions and concession agreements are subject to customary
royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the
oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests.
See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be
in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working
interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts,
associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly-owned, assets.”



Our customers



In Colombia, our primary customer is Trafigura,
and who represented 59%, of our total revenues for the year ended December 31, 2016. In Chile, our primary customers are ENAP and
Methanex. As of December 31, 2016, ENAP purchased all of our oil and condensate production and Methanex purchased almost all of
our natural gas production in Chile, and represented 10% and 9%, respectively, of our total revenues for the year ended December
31, 2016. In Brazil, all of our hydrocarbons in Manati are sold to Petrobras. In Peru, our primary customer may be Petroperu, has
the first option to acquire the oil produced by us in the Morona Block by matching any offer received by third parties regarding
such production.



Seasonality



Although there is some historical seasonality
to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not
played a significant role in our ability to conduct our operations, including drilling and completion activities.



However, as the Morona Block is located
in a remote area, the development of the project depends on significant infrastructure being built which can be impacted by seasonal
weather patterns, including rain. Since there are no roads available in the surrounding area, logistics will be performed by helicopters
or barges during specific seasons of the year.



We take such seasonality into account in
planning for and conducting our operations, such that the impact on our overall business is not material.



Our competition



The oil and gas industry is competitive,
and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring
and developing licenses in the countries where we operate or plan to operate.



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Many of these competitors have financial
and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for
desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel
resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful
wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic
conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely
affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Competition
in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects,
market oil and natural gas and secure trained personnel.”



We may also be affected by competition
for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling
rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services
and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our
ability to drill wells and conduct our operations.



Health, safety and environmental matters



General



Our operations are
subject to various stringent and complex international, federal, state and local environmental, health and safety laws and regulations
in the countries in which we operate. These laws and regulations govern matters including the emission and discharge of pollutants
into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and human health
and safety. These laws and regulations may, among other things:



| | · | require the acquisition of various permits or other authorizations or the preparation of environmental
assessments, studies or plans (such as well closure plans) before seismic or drilling activity commences;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | enjoin some or all of the operations of facilities deemed not in compliance with permits;
| | - | -----------------------------------------------------------------------------------------



| | · | restrict the types, quantities or concentration of various substances that can be released into
the environment related to oil and natural gas drilling, production and transportation activities;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | require establishing and maintaining bonds, reserves or other commitments to plug and abandon wells;
| | - | ----------------------------------------------------------------------------------------------------



| | · | limit or prohibit seismic and drilling activities in certain locations lying within or near protected
or environmentally sensitive areas;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



| | · | require preventative measures to mitigate pollution from our operations, which, if not undertaken,
could subject us to substantial penalties; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------



| | · | require us to maintain a safe and healthy working environment for all employees, contractors and
visitors in accordance with applicable regulations and industry best practices.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



These laws and regulations
may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these
laws can be costly. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and
consequently affects profitability.



Public interest in
the protection of the environment continues to increase. Drilling in some areas has been opposed by certain community and environmental
groups and, in other areas, has been restricted.



Climate change



Both our operations and the combustion
of oil and natural gas-based products results in the emission of greenhouse gases, which may contribute to global climate change.
Climate change regulation has gained momentum in recent years internationally and at the federal, regional, state and local levels.
On the international level, various nations have committed to reducing their greenhouse gas emissions pursuant to the Kyoto Protocol.
The Kyoto Protocol was set to expire in 2012. In late 2011, an international climate change conference in Durban, South Africa
resulted in, among other things, an agreement to negotiate a new climate change regime by 2015 that would aim to cover all major
greenhouse gas emitters worldwide, including the U.S., and take effect by 2020. In November and December 2012, at an international
meeting held in Doha, Qatar, the Kyoto Protocol was extended by amendment until 2020. In addition, the Durban agreement to develop
the protocol’s successor by 2015 and implement it by 2020 was reinforced. We are committed to controling the emission of
greenhouse gases and implementing available technologies to reduce the impact caused by our operations. For example, during 2016
we began a migration plan to replace diesel with natural gas and electric generation.



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Our HSE Management System



Our health, safety and environmental management
plan is focused on undertaking realistic and practical programs based on recognized world practices. Our emphasis is on building
key principles and company-wide ownership and then expanding programs as we continue growing. Our S.P.E.E.D. philosophy and our
HSE Plan have been developed with reference to ISO 14001 for environmental management issues, OHSAS 18001 for occupational health
and safety management issues, SA 8000 for social accountability and workers’ rights issues and applicable World Bank Standards.



Our Environmental Policy



Our policy looks forward to meet or exceed
environmental regulations in the countries in which we operate. We believe that oil and gas can be produced in an environmentally-responsible
manner with proper care, understanding and management. Within our S.P.E.E.D. philosophy we have a team that is exclusively focused
on securing the environmental authorizations and permits for the projects we undertake. This professional and trained team, specialized
in environmental issues, is also responsible for the achievement of the environmental standards set by our Board of Directors and
for training and supporting our personnel. Our senior executives, personnel in the field, visitors and contractors have also received
training in proper environmental management.



Our Health and Safety Policy



We believe that the implementation of additional
safety tools in our operations in 2016 has significantly contributed to control and minimizing risks in our operations. Actions
taken by us included the development of a new Proactive Observation Program, HSE training, permits to work, internal audits, drills,
pre-job meetings and job safety analysis, among others. As of December 31, 2016, on the last 12-month basis, our HSE development
statistics workforce shows that Lost Time Injury Frequency (LTIF) was 0.63 (out of every 1,000,000 worked hours), our Total Recordable
Incident Rate (TRIR) was 1.89 (out of every 1,000,000 worked hours) and we had no fatal incidents related to operations in 2016
(workforce).



In 2016, we subscribed to the International
Association of Oil and Gas Producers in order to align our Management System and policies with the best international standards.



Certain Bermuda law considerations



As a Bermuda exempted company, we and our
Bermuda subsidiaries are subject to regulation in Bermuda. We have been designated by the BMA as a non-resident for Bermuda exchange
control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are
no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda.



Under Bermuda’s law, “exempted”
companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda.
As exempted companies, we and our Bermuda subsidiaries may not, without a license or consent granted by the Minister of Finance
of Bermuda, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying
on of business of any kind for which we or our Bermuda subsidiaries are not licensed in Bermuda.



Insurance



We maintain insurance coverage of types
and amounts that we believe to be customary and reasonable for companies of our size and with similar operations in the oil and
gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business,
either because such insurance is not available or because premium costs are considered prohibitive.



Currently, our insurance program includes,
among other things, construction, fire, vehicle, technical, umbrella liability, director’s and officer’s liability
and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met
prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business,
financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to
our business—Oil and gas operations contain a high degree of risk and we may not be fully insured against all risks we face
in our business.”



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Industry and regulatory framework



Colombia



Regulation of the oil and gas industry



The ANH is responsible for managing all
exploration lands not subject to previously existing association contracts with Ecopetrol. The ANH began offering all undeveloped
and unlicensed exploration areas in the country under E&P Contracts and Technical Evaluation Agreements, or TEAs, which resulted
in a significant increase in Colombian exploration activity and competition, according to the ANH. The ANH is also in charge of
negotiating and executing contracts through “direct negotiation” mechanisms with attention to special conditions in
the areas to be explored.



Regulatory framework



Regulation of exploration and production activities



Pursuant to Colombian law, the state is
the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties
or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of
Mines and Energy is the authority responsible for regulating all activities related to the exploration and production of hydrocarbons
in Colombia.



Decree Law 1056 of 1953 (Código
de Petróleos), or the Petroleum Code, establishes the general procedures and requirements that must be completed by
a private investor and disclosure procedures that need to be followed during the performance of these activities.



Exploration and production activities were
governed by Decree 1895 of 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by Decree 743 of 1975) governed
the contracts and contracting processes carried out by Ecopetrol and the rules applicable to such contracts, and also provided
that Ecopetrol was responsible for administering the hydrocarbons resources in the Country. Decree 2310 of 1974 was replaced by
Decree Law 1760 of 2003, but all agreements entered into by us prior to 2003 with other oil companies are still regulated by Decree
2310 of 1974.



The regime for the ANH’s contracts
is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by Accord 004 of
2012, issued by the Directive Council of the ANH, sets forth the necessary steps for entering into E&P Contracts with the ANH.
This Agreement only regulates the contracts entered into as of May 4, 2012. Prior contracts are still ruled by Agreement 008
of 2004. Due to the oil prices crisis of 2015, the ANH implemented transitory measures through Agreements 002, 003, 004 and 005
of 2015, which are still in place. The ANH is working on a new Agreement that compiles the relevant rulings in one document.



Resolution 18-1495 of 2009 establishes
a series of regulations regarding hydrocarbon exploration and exploitation. In the E&P Contracts, operators are afforded access
to non-contracted blocks by committing to an exploration work program. These E&P Contracts provide companies with 100% of new
production, less the participation of the ANH, which participation may differ for each E&P Contract and depends on the percentage
that each company has offered to the ANH in order to be granted with a block, subject to an initial royalty payment of 8% and the
payment of income taxes of 33%. In addition, the Colombian government also introduced TEAs, in which companies that enter into
TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas and to propose work commitments
on those areas, and have a preemptive right to enter into an E&P Contract, thereby providing companies with low-cost access
to larger areas for preliminary evaluation prior to committing to broader exploration programs. A preemptive right is granted to
convert the TEA into an E&P Contract. Exploration activities can only be carried out by the TEA contractor.



Pursuant to Colombian law, companies are
obligated to pay a percentage of their production to the ANH as royalties and an economic right as ANH’s participating interest
in the production. Producing fields pay royalties in accordance with the applicable royalty program at the time of the discovery.



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Taxation



The Tax Statute and Law 9 of 1991 provide
the primary features of the oil and gas industry’s tax and exchange system in Colombia. Generally, national taxes under the
general tax statute apply to all taxpayers, regardless of industry. The main taxes currently in effect—after the December
2016 tax reform discussed below—are the income tax (40% for 2017, 37% for 2018 and 33% for 2019 onwards), sales or value
added tax (19%), and the tax on financial transaction (0.4%). Additional regional taxes also apply. Colombia has entered into a
number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax.
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment
in Colombia. Resolution 8 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions
governing exchange operations. Articles 48 to 52 of Resolution 8 provide for a special exchange regime for the oil industry that
removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies.
Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign
exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in
this special oil and gas exchange regime, however, by informing the Colombian Central Bank, in which case they will be subject
to the general exchange regime of Resolution 8 and may not be able to access the special exchange regime for a period of 10 years.
In December 2016, the Colombian Congress approved a tax reform (Law 1819 of 2016). The main aspects of the reform are summarized
below.



| | · | The enterprise contribution on equality (“CREE” for its Spanish acronym) tax is eliminated, but a carry forward
of CREE receivables and losses for income tax purposes will be permitted.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Income tax rates will be 34% plus a 6% surcharge for fiscal year 2017, 33% plus a 4% surcharge for fiscal year 2018 and 33%
for fiscal year 2019 and beyond.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | A dividend tax is included on distributions from Colombian corporations for non-resident shareholders, with tax rates of 5%,
for dividends which were taxed at the corporate level and 35% and then a 5% on the remaining amount for dividends which were not
taxed at the corporate level.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Grandfather rules avoid the application of the 5% tax for profits obtained before fiscal year 2017. While it is unclear what
the rate is today for profits obtained before that date which were not taxed at the corporate level, a conservative approach would
be to tax them at 35%.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Tax losses to be carried forward up to 12 years, losses generated before 2017 are grandfathered.
| | - | ------------------------------------------------------------------------------------------------



| | · | Presumptive taxable base increases to 3.5% of the net equity at the end of the prior year.
| | - | ------------------------------------------------------------------------------------------



| | · | Cross border payments withholding tax suffered modifications. The general rule on services is that there will be a 15% withholding
tax, which includes management fees, even if the service is rendered form abroad. Additionally, services rendered from abroad will
be subject to VAT if the beneficiary is in Colombia (for example services rendered to Geopark Colombia from abroad would be subject
to such treatment).
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | The net wealth tax is still set to expire in fiscal year 2017 for corporations, but it remains unclear if its term will be
extended.
| | - | ------------------------------------------------------------------------------------------------------------------------------------



| | · | IFRS will become the basis for tax purposes with certain exceptions, such as:
| | - | -----------------------------------------------------------------------------



| | o | Depreciation: The general rule is that the term of depreciation is determined according to IFRS, but with a depreciation percentage
cap per year for tax purposes. Assets held before 2017 will be depreciated according to the previous rules.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | Amortization: Amortization of investments in the oil and gas industry to be depleted according to the “units of production
method” beginning 2028. Beginning in fiscal year 2017 and until 2027,exploratory investments will be amortized by the straight line method in a period of 5 years. Grandfather rule was established
for undepleted investments held before fiscal year 2017.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | · | Goodwill in the acquisition of shares is no longer subject to amortization. Goodwill generated before 2017 will be subject
to amortization according to the rules enforceable at the moment of generation of the goodwill, however amortization of the undepleted
values as of January 1, 2017 may not take more than five years, and must be done through the straight line method.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | VAT modifications: (a) general rate increased to 19%; (b) eight month window period to credit input tax; (c) input tax, on
the acquisition or importation of fixed assets may be deductible for income tax purposes, unless it is to be treated as creditable,
or as part of the tax cost of the asset; and (d) sale of crude oil to refineries subject to VAT at a rate of 19%.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Banking tax (4x1000), to become permanent.
| | - | ------------------------------------------



| | · | Benefits for the oil and gas industry: taxpayers that increase investments in exploration of new hydrocarbon reserves, incorporation
of new recoverable reserves, and the addition of proven reserves, would have the right to a Tax Refund Certificate (CERT), which
could be used to pay taxes administered by the Colombian Tax Office or sold in the market to other taxpayers.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Chile



Regulation of the oil and gas industry



Under the Chilean Constitution, the state
is the exclusive owner of all mineral and fossil substances, including hydrocarbons, regardless of who owns the land on which the
reserves are located. The exploration and exploitation of hydrocarbons may be carried out by the state, companies owned by the
state or private entities through administrative concessions granted by the President of Chile by Supreme Decree or CEOPs executed
by the Minister of Energy. Exploitation rights granted to private companies are subject to special taxes and/or royalty payments.
The hydrocarbon exploration and exploitation industry is supervised by the Chilean Ministry of Energy.



In Chile, a participant is granted rights
to explore and exploit certain assets under a CEOP. If a participant breaches certain obligations under a CEOP, the participant
may lose the right to exploit certain areas or may be required to return all or a portion of the awarded areas to Chile with no
right of compensation. Although the government of Chile cannot unilaterally modify the rights granted in the CEOP once it is signed,
exploration and exploitation are nonetheless subject to significant government regulations, such as regulations concerning the
environment, tort liability, health and safety and labor.



Regulatory framework



Regulation of exploration and production activities



Oil and gas exploration and development
is governed by the Political Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986 of the Ministry of Mines,
which set forth the revised text of the Decree Law 1089 of 1975, on CEOPS. However, the right to explore and develop fields is
granted for each area under a CEOP between Chile and the relevant contractors. The CEOP establishes the legal framework for hydrocarbon
activities, including, among other things, minimum investment commitments, exploration and exploitation phase durations, compensation
for the private company (either in cash or in kind) and the applicable tax regime. Accordingly, all the provisions governing the
exploitation and development of our Chilean operations are contained in our CEOPs and the CEOPs constitute all the licenses that
we need in order to own, operate, import and export any of the equipment used in our business and to conduct our gas and petroleum
operations in Chile.



Under Chilean law, the surface landowners
have no property rights over the minerals found under the surface of their land. Subsurface rights do not generate any surface
rights, except the right to impose legal easements or rights of way. Easements or rights of way can be individually negotiated
with individual surface land owners or can be granted without the consent of the landowner through judicial process. Pursuant to
the Chilean Code of Mines, a judge can permit a party to use an easement pending final adjudication and settlement of compensation
for the affected landowner.



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Taxation



With regard to indirect taxes on hydrocarbon
exploitation, the general rule is that hydrocarbons are transferred to the contractor (its retribution under the CEOP), and those
re-acquisitions from the contractor performed by Chile or its enterprises, as well as their corresponding acts, contracts and documents,
are tax exempt. In addition, hydrocarbon exports by the contractor are also tax exempt. With regard to income taxes, as provided
by article 5 of Decree Law No. 1,089, the contractor is subject either to a single tax calculated on its retribution,
equal to 50% of such retribution, or to the general income tax regime established in the Income Tax Law (Decree Law No. 824
of 1974), in force at the time of the execution of the public deed which contains CEOPs, terms of which will be applicable and
invariable throughout the duration of the contract. Income in Chile is subject to corporate tax on an accrual basis and has a current
rate of 24% for fiscal year 2016. The applicable and invariable corporate income tax rates of our CEOPs range between 15% and 18.5%,
as follows: the Fell Block is subject to a rate of 15%, the Otway and Tranquilo Blocks are subject to a rate of 17% and the Flamenco,
Isla Norte and Campanario Blocks are subject to a rate of 18.5% for the income accrued or received during 2012 and 17% for the
income accrued or received during 2013 and onward. Dividends or profits distributed to the foreign shareholders of the contractors
are subject to 35% Additional Withholding Tax with a tax credit for the corporate income tax paid by the contractor. With regard
to the value added tax, contractors may obtain as a refund the value added tax (which is 19% according to the Sales and Services
Tax Law contained in Decree Law No. 825 of 1974) supported or paid on the import or purchase of goods or services used in
connection with the exploration and exploitation activities. The applicable tax regime for each CEOP remains unchanged throughout
the duration of the CEOP.
The Chilean Congress approved a reform to the income tax law in September 2014 which was amended in February 2016.  Under
this reform the income tax rate will increase 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 we control in Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes
Limitada, are not affected by the income tax reform mentioned since they are covered by the tax treatment established in the CEOPs.
The above has been confirmed by the Chilean IRS through ruling N°2478/2016.



Brazil



Regulation of the oil and gas industry



Article 177 of the Brazilian Federal
Constitution of 1988 provides for the Federal Government’s monopoly over the prospecting and exploration of oil, natural
gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline
transportation of crude oil and natural gas. Initially, paragraph one of article 177 barred the assignment or concession of
any kind of involvement in the exploration of oil or natural gas deposits to private industry. On November 9, 1995, however,
Constitutional Amendment Number 9 altered paragraph one of article 177 so as to allow private or state-owned companies
to engage in the exploration and production of oil and natural gas, subject to the conditions to be set forth by legislation.



Regulatory framework



Pricing policy



Until the enactment of the Brazilian Petroleum
Law, the Brazilian government regulated all aspects of the pricing of oil and oil products in Brazil, from the cost of oil imported
for use in refineries to the price of refined oil products charged to the consumer. Under the rules adopted following the Brazilian
Petroleum Law, the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government:
(1) introduced a new methodology for determining the price of oil products designed to track prevailing international prices
denominated in U.S. dollars, and (2) gradually eliminated controls on wholesale prices.



Concessions



In addition to opening the Brazilian oil
and natural gas industry to private investment, the Brazilian Petroleum Law created new institutions, including the ANP, to regulate
and control activities in the sector. As part of this mandate, the ANP is responsible for licensing concession rights for the exploration,
development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding
process. The ANP has conducted 13 bidding rounds for exploration concessions since 1999. Our PN-T-597 is still subject to the entry
into the concession agreement. See “—Our operations—Operations in Brazil” and “Item 3. Key information—D.
Risk factors—Risks relating to our business—The PN-T-597 concession is subject to an injunction and may not close”
for more information.



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Taxation



The Brazilian Petroleum Law introduced
significant modifications and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation
is the government take, comprised of license fees, fees payable in connection with the occupation or title of areas, royalties
and a special participation fee. The introduction of the Brazilian Petroleum Law presents certain tax benefits primarily with respect
to indirect taxes. Such indirect taxes are very complex and can add significantly to project costs. Direct taxes are mainly corporate
income tax and social contribution on net profit.

Government take.



With the effectiveness of the Brazilian Petroleum
Law and the regulations promulgated by the ANP, concessionaires are required to pay the Brazilian federal government the following:



| | · | license fees;
| | - | -------------



| | · | rent for the occupation or retention of areas;
| | - | ----------------------------------------------



| | · | special participation fee; and
| | - | ------------------------------



| | · | royalties on production.
| | - | ------------------------



The minimum value of the license fees is
established in the bidding rules for the concessions, and the amount is based on the assessment of the potential, as conducted
by the ANP. The license fees must be paid upon the execution of the concession contract. Additionally, concessionaires are required
to pay a rental fee to landowners varying from 0.5% to 1.0% of the respective hydrocarbon production.



The special participation fee is an extraordinary
charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according
to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date on which extraordinary
production occurs. This participation rate, whenever due, may reach up to 40% of net revenues depending on (i) volume of production
and (ii) whether the block is onshore, shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations
issued by the ANP, the special participation fee is calculated based upon quarterly net revenues of each field, which consist of
gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate for
the period) less: royalties paid; investment in exploration; operational costs; and depreciation adjustments and applicable taxes.



The 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.



Relevant Tax Aspects on Upstream Activities.
The special customs regime for goods to be used in the oil and gas activities in Brazil, REPETRO, aims primarily at reducing the
tax burden on companies involved in exploring and extracting oil and natural gas, through the total suspension of federal taxes
due on the importation of equipment (platforms, subsea equipment, among others), under leasing agreements, subject to the compliance
with applicable legal requirements. The period in which the goods are allowed to remain in Brazil under the REPETRO regime may
vary depending on the importer, but usually corresponds to the duration of the contract executed between the Brazilian company
and the foreign entity, or the period for which the company was authorized to exploit or produce oil and gas.



In 2007, the legislation regarding the
State Value Added Tax—ICMS imposed taxation on the import of equipment into Brazil under the REPETRO regime was significantly
changed by ICMS Convention No. 130/2007. This regulation allows each State to grant the ICMS tax calculation basis reduction (generating
a tax burden of 7.5% with the recoverability of credits or 3%, without the recoverability of credits) for goods purchased under
the REPETRO regime for the production phase and the total exemption or ICMS tax calculation basis reduction (generating a tax burden
of 1.5%, without the recoverability of credits) for the exploration phase. In order to be in force, the ICMS Convention No. 130/07
must be included in each state’s legislation.



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For example, currently, based on Convention
No. 130/2007, the state of Rio de Janeiro grants tax calculation basis reduction for the exploitation (generating a tax burden
of 7.5%, with the recoverability of credits or 3%, without the recoverability of credits) and production of oil and gas (generating
a tax burden of 1.5%, without the recoverability of credits). For production activities, the legislation previously granted an
exemption of ICMS, which was changed to a tax calculation basis reduction, according to Resolution Sefaz No. 631, dated May 14,
2013. Taxpayers, however, have challenged this change and received favorable decisions in court in order to avoid collecting ICMS
on REPETRO imports as, according to STF (Supreme Court of Justice), the temporary imports on REPETRO do not constitute an ICMS
triggering event.



It is important to mention that before
the enactment of the Convention No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on production activities,
based on State Law No. 4,117, dated June, 27, 2003, which was regulated by Decree No. 34,761, dated February 3, 2004, and was subsequently
suspended by Decree No. 34,783 of February 4, 2004 for an undetermined period of time. This legislation has been revoked in 2015
when Rio de Janeiro State created Law No. 7,183/2015 aiming to collect ICMS on the extraction of oil and Law No. 7,182/2015 creating
a new fee per barrel of oil produced in the state. The constitutionality of these laws is currently being challenged by taxpayers.
It is important to highlight that, while such legislation applies for oil fields operated in the State of Rio de Janeiro, legislation
may vary in other states.



Pursuant to the Brazilian Petroleum Law
and subsequent legislation, the federal government enacted Law No. 10,336/01, to impose the Contribution for Intervention in the
Economic Sector, or CIDE, an excise tax payable by producers, blenders and importers on transactions with some oil and fuel products,
which is imposed at a flat rate based on the specific quantities of each product. Currently, the CIDE rates are zero, based on
Decree No. 7,764/2012.



Brazil has enacted a corporate tax reform,
Law 12.973 of 13 May 2014. On upstream operations, as from 2015 fiscal year, the new tax law may generate timing effects for income
tax purposes on the deduction of pre-operational costs as well as depreciation of fixed assets and amortization of intangibles.
The new law imposes restrictions for the tax deduction of goodwill arising from in-house operations, and brings several changes
to the Brazilian CFC rules.



Peru



Regulation of the oil and gas industry



The hydrocarbons activities in Peru are
mainly regulated by the General Hydrocarbons Law (Law 26,221), and several regulations enacted in order to develop the provisions
included in such law.



According to the Hydrocarbons Law, oil
and gas exploration and production activities are carried out under license or service contracts granted by the government. Under
a license contract, the investor pays a royalty, whereas under a service contract, the government pays remuneration to the contractor.
As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons, a license contract does not imply a transfer or lease
of property over the area of exploration or exploitation. By virtue of the license contract, the contractor acquires the authorization
to explore or to exploit hydrocarbons in a determined area, and Perupetro (the entity that holds the Peruvian state interest) transfers
the property right in the extracted hydrocarbons to the contractor, who must pay a royalty to the state.



Regulatory framework



License and service contracts are approved
by a supreme decree issued by the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of Energy and Mining, and
can only be modified by a written agreement signed by the parties. Before initiating any negotiation, every oil and gas company
must be duly qualified by Perupetro, in order to determine if it fulfills all the requirements needed to develop exploration and
production activities under the contract form requirements mentioned above.



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License and services agreements may be
granted for just an exploitation stage -when a commercial discovery has been made- or for an exploration and exploitation stage
–when such discovery has not been made yet. In this case, the exploration phase will last no more than 7 years, counted from
the effective date of the contract (60 days after the signing date). This term can be divided into several periods as agreed in
the contract, and all of them with a minimum work obligation that should be fulfilled by a contractor in order to access the next
exploration period. The exploitation phase will last 40 years from the effective date of the contract in case of natural gas discoveries
and 30 years from the effective date in case of oil discoveries.



The Ministry of Energy and Mines may exceptionally
authorize an extension of three years for the exploration stage, if the contractor has fulfilled with the minimum work program
established in the contract, and also commits to fulfill an additional work program that justifies such extension. The contractor
shall be responsible for providing the technical and economic resources required for the execution of the operations of this phase.



The Peruvian regulations also established
the roles of the Peruvian government agencies that regulate, promote and supervise the oil and gas industry, including the Ministry
of Energy and Mines, Perupetro and OSINERGMIN.



Taxation



The fiscal regime that applies in Peru
to the oil and gas industry consists of a combination of corporate income tax, royalties and other levies.



In general terms, oil and gas companies
are subject to the general corporate income tax regime that is stabilized in the applicable regime on the date of subscription
of the original License Agreement (due to a tax stability contract); nevertheless, there are certain special tax provisions for
the oil and gas sector.



Resident companies (incorporated in Peru), are subject to income
tax on their worldwide taxable income. Branches and permanent establishments of foreign companies that are located in Peru and
non-resident entities are taxed on Peruvian source income only.



With respect to the Morona Agreement, in
which we take part, the applicable income tax stabilized regime is from 1995, which is the year of subscription of the original
License Agreement. The income tax rate in 1995 was 30% and there was no withholding income tax for dividends. Additionally, in
1995 it was stated that the income tax should not be lower than 2% of the net assets of the Company (the “Minimum Income
Tax”). The Minimum Income Tax was later declared unconstitutional, which is why, even when there was a tax stability contract,
the Minimum Income Tax has been understood as not applicable or enforceable.



Taxable income is generally computed by
reducing gross revenue by cost of goods sold and all expenses necessary to produce the income or maintain the source of income.
Certain types of revenue, however, must be computed as specified in the tax law and some expenses are not fully deductible for
tax purposes. Business transactions must be recorded in legally authorized accounting records that are in full compliance with
the International Accounting Standards (IAS). Contractors in a license or services contract for the exploration or exploitation
of hydrocarbons (Peruvian corporations and branches) are entitled to keep their accounting records in foreign currency, but taxes
must be paid in Peruvian Nuevos Soles (“PEN”).



Any investments in a contract area that
did not reach the commercial extraction stage and that were totally released, can be accumulated with the same type of investments
made in another contract area that has reached the stage of commercial extraction.



These investments are amortized in accordance
with the amortization method chosen in the letter contract. If the contractor has entered into a single contract, the accumulated
investments are charged as a loss against the results of the contract for the year of total release of the area for any contract
that did not reach the commercial extraction stage, with the exception of investments consisting of buildings, power installations,
camps, means of communication, equipment and other goods that the contractor keeps or recovers to use in the same operations or
in other operations of a different nature.



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The contractor determines the tax base and
the amount of the tax, separately and for each contract. If the contractor carries out related activities (i.e., activities related
to oil and gas, but not carried out under the terms of the contract) or other activities (i.e., activities not related to oil and
gas), the contractor is obligated to determine the tax base and the amount of tax, separately, and for each activity. The corresponding
tax is determined based on the income tax provisions that apply in each case (subject to the tax stability provisions for contract
activities and based on the regular regime for the related activities or other activities). The total income tax amount that the
contractor must pay is the sum of the amounts calculated for each contract, for both the related activities and for the other activities.
The forms to be used for tax statements and payments are determined by the tax administration. If the contractor has more than
one contract, it may offset the tax losses generated by one or more contracts against the profits resulting from other contracts
or related activities. Moreover, the tax losses resulting from related activities may be offset against the profits from one or
more contracts.



It is possible to choose the allocation
of tax losses to one or more of the contracts or related activities that have generated the profits, provided that the losses are
depleted or compensated to the limit of the profits available. This means that if there is another contract or related activity,
the taxpayer can continue compensating tax losses until they are completely offset. A contractor with tax losses from one or more
contracts or related activities may not offset them against profits generated by the other activities. Furthermore, in no case
may tax losses generated by the other activities be offset against the profits resulting from the contracts or the related activities.



During the exploration phase, operators are exempt from import
duties and other forms of taxation applicable to goods intended for exploration activities. Exemptions are withdrawn at the production
phase, but exceptions are made in certain instances, and the operator may be entitled to temporarily import goods tax-free for
a two-year period (“Temporary Import”). A temporary Import may be extended for additional one year periods for up to
two times upon the request of an operator, approval of the Ministry of Energy and Mines and authorization of the Superintendencia
Nacional de Aduanas y de Administracion Tributaria (Peruvian Customs Agency).



Environmental Regulation



Before initiating any hydrocarbon activity
(e.g. seismic exploration, drilling of exploration wells, etc.) the contractor must file and obtain an approval for an Environmental
Impact Study (EIS), which is the most important permit related to HSE for any hydrocarbon project. This study includes technical,
environmental and social evaluations of the project to be executed in order to define the activities that should be required for
preventing, minimizing, mitigating and remediation of the possible negative environmental and social impacts that the hydrocarbon
project may generate.



There are general environmental regulations
for the protection of water, soils, air, endangered species, biodiversity, natural protected areas, etc. In addition, there are
specific environmental regulations applicable to the hydrocarbon industry.



Argentina



Regulatory framework



From the 1920s to 1989, the Argentine public
sector dominated the upstream segment of the Argentine oil and gas industry and the midstream and downstream segment of the business.



In 1989, Argentina enacted certain laws
aimed at privatizing the majority of its state-owned companies and issued a series of presidential decrees (namely, Decrees No.
1055/89, 1212/89 and 1589/89 (“Oil Deregulation Decrees”), relating specifically to deregulation of energy activities).
The Oil Deregulation Decrees eliminated restrictions on imports and exports of crude oil, deregulated the domestic oil industry,
and effective January 1, 1991, the prices of oil and petroleum products were also deregulated. In 1992, Law No. 24,145, referred
to as the Privatization Law, privatized YPF and provided for transfer of hydrocarbon reservoirs from the Argentine government to
the provinces, subject to the existing rights of the holders of exploration permits and production concessions.



In October 2004, the Argentine Congress
enacted Law No. 25,943, creating a new state-owned energy company, Energía Argentina S.A. (“ENARSA”).
The corporate purpose of ENARSA is the exploration and exploitation of solid, liquid and gaseous hydrocarbons; the transport, storage,
distribution, commercialization and industrialization of these products; as well as the transportation and distribution of natural
gas, and the generation, transportation, distribution and sale of electricity. Moreover, Law No. 25,943 granted ENARSA all
offshore areas located beyond 12 nautical miles from the coastline up to the outer boundary of the continental shelf that were
vacant at the time of the effectiveness of this law (i.e. November 3, 2004).



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On May 3, 2012, the Argentine Congress
passed the Hydrocarbons Sovereignty Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, as well as
in the exploitation, industrialization, transportation and sale of hydrocarbons, a national public interest and a priority for
Argentina. In addition, the law expropriated 51% of the share capital of YPF, the largest Argentine oil company, from Repsol, the
largest Spanish oil company.



On July 28, 2012, Presidential Decree 1277/2012,
which regulated the Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and Coordination Committee for the
National Hydrocarbon Investment Plan and vesting it with the power to set the sector’s reference prices and to develop investment
plans for the country to increase production and reserves. The decree introduced important changes to the rules governing Argentina’s
oil and gas industry, including the repeal of certain articles of Deregulation Decrees passed during 1989 relating to free marketability
of hydrocarbons at negotiated prices, the deregulation of the oil and gas industry, freedom to import and export hydrocarbons and
the ability to keep proceeds from export sales in foreign bank accounts.



On January 4, 2016, immediately after the
new national administration took office, Presidential Decree 272/2015 was released. This Decree abrogated the provisions of the
Presidential Decree 1277/2012 which had repealed the Deregulation Decrees. Thus, the Deregulation Decrees were reinstated.



Other measures have also been taken by
the new presidential administration aimed at reducing government intervention and reestablishing market forces in the oil &
gas industry.



Domain and Jurisdiction of hydrocarbons
resources



After a constitutional reform enacted in
1994, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested in such provincial state,
while eminent domain over hydrocarbon resources lying offshore on the continental platform beyond the jurisdiction of the coastal
provincial states is vested in the federal state



Thus, oil and gas exploration permits and
exploitation concessions are now granted by each provincial government. A majority of the existing concessions were granted by
the federal government prior to the enactment of Law No.26,197 and were thereafter transferred to the provincial states.



Regulation of exploration and production activities



New Hydrocarbon Act:



In October 31, 2014 the Argentine Republic
Official Gazette published the text of Law No. 27,007, amending the Hydrocarbon Law No. 17,319.



The most relevant aspects of the new law
are as follows:



| | · | With regards to concessions, three types of concessions are provided, namely, conventional exploitation, unconventional exploitation,
and exploitation in the continental shelf and territorial waters, establishing the respective terms for each type.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | The terms for hydrocarbon transportation concessions were adjusted in order to comply with the exploitation concessions terms.
| | - | ------------------------------------------------------------------------------------------------------------------------------



| | · | With regards to royalties, a maximum of 12% is established, which may reach 18% in the case of granted extensions, where the
law also establishes the payment of an extension bond for a maximum amount equal to the amount resulting from multiplying the remaining
proven reserves at the end of effective term of the concession by 2% of the average basin price applicable to the respective hydrocarbons
over the 2 years preceding the time on which the extension was granted.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | The extension of the Investment Promotion Regime for the Exploitation of Hydrocarbons (Decree No. 929/2013) is established
for projects representing a direct investment in foreign currency of at least 250 million dollars, increasing the benefits for
other type of projects.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Regulation of transportation activities



Exploitation concessionaires have the exclusive
right to obtain a transportation concession for the transport of oil and gas from the provincial states or the federal government,
depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other fixed facilities
necessary for the transportation of oil, gas and by-products. Transportation facilities with surplus capacity must transport third
parties’ hydrocarbons on an open-access basis, for a fee which is the same for all users on similar terms. As a result of
the privatizations of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered and continue to
operate to date.



Taxation



Exploitation concessionaires are subject
to the general federal and provincial tax regime. The most relevant federal taxes are the income tax (35%), the value added tax
(21%) and a tax on assets. The most relevant provincial taxes are the turnover tax (1% to 3%) and stamp tax. In 2002, in response
to the economic crisis, the federal government adopted new taxes on oil and gas products, including export taxes ranging from 5%
for by-products to 45% for crude oil. Such export taxes lapsed and terminated on January 6, 2016 on the 15th anniversary of their
enactment.



| | C. | Organizational structure
| | -- | ------------------------



We are an exempted company incorporated
pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an
illustration of our corporate structure in Note 20 (“Subsidiary undertakings”) to our Consolidated Financial Statements.



| | D. | Property, plant and equipment
| | -- | -----------------------------



See “—B. Business Overview—Title
to properties.”



ITEM 4A. UNRESOLVED STAFF COMMENTS



Not applicable.



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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS



| | A. | Operating results
| | -- | -----------------



The following discussion of our financial
condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto
as well as the information presented under “Item 3. Key Information— A. Selected financial data.”



The following discussion contains forward-looking
statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking
statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors”
and “Forward-looking statements.”



Factors affecting our results of operations



We describe below the year-to-year comparisons
of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical
results due to a variety of factors, including the following:



Discovery and exploitation of reserves



Our results of operations depend on our
level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While
we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance
that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural
gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future
exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is
no certainty that the discoveries will be commercially viable to produce.



For the year ended December 31, 2016, we
made total capital expenditures of US$39.3 million (US$26.2 million, US$7.8 million, US$1.7 million and US$3.6 million in Colombia,
Chile, Argentina and Brazil, respectively) for the year 2016, consisting of US$18.2 million related to exploration.



Oil prices were volatile since the end
of 2014. In preparation for continued volatility, we have developed multiple scenarios for our 2017 capital expenditure program.
See “Item 4. Information on the Company –B. Business Overview—2017 Strategy and Outlook.”



Funding for our capital expenditures relies
in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low
oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as
the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current
operations and the amount of cash we can obtain from prepayment agreements such as the Trafigura Agreement, which is our offtake
and prepayment agreement. If we are not able to generate the sales which, together with our current cash resources, are sufficient
to fund our capital program, we will not be able to efficiently execute our work program which would cause us to further decrease
our work program, which could harm our business outlook, investor confidence and our share price.



If oil prices average higher than the base
budget price, we have the ability to allocate additional capital to more projects and increase its work and investment program
and thereby further increase oil and gas production.



Our results of operations will be adversely
affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually
be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to
exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that
contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business,
results of operations and financial condition.



Oil and gas revenue and international
prices



Our revenues are derived from the sale
of our oil and natural gas production, as well as of condensate derived from the production of natural gas. Our oil and natural
gas prices are driven by the international prices of oil and methanol (for our Chilean gas production), respectively, which are
denominated in US$. The price realized for the oil we produce is generally linked to WTI, Brent or Vasconia. The price realized
for the natural gas we produce in Chile is linked to the international price of methanol, which is settled in the international
markets in US$. 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.



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From January 1, 2011 to December 31, 2016,
Brent spot prices ranged from a low of US$30.7 per barrel to a high of US$125.5 per barrel, NYMEX West Texas International (“WTI”)
crude oil contracts prices ranged from a low of US$30.3 per bbl to a high of US$109.5 per bbl, Henry Hub natural gas average spot
prices ranged from a low of US$1.7 per mmbtu to a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low
of US$250 per metric ton to a high of US$635 per metric ton. Furthermore, oil, natural gas and methanol prices do not necessarily
fluctuate in direct relationship to each other.



As a consequence of the oil price crisis
which started in the second half of 2014 (WTI and Brent, the main international oil price markers, fell more than 60% between August
2014 and March 2016), we took decisive steps in 2015 and 2016 to adapt to the new oil price environment. We reduced our capital
expenditure program from US$238 million in 2014 to US$48 million in 2015 and US$39 million in 2016 and implemented significant
cost reduction initiatives that resulted in production and operating costs being reduced by 49% (2016 versus 2014), and administrative
expenses being reduced by 26% (2016 versus 2014), while increasing average production to approximately 22.4 mboepd and increasing
our proved reserves to 73.6 mmboe.



In October 2016, we decided to manage part
of our exposure to the volatile crude oil price using derivatives. For further information related to Commodity Risk Management
Contracts, please see Note 36 to our Consolidated Financial Statements.



Additionally, the oil and gas we sell may
be subject to certain discounts. For example, in Colombia, the price of oil we sell 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, sulfur,
delivery point and water content, as well as on certain transportation costs (including pipeline costs and trucking costs). The
delivery points for our production range from the well head to the port of export (Coveñas).



In Chile, the price of oil we sell to ENAP
is based on Brent minus certain marketing and quality discounts. We have a long-term gas supply contract with Methanex. 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. See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—A substantial or extended decline in oil, natural gas and methanol prices
may materially adversely affect our business, financial condition or results of operations.” As of the date of this annual
report, we had not entered into any derivative arrangements or contracts to mitigate the impact on our results of operations of
fluctuations in commodity prices.



If the market prices of oil and methanol
had fallen by 10% as compared to actual prices during the year, with all other variables held constant, after-tax loss for the
year ended December 31, 2016 would have been higher by US$23.7 million (US$23.9 million in 2015).



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 reais and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Índice Geral
de Preços—Mercado) (“IGPM”). See Note 3 to our Consolidated Financial Statements.



Production and operating costs



Our production and operating costs consist
primarily of expenses associated with the production of oil and gas, the most significant of which are gas plant leasing, facilities
and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and
products, among others. As commodity prices increase or decrease, our production costs may vary. We have historically not hedged
our costs to protect against fluctuations.



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Availability and reliability of infrastructure



Our business depends on the availability
and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment
and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business,
and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks
relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access
to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.”



In order to mitigate the risk of unavailability
of operating and transportation infrastructure, we have invested in the construction of plant and pipeline infrastructure to produce,
process and store hydrocarbon reserves and to transport them to market.



Production levels



Our oil and gas production levels are heavily
influenced by our drilling results, our acquisitions and to oil and natural gas prices.



We expect that fluctuations in our financial
condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir
pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D.
Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production
will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects
and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.”



Contractual obligations



In order to protect our exploration and
production rights in our license areas, we must make and declare discoveries within certain time periods specified in our various
special contracts, E&P Contracts and concession agreements. The costs to maintain or operate our license areas may fluctuate
or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms
or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in
securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk
factors—Risks relating to our business—Under the terms of some of our various CEOPs, E&P Contracts and concession
agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order to retain our rights and
establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts
of our blocks or concession areas.”



Administrative expenses



Our administrative expenses for the year
ended December 31, 2016 decreased by US$3.3 million, or (9)%, compared to the year ended December 31, 2015 resulting from financial
discipline and cost reduction initiatives. However, administrative costs may increase as a result of our Peruvian operations, other
acquisitions, increased activity or the impact of appreciation of local currencies in the countries where we operate.



Acquisitions



Our results of operations are significantly
affected by our past acquisitions. We generally incorporate our acquired business into our results of operations at or around the
date of closing, such as our Colombian acquisitions in 2012 and our Rio das Contas acquisition in 2014, which limits the comparability
of the period including such acquisitions with prior or future periods.



As described above, part of our strategy
is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties
and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results
of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future
acquisitions.



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Functional and presentational currency



Our Consolidated Financial Statements are
presented in US$, which is our functional and presentational currency. Items included in the financial information of each of our
entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency,
which is the US$ in each case, except for our Brazil operations, where the functional currency is the real.



Geographical segment reporting



In the description of our results of operations
that follow, our “Other” operations reflect our non-Colombian, non-Chilean and non-Brazilian operations, primarily
consisting of our Argentine, Peruvian (mainly related to the start-up of our operations in such country) and corporate head office
operations.



We divide our business into five geographical
segments—Colombia, Chile, Brazil, Peru and Argentina—that correspond to our principal jurisdictions of operation. Activities
not falling into these four geographical segments are reported under a separate corporate segment that primarily includes certain
corporate administrative costs not attributable to another segment.



Description of principal line items



The following is a brief description of
the principal line items of our statement of income.



Revenue



Revenue includes the sale of crude oil,
condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury
adjustments) 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. Revenue is recognized when the significant risks and rewards of ownership have been
transferred to the buyer, the associated costs and amount of revenue can be estimated reliably, recovery of the consideration is
probable, and there is no continuing management involvement with the goods.



Commodity risk management contracts



Includes realized and unrealized gains
and losses arising from commodity risk management contracts.



Production and operating costs



For a description of our production and
operating costs, see “—Factors affecting our results of operations.”



Depreciation and write-off of unsuccessful
efforts



Capitalized costs of proved oil and natural
gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial
proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society
of Petroleum Engineers and the World Petroleum Council (“PRMS”), which differs from SEC reporting guidelines pursuant
to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production”
depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized
prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.



In particular, upon completion of the evaluation
phase, a prospect is either transferred to oil and gas properties if it contains reserves, or is charged to profit and loss in
the period in which the determination is made. See “—Critical accounting policies and estimates—Oil and gas accounting.”



Geological and geophysical expenses



Geological and geophysical expenses consist
of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy
costs and costs relating to independent reservoir engineer studies.



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Administrative expenses



Administrative costs consist of corporate
costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages
and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions.



Selling expenses



Selling expenses consist primarily of transportation
and storage costs.



Impairment of non-financial assets



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



An impairment loss is recognized for the
amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s
fair value minus costs to sell and value in use.



During 2016, we recognized a reversal of
impairment losses amounting to US$5.7 million, while in 2015 and 2014 we recognized impairment losses amounting to US$149.6 million
and US$9.4 million. See Note 35 to our Consolidated Financial Statements.



Financial costs



Financial costs consist of financial income
offset by financial expenses. Financial income includes interest received from bank time deposits. Financial expenses principally
include interest expense not subject to capitalization, bank charges and the unwinding of long-term liabilities.



Foreign exchange gain or loss



Foreign exchange gain or loss represents
the effect of exchange rate differences.



Loss or profit for the period attributable
to owners of the Company



Loss or profit for the period attributable
to owners of the Company consists of losses or profit for the year less non-controlling interest.



Critical accounting policies and estimates



We prepare our Consolidated Financial Statements
in accordance with IFRS and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as adopted by the
IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported
amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually
evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various
other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral component
of the financial reporting process, actual results could differ from those estimates.



An accounting policy is considered critical
if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time such
estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the accounting estimates
that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following
accounting policies represent critical accounting policies as they involve a higher degree of judgment and complexity in their
application and require us to make significant accounting estimates. The following descriptions of critical accounting policies
and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes and other disclosures.



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Business combinations



Business combinations are accounted for
using the acquisition method. The cost of an acquisition is measured as the fair market value of the assets acquired, equity instruments
issued and liabilities incurred or assumed on the date of completion of the acquisition. Acquisition costs incurred are expensed
and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair market values at the acquisition date. The excess of the cost of acquisitions
over fair market value of a company’s share of the identifiable net assets acquired is recorded as goodwill. If the cost
of the acquisition is less than a company’s share of the net assets required, the difference is recognized directly in the
statement of income.



The determination of fair value of identifiable
acquired assets and assumed liabilities means that we are to make estimates and use valuation techniques, including independent
appraisers. The valuation assumptions underlying each of these valuation methods are based on available updated information, including
discount rates, estimated cash flows, market risk rates and other data. As a result, the process of identification and the related
determination of fair values require complex judgments and significant estimates.



Cash flow estimates for impairment assessments



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 natural gas prices have exhibited significant volatility. Our forecasts
for oil and natural gas revenues are based on prices derived from future price forecasts among industry analysts, as well as our
own assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development
costs.



The process of estimating reserves requires
significant judgments 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 D&M Reserves
Report. Such estimates incorporate many factors and assumptions including:



| | · | expected reservoir characteristics based on geological, geophysical and engineering assessments;
| | - | ------------------------------------------------------------------------------------------------



| | · | future production rates based on historical performance and expected future operating and investment activities;
| | - | ----------------------------------------------------------------------------------------------------------------



| | · | future oil and natural gas prices and quality differentials;
| | - | ------------------------------------------------------------



| | · | anticipated effects of regulation by governmental agencies; and
| | - | ---------------------------------------------------------------



| | · | future development and operating costs.
| | - | ---------------------------------------



Our management believes these factors and
assumptions are reasonable based on the information available at the time we prepare our 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 natural gas prices and costs change.



For further information related to impairment
of property, plant and equipment, please see Note 35 to our Consolidated Financial Statements.



Oil and gas accounting



Oil and gas exploration and production
activities are accounted for in accordance with the successful efforts method on a field by field basis. We account 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 income statement.



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Exploration and evaluation costs may include:
license acquisition, geological and geophysical studies (i.e., seismic), direct labor costs and drilling costs of exploratory wells.
No depreciation and/or amortization are charged during the exploration and evaluation phase. Upon completion of the evaluation
phase, the prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination
is made, depending whether they have found reserves. 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. All field development
costs are considered construction in progress until they are finished and capitalized within oil and gas properties, and are subject
to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling
costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition
costs of rights and concessions related to proved properties.



Workovers of wells made to develop reserves
and/or increase production are capitalized as development costs. Maintenance costs are charged to income when incurred.



Capitalized costs of proved oil and gas
properties and production facilities and machinery are depreciated on a licensed area by 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 un-escalated price levels.
Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of
approximate relative energy content.



Oil and gas reserves for purposes of our
Consolidated Financial Statements are determined in accordance with PRMS, and were estimated by DeGolyer and MacNaughton, independent
reserves engineers.



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 three and 10 years.



Asset retirement obligations



Obligations related to the plugging and
abandonment of wells once operations are terminated may result in the recognition of significant liabilities. We record the fair
value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially
recognized, the cost is also capitalized by increasing the carrying amount of the related asset. Over time, the liability is accreted
to its present value at each reporting date, and the capitalized cost is depreciated over the estimated useful life of the related
asset. Estimating the future abandonment costs is difficult and requires management to make assumptions and judgments because most
of the obligations will be settled after many years. Technologies and costs are constantly changing, as are political, environmental,
health, safety and public relations considerations. Consequently, the timing and future cost of dismantling and abandonment are
subject to significant modification. Any change in the variables underlying our assumptions and estimates can have a significant
effect on the liability and the related capitalized asset and future charges related to the retirement obligations. The present
value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated
future expenditure. The liability recognized is based upon estimated future abandonment costs, wells subject to abandonment, time
to abandonment, and future inflation rates.



Share-based payments



We provide several equity-settled, share-based
compensation plans to certain employees and third-party contractors, composed of payments in the form of share awards and stock
options plans.



Fair value of the stock option plans for
employee or contractor services received in exchange for the grant of the options is recognized as an expense. The total amount
to be expensed over the vesting period, which is the period over which all specified vesting conditions are to be satisfied, is
determined by reference to the fair value of the options granted calculated using the Geometric Brownian Motion method. Determining
the total value of our share-based payments requires the use of highly subjective assumptions, including the expected life of the
stock options, estimated forfeitures and the price volatility of the underlying shares. The assumptions used in calculating the
fair value of share-based payment represent management’s best estimates, but these estimates involve inherent uncertainties
and the application of management’s judgment.



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Non-market vesting conditions are included
in assumptions in respect of the number of options that are expected to vest. At each balance sheet date, we revise our estimates
of the number of options that are expected to vest. We recognize the impact of the revision to original estimates, if any, in the
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 recognized as an expense over the vesting period.



When options are exercised, we issue new
common 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.



Taxation



The computation of our income tax expense
involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken
by us, 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.



In addition, we have 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.



Contingencies



From time to time, we may be subject to
various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental
and health & safety matters. For example, from time to time, the Company receives notices of environmental, health and safety
violations. Based on what our Management currently knows, such claims are not expected to have a material impact on the financial
statements.



Recent accounting pronouncements



See Note 2.1.1 to our Consolidated Financial
Statements.



Results of operations



The following discussion is of certain
financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial
Statements and the accompanying notes.



We closed the acquisition of Brazilian
Rio das Contas on March 31, 2014 and began consolidating its financials beginning on March 31, 2014. Accordingly, our results of
operations for the year ended December 31, 2014, are not fully comparable with prior periods. See Note 34 to our Consolidated Financial
Statements.



As a consequence of the oil price crisis
which started in the second half of 2014 (WTI and Brent, the main international oil price markers, fell more than 60% between August
2014 and March 2016), we have undertaken decisive measures to ensure our ability to both maximize the work program and preserve
our cash.



During 2015 and 2016, we took decisive
steps to adapt to the new oil price environment. We reduced our capital expenditure program from US$238 million in 2014 to US$48
million in 2015 and US$39 million in 2016 and implemented significant cost reduction initiatives that resulted in production and
operating costs being reduced by 49% (2016 versus 2014), and administrative expenses being reduced by 26% (2016 versus 2014),
while increasing average production to approximately 22.4 mboepd and increasing our proved reserves to 73.6 mmboe.



In preparation
for continued volatility, we have developed multiple scenarios for our 2017 capital expenditure program. See “Item 4. Information
on the Company –B. Business Overview—2017 Strategy and Outlook.”



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Year ended December 31, 2016 compared
to year ended December 31, 2015



The following table summarizes certain
of our financial and operating data for the years ended December 31, 2016 and 2015.



|                                                               |  | For the year ended December 31,              
|-------------------------------------------------------------- |  | ---------------------------------------------
|                                                               |  | 2016                                         
|                                                               |  | (in thousands of US$, except for percentages)
|Revenue                                                        |  |                                              
|Net oil sales                                                  |  |                                              
|Net gas sales                                                  |  |                                              
|Revenue                                                        |  |                                              
|Commodity risk management contracts                            |  |                                              
|Geological and geophysical expenses                            |  |                                              
|Administrative expenses                                        |  |                                              
|Selling expenses                                               |  |                                              
|Depreciation                                                   |  |                                              
|Write-off of unsuccessful efforts                              |  |                                              
|Impairment loss reversed (recognized) for non-financial assets |  |                                              
|Other operating expense                                        |  |                                              
|Operating loss                                                 |  |                                              
|Financial costs                                                |  |                                              
|Foreign exchange gain (loss)                                   |  |                                              
|Loss before income tax                                         |  |                                              
|Income tax (expense) benefit                                   |  |                                              
|Loss for the year                                              |  |                                              
|Non-controlling interest                                       |  |                                              
|Loss for the year attributable to owners of the Company        |  |                                              
|Net production volumes                                         |  |                                              
|Oil (mbbl)                                                     |  |                                              
|Gas (mcf)                                                      |  |                                              
|Total net production (mboe)                                    |  |                                              
|Average net production (boepd)                                 |  |                                              
|Average realized sales price                                   |  |                                              
|Oil (US$ per bbl)                                              |  |                                              
|Gas (US$ per mmcf)                                             |  |                                              
|Average unit costs per boe (US$)                               |  |                                              
|Operating cost                                                 |  |                                              
|Royalties and other                                            |  |                                              
|Production costs(1)                                            |  |                                              
|Geological and geophysical expenses                            |  |                                              
|Administrative expenses                                        |  |                                              
|Selling expenses                                               |  |                                              




| | (1) | Calculated pursuant to FASB ASC 932.
| | --- | ------------------------------------



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The following table summarizes certain
financial and operating data.



|                         |  | For the year ended December 31,
|------------------------ |  | -------------------------------
|                         |  | 2016                           
|                         |  | Chile                          
|                         |  | (in thousands of US$)          
|Revenue                  |  |                                
|Depreciation             |  |                                
|Impairment and write-off |  |                                
|                         |  |                                

Revenue



For the year ended December 31, 2016, crude
oil sales were our principal source of revenue, with 75% and 25% of our total revenue from crude oil and gas sales, respectively.
The following chart shows the change in oil and natural gas sales from the year ended December 31, 2015 to the year ended December
31, 2016.



|                  |  | For the year ended December 31,
|----------------- |  | -------------------------------
|                  |  | 2016                           
|Consolidated      |  | (in thousands of US$)          
|Sale of crude oil |  |                                
|Sale of gas       |  |                                
|Total             |  |                                



|           |  | Year ended December 31,                       |         | Change from prior year
|---------- |  | --------------------------------------------- | ------- | ----------------------
|           |  | 2016                                          |         | 2015                  
|           |  | (in thousands of US$, except for percentages)
|By country |  |                                              
|Colombia   |  |                                               | 126,228 |                       
|Chile      |  |                                               | 36,723  |                       
|Brazil     |  |                                               | 29,719  |                       
|Other      |  |                                               | -       |                       
|Total      |  |                                               | 192,670 |                       



Revenue decreased 8%, from US$209.7 million
for the year ended December 31, 2015 to US$192.7 million for the year ended December 31, 2016, primarily as a result of lower prices.
Sales of crude oil increased to 5.9 mmbbl in the year ended December 31, 2016 compared to 5.3 mmbbl in the year ended December
31, 2015, and resulted in net revenue of US$145.2 million for the year ended December 31, 2016 compared to US$162.6 for the year
ended December 31, 2015. In addition, sales of gas increased from US$47.1 million for the year ended December 31, 2015 to US$47.5
million for the year ended December 31, 2016 due to higher production.



The decrease in 2016 net revenue of US$17.0
million is mainly explained by:



| | · | a decrease of US$5.7 million in oil sales in Colombia
| | - | -----------------------------------------------------



| | · | a decrease of US$8.1 million in sales in Chile, including US$10.4 million in oil sales partially offset by an increase of US$2.3
million of gas sales.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a decrease of US$2.7 million in sales in Brazil, related to our Manati operations and including US$0.3 million of oil sales
and US$2.4 million of gas sales,
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------



all of which was due principally to lower
oil and gas prices, as further described below.



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Revenue attributable to our operations
in Colombia for the year ended December 31, 2016 was US$126.2 million, compared to US$131.9 million for the year ended December
31, 2015, representing 66% and 63% of our total consolidated sales. The decrease is related to a decrease in the average realized
prices per barrel of crude oil from US$28.8 per barrel to US$24.4 per barrel, primarily due to lower reference international prices.
This was partially offset by an increased sales of crude oil, from 4.6 mmbbl for the year ended December 31, 2015 to 5.4 mmbbl
for the year ended December 31, 2016, an increase of 17%. This increase resulted mainly from the development and appraisal of the
Jacana and Tigana fields in the Llanos 34 Block.



Revenue attributable to our operations
in Chile for the year ended December 31, 2016 was US$36.7 million, a 18% decrease from US$44.8 million for the year ended December
31, 2015, principally due to (1) decreased sales of crude oil of 0.5 mmbbl for the year ended December 31, 2016 compared to 0.7
mmbbl for the year ended December 31, 2015 (a decrease of 29%) due to the decline in oil base production, (2) decreased average
realized prices per barrel of crude oil from US$42.2 per barrel for the year December 31, 2015 to US$37.0 per barrel for the year
ended December 31, 2016 (a decrease of US$5.2 per barrel or a total of 12%). The decrease in the average realized price per barrel
was attributable to lower international reference prices. This was partially offset by an increase in gas sales by US$2.3 million,
due to increased gas production levels as compared to the previous year. The contribution to our revenue during such years from
our operations in Chile was 19% and 21%, respectively.



Revenue attributable to our operations
in Brazil for the year ended December 31, 2016 was US$29.7 million, a 8% decrease from US$32.4 million for the year ended December
31, 2015, principally due to decreased sales of gas of 5.8 mmcf for the year ended December 31, 2016 compared to 6.7 mmcf for the
year ended December 31, 2015 (a decrease of 13%) due to lower industrial demand. The contribution to our revenue during such years
from our operations in Brazil was 15%.



Production and operating costs



The following table summarizes our production
and operating costs for the years ended December 31, 2016 and 2015.



|                                                                     |  | For the year ended December 31,              
|-------------------------------------------------------------------- |  | ---------------------------------------------
|                                                                     |  | 2016                                         
|                                                                     |  | (in thousands of US$, except for percentages)
|Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) |  |                                              
|Royalties                                                            |  |                                              
|Staff costs                                                          |  |                                              
|Transportation costs                                                 |  |                                              
|Well and facilities maintenance                                      |  |                                              
|Consumables                                                          |  |                                              
|Equipment rental                                                     |  |                                              
|Other costs                                                          |  |                                              
|Total                                                                |  |                                              



|                                |  | Year ended December 31,
|------------------------------- |  | -----------------------
|                                |  | 2016                   
|                                |  | Chile                  
|By country                      |  | (in thousands of US$)  
|Royalties                       |  |                        
|Staff costs                     |  |                        
|Transportation costs            |  |                        
|Well and facilities maintenance |  |                        
|Consumables                     |  |                        
|Equipment rental                |  |                        
|Other costs                     |  |                        
|Total                           |  |                        
|                                |  |                        

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Consolidated production and operating costs
decreased 22%, from US$86.7 million for the year ended December 31, 2015 to US$67.2 million for the year ended December 31, 2016,
primarily due to cost reduction efforts and efficiencies, partially offset by increased volume sold.



Production and operating costs in Colombia
decreased 25%, to US$36.6 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily
due to cost reduction efforts. In addition, operating costs per boe in Colombia decreased to US$5 per boe for the year ended December
31, 2016 from US$9 per boe for the year ended December 31, 2015.



Production and operating costs in Chile
decreased by 23%, due to cost reduction initiatives and operating costs per boe decreased to US$16 per boe from US$21 per boe in
2015. In the year ended December 31, 2016, the revenue mix for Chile was 51.1% oil and 48.9% gas, whereas for the same period in
2015 it was 65.1% oil and 34.9% gas.



Production and operating costs in Brazil
increased by 5%, to US$8.4 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily
due to decrease in production. Operating costs per boe increased to US$6 for the year ended December 31, 2016 from US$4 per boe
for the year ended December 31, 2015.



Geological and geophysical expenses



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (4,296  | )                     
|Chile    |  |                                               | (1,671  | )                     
|Brazil   |  |                                               | (1,053  | )                     
|Other    |  |                                               | (3,262  | )                     
|Total    |  |                                               | (10,282 | )                     



Geological and geophysical expenses decreased
26%, from US$13.8 million for the year ended December 31, 2015 to US$10.3 million for the year ended December 31, 2016, primarily
as the result of higher allocation to capitalized projects and lower staff costs.



Administrative costs



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (14,715 | )                     
|Chile    |  |                                               | (7,153  | )                     
|Brazil   |  |                                               | (3,085  | )                     
|Other    |  |                                               | (9,217  | )                     
|Total    |  |                                               | (34,170 | )                     



Administrative costs decreased 9%, from
US$37.5 million for the year ended December 31, 2015 to US$34.2 million for the year ended December 31, 2016, primarily as a result
of continuing financial discipline.



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Selling expenses



|         |  | Year ended December 31,                       |        | Change from prior year
|-------- |  | --------------------------------------------- | ------ | ----------------------
|         |  | 2016                                          |        | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (2,830 | )                     
|Chile    |  |                                               | (994   | )                     
|Brazil   |  |                                               | (20    | )                     
|Other    |  |                                               | (378   | )                     
|Total    |  |                                               | (4,222 | )                     



Selling expenses decreased 19%, from US$5.2
million for year ended December 31, 2015 to US$4.2 million for the year ended December 31, 2016, primarily due to a change in the
commercialization mix increasing sales at wellhead in our Colombian operations. In our Chilean operations, selling expenses were
8% lower compared to prior year, primarily as a result of lower oil production levels.



Operating (loss) profit



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | 31,464  |                       
|Chile    |  |                                               | (44,969 | )                     
|Brazil   |  |                                               | (644    | )                     
|Other    |  |                                               | (14,464 | )                     
|Total    |  |                                               | (28,613 | )                     



We recorded an operating loss of US$28.6
million for the year ended December 31, 2016, an 88% improvement from the operating loss of US$232.5 million for the year ended
December 31, 2015, primarily due to the recognition in 2015 of non-cash impairments of non-financial assets amounting to US$149.6
million (US$104.5 million recorded in Chile and US$45.1 million in Colombia). In 2016, we recorded a gain on non-cash impairments
reversal of non-financial assets amounting to US$5.7 million in Colombia, resulting from an improved oil price environment and
improvements in cost structure.



Financial costs



Financial costs decreased 4% to US$34.1
million for the year ended December 31, 2016 as compared to US$35.7 million for the year ended December 31, 2015, mainly due to
the impact of lower bank charges and higher interest gains.



Foreign exchange gain (loss)



Foreign exchange variation was 141% to
a gain of US$13.9 million for the year ended December 31, 2016 as compared to US$33.5 million loss for the year ended December
31, 2015, mainly because of the appreciation of the real over US$ denominated net debt incurred at the local subsidiary
level, where the functional currency is the real.



(Loss) Profit before income tax



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | 25,845  |                       
|Chile    |  |                                               | (58,017 | )                     
|Brazil   |  |                                               | 8,762   |                       
|Other    |  |                                               | (25,432 | )                     
|Total    |  |                                               | (48,842 | )                     

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For the year ended December 31, 2016, we
recorded a loss before income tax of US$48.8 million, compared to a loss of US$301.6 million for the year ended December 31, 2015,
primarily due to decreased losses from our Chilean and Other operations and profits recorded in our Colombian and Brazilian operations.



Income tax (expense) benefit



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (11,969 | )                     
|Chile    |  |                                               | 2,155   |                       
|Brazil   |  |                                               | (2,764  | )                     
|Other    |  |                                               | 774     |                       
|Total    |  |                                               | (11,804 | )                     



Income tax expense decreased 169%, from
US$17.1 million for the year ended December 31, 2015 to a loss of US$11.8 million for the year ended December 31, 2016, as a result
of increased results of operations, mainly related to Colombia and Brazil.



(Loss) Profit for the year



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2016                                          |         | 2015                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | 13,876  |                       
|Chile    |  |                                               | (55,862 | )                     
|Brazil   |  |                                               | 5,998   |                       
|Other    |  |                                               | (24,658 | )                     
|Total    |  |                                               | (60,646 | )                     



For the year ended December 31, 2016, we
recorded a loss of US$60.6 million as a result of the reasons described above.



(Loss) Profit for the year attributable to
owners of the Company



Loss for the year attributable to owners
of the Company decreased by 79% to US$49.1 million, for the reasons described above. Loss attributable to non-controlling interest
decreased by 77% to US$11.6 million for the year ended December 31, 2016 as compared to the prior year.



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Year ended December 31, 2015 compared
to year ended December 31, 2014



The following table summarizes certain
of our financial and operating data for the years ended December 31, 2015 and 2014.



|                                                                 |  | For the year ended December 31,              
|---------------------------------------------------------------- |  | ---------------------------------------------
|                                                                 |  | 2015                                         
|                                                                 |  | (in thousands of US$, except for percentages)
|Revenue                                                          |  |                                              
|Net oil sales                                                    |  |                                              
|Net gas sales                                                    |  |                                              
|Net revenue                                                      |  |                                              
|Production and operating costs                                   |  |                                              
|Geological and geophysical expenses                              |  |                                              
|Administrative expenses                                          |  |                                              
|Selling expenses                                                 |  |                                              
|Depreciation                                                     |  |                                              
|Write-off of unsuccessful efforts                                |  |                                              
|Impairment loss for non-financial assets                         |  |                                              
|Other operating expense                                          |  |                                              
|Operating (loss)/profit                                          |  |                                              
|Financial costs                                                  |  |                                              
|Foreign exchange loss                                            |  |                                              
|(Loss) Profit before income tax                                  |  |                                              
|Income tax benefit (expense)                                     |  |                                              
|(Loss) Profit for the year                                       |  |                                              
|Non-controlling interest                                         |  |                                              
|(Loss) Profit for the year attributable to owners of the Company |  |                                              
|Net production volumes                                           |  |                                              
|Oil (mbbl)                                                       |  |                                              
|Gas (mcf)                                                        |  |                                              
|Total net production (mboe)                                      |  |                                              
|Average net production (boepd)                                   |  |                                              
|Average realized sales price                                     |  |                                              
|Oil (US$ per bbl)                                                |  |                                              
|Gas (US$ per mmcf)                                               |  |                                              
|Average unit costs per boe (US$)                                 |  |                                              
|Operating cost                                                   |  |                                              
|Royalties and other                                              |  |                                              
|Production costs(1)                                              |  |                                              
|Geological and geophysical expenses                              |  |                                              
|Administrative expenses                                          |  |                                              
|Selling expenses                                                 |  |                                              




| | (1) | Calculated pursuant to FASB ASC 932.
| | --- | ------------------------------------



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The following table summarizes certain
financial and operating data.



|                         |                       | For
        the year ended December 31,
|------------------------ | --------------------- | ---------------------------------------
|                         | 2015                  | 2014                                   
|                         | Chile                 | Colombia                               
|                         | (in thousands of US$)
|Net revenue              | 44,808                | 131,897                                
|Depreciation             | (39,227)              | (52,434)                               
|Impairment and write-off | (130,266)             | (49,392)                               
|                         |                       |                                        



Net revenue



For the year ended December 31, 2015, crude
oil sales were our principal source of revenue, with 78% and 22% of our total revenue from crude oil and gas sales, respectively.
The following chart shows the change in oil and natural gas sales from the year ended December 31, 2014 to the year ended December
31, 2015.



|                  |  | For the year ended December 31,
|----------------- |  | -------------------------------
|                  |  | 2015                           
|Consolidated      |  | (in thousands of US$)          
|Sale of crude oil |  |                                
|Sale of gas       |  |                                
|Total             |  |                                



|           |  | Year ended December 31,                       |         | Change from prior year
|---------- |  | --------------------------------------------- | ------- | ----------------------
|           |  | 2015                                          |         | 2014                  
|           |  | (in thousands of US$, except for percentages)
|By country |  |                                              
|Colombia   |  |                                               | 131,897 |                       
|Chile      |  |                                               | 44,808  |                       
|Brazil     |  |                                               | 32,388  |                       
|Other      |  |                                               | 597     |                       
|Total      |  |                                               | 209,690 |                       



Net revenue decreased 51%, from US$428.7
million for the year ended December 31, 2014 to US$209.7 million for the year ended December 31, 2015, primarily as a result of
lower prices. Sales of crude oil increased to 5.3 mmbbl in the year ended December 31, 2015 compared to 5.0 mmbbl in the year ended
December 31, 2014, and resulted in net revenue of US$162.6 million for the year ended December 31, 2015 compared to US$367.1 for
the year ended December 31, 2014. In addition, sales of gas decreased from US$61.6 million for the year ended December 31, 2014
to US$47.1 million for the year ended December 31, 2015 due to lower prices.



The decrease in 2015 net revenue of US$219.0
million is mainly explained by:



| | · | a decrease of US$114.2 million in oil sales in Colombia
| | - | -------------------------------------------------------



| | · | a decrease of US$100.9 million in sales in Chile, including US$89.0 million in oil sales and US$11.9 million of gas sales.
| | - | --------------------------------------------------------------------------------------------------------------------------



| | · | a decrease of US$3.2 million in sales in Brazil, related to our Rio das Contas operations and including US$0.6 million of oil
sales and US$2.6 million of gas sales,
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



all of which was due principally to lower
oil and gas prices, as further described below.



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Net revenue attributable to our operations
in Colombia for the year ended December 31, 2015 was US$131.9 million, compared to US$246.1 million for the year ended December
31, 2014, representing 63% and 57% of our total consolidated sales. The decrease is related to a decrease in the average realized
prices per barrel of crude oil from US$73.0 per barrel to US$28.8 per barrel, primarily due to lower reference international prices.
This was partially offset by an increased sales of crude oil, from 3.7 mmbbl for the year ended December 31, 2014 to 4.6 mmbbl
for the year ended December 31, 2015, an increase of 24%. This increase resulted mainly from the development of the Tigana field
in the Llanos 34 Block.



Net revenue attributable to our operations
in Chile for the year ended December 31, 2015 was US$44.8 million, a 69% decrease from US$145.7 million for the year ended December
31, 2014, principally due to (1) decreased sales of crude oil of 0.7 mmbbl for the year ended December 31, 2015 compared to 1.3
mmbbl for the year ended December 31, 2014 (a decrease of 46%) due to the decline in base production, (2) decreased average realized
prices per barrel of crude oil from US$89.4 per barrel for the year December 31, 2014 to US$42.2 per barrel for the year ended
December 31, 2015 (a decrease of US$47.2 per barrel or a total of 53%). The decrease in the average realized price per barrel was
attributable to lower international reference prices. In addition, gas sales decreased by US$11.9 million. The contribution to
our net revenue during such years from our operations in Chile was 21% and 34%, respectively.



Net revenue attributable to our operations
in Brazil for the year ended December 31, 2015 was US$32.4 million, representing 15% of our total consolidated sales, were related
to our Rio das Contas operations and were composed of 97% gas sales, amounting to US$31.4 million.



Production and operating costs



The following table summarizes our production
and operating costs for the years ended December 31, 2015 and 2014.



|                                                               |  | For the year ended December 31,              
|-------------------------------------------------------------- |  | ---------------------------------------------
|                                                               |  | 2015                                         
|                                                               |  | (in thousands of US$, except for percentages)
|Consolidated (including Colombia, Chile, Argentina and Brazil) |  |                                              
|Royalties                                                      |  |                                              
|Staff costs                                                    |  |                                              
|Transportation costs                                           |  |                                              
|Well and facilities maintenance                                |  |                                              
|Consumables                                                    |  |                                              
|Equipment rental                                               |  |                                              
|Other costs                                                    |  |                                              
|Total                                                          |  |                                              



|                                |  | Year ended December 31,
|------------------------------- |  | -----------------------
|                                |  | 2015                   
|                                |  | Chile                  
|                                |  | (in thousands of US$)  
|By country                      |  |                        
|Royalties                       |  |                        
|Staff costs                     |  |                        
|Transportation costs            |  |                        
|Well and facilities maintenance |  |                        
|Consumables                     |  |                        
|Equipment rental                |  |                        
|Other costs                     |  |                        
|Total                           |  |                        

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Consolidated production and operating costs
decreased 34%, from US$131.4 million for the year ended December 31, 2014 to US$86.7 million for the year ended December 31, 2015,
primarily due to cost reduction initiatives and the impact of the depreciation of the local currencies against the US$.



Production and operating costs in Colombia
decreased 40%, to US$48.5 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014, primarily
due to cost reduction initiatives and the impact of the depreciation of the Col$ against the US$. In addition, operating costs
per boe in Colombia decreased to US$9 per boe for the year ended December 31, 2015 from US$18 per boe for the year ended December
31, 2014, due to the fact that increased production generated improved fixed cost absorption, which positively impacted production
costs per boe.



Production and operating costs in Chile
decreased by 31%, due to cost reduction initiatives and the impact of the depreciation of the Ch$ against the US$. In the year
ended December 31, 2015, in Chile, operating costs per boe increased to US$21.0 per boe from US$16.7 per boe in 2014. In the year
ended December 31, 2015, the revenue mix for Chile was 65.1% oil and 34.9% gas, whereas for the same period in 2014 it was 81.1%
oil and 18.9% gas.



Production and operating costs in Brazil
amounted to US$8.1 million for the year ended December 31, 2015 corresponding to our Rio das Contas operations. Operating costs
per boe decreased to US$4 for the year ended December 31, 2015 from US$6 per boe for the year ended December 31, 2014.



Geological and geophysical expenses



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2015                                          |         | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (2,798  | )                     
|Chile    |  |                                               | (4,749  | )                     
|Brazil   |  |                                               | (1,103  | )                     
|Other    |  |                                               | (5,181  | )                     
|Total    |  |                                               | (13,831 | )                     



Geological and geophysical expenses increased
6%, from US$13.0 million for the year ended December 31, 2014 to US$13.8 million for the year ended December 31, 2015, primarily
as the result of a lower allocation to capitalized projects generated by the reduction of the capital expenditures program in 2015.



Administrative costs



|         |  | Year ended December 31,                       |         | Change from prior year
|-------- |  | --------------------------------------------- | ------- | ----------------------
|         |  | 2015                                          |         | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (10,579 | )                     
|Chile    |  |                                               | (10,978 | )                     
|Brazil   |  |                                               | (2,936  | )                     
|Other    |  |                                               | (12,978 | )                     
|Total    |  |                                               | (37,471 | )                     



Administrative costs decreased 18%, from
US$45.9 million for the year ended December 31, 2014 to US$37.5 million for the year ended December 31, 2015, primarily as a result
of a decrease in costs due to continuing financial discipline and cost reduction initiatives impacting consultant fees, office
expenses, directors fees and others. The reduction was achieved despite new start-up costs related to operations in Peru.



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Selling expenses



|         |  | Year ended December 31,                       |        | Change from prior year
|-------- |  | --------------------------------------------- | ------ | ----------------------
|         |  | 2014                                          |        | 2013                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (3,658 | )                     
|Chile    |  |                                               | (1,085 | )                     
|Brazil   |  |                                               | —      |                       
|Other    |  |                                               | (468   | )                     
|Total    |  |                                               | (5,211 | )                     



Selling expenses decreased 79%, from US$24.4
million for year ended December 31, 2014 to US$5.2 million for the year ended December 31, 2015, primarily due to a change in the
commercialization mix increasing sales at wellhead in our Colombian operations. In our Chilean operations, selling expenses were
56% lower compared to prior year, primarily as a result of lower production and deliveries in Chile.



Operating (loss) profit



|         |  | Year ended December 31,                       |          | Change from prior year
|-------- |  | --------------------------------------------- | -------- | ----------------------
|         |  | 2015                                          |          | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (37,227  | )                     
|Chile    |  |                                               | (180,264 | )                     
|Brazil   |  |                                               | 6,639    |                       
|Other    |  |                                               | (21,639  | )                     
|Total    |  |                                               | (232,491 | )                     



We recorded an operating loss of US$232.5
million for the year ended December 31, 2015, a 424% decrease from the operating profit of US$71.8 million for the year ended December
31, 2014, primarily due to non-cash impairments of non-financial assets, which amounted to US$149.6 million (US$104.5 million recorded
in Chile and US$45.1 million in Colombia), resulting from the continuing low oil price environment and lower sales.



Financial costs



Financial costs increased 29% to US$35.7
million for the year ended December 31, 2015 as compared to US$27.6 million for the year ended December 31, 2014, mainly due to
the impact of lower capitalized interest costs and, to a lesser extent, the increase of other financial costs.



Foreign exchange loss



Foreign exchange loss increased 45% to
US$33.5 million for the year ended December 31, 2015 as compared to US$23.1 million for the year ended December 31, 2014, mainly
because of the depreciation of the real over US$ denominated net debt incurred at the local subsidiary level, where the
functional currency is the real.



(Loss) Profit before income tax



|         |  | Year ended December 31,                       |          | Change from prior year
|-------- |  | --------------------------------------------- | -------- | ----------------------
|         |  | 2015                                          |          | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (38,339  | )                     
|Chile    |  |                                               | (193,683 | )                     
|Brazil   |  |                                               | (37,980  | )                     
|Other    |  |                                               | (31,618  | )                     
|Total    |  |                                               | (301,620 | )                     

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For the year ended December 31, 2015, we
recorded a loss before income tax of US$301.6 million, compared to a profit of US$21.1 million for the year ended December 31,
2014, primarily due to losses from our Chilean, Colombian and Brazilian operations amounting to US$206.8 million, US$99.9 million
and US$28.3 million, respectively, partially offset by lower losses from our Other operations amounting to US$12.3 million.



Income tax benefit (expense)



|         |  | Year ended December 31,                       |        | Change from prior year
|-------- |  | --------------------------------------------- | ------ | ----------------------
|         |  | 2015                                          |        | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (620   | )                     
|Chile    |  |                                               | 16,893 |                       
|Brazil   |  |                                               | 8,357  |                       
|Other    |  |                                               | (7,576 | )                     
|Total    |  |                                               | 17,054 |                       



Income tax expense decreased 428%, from
US$5.2 million for the year ended December 31, 2014 to a benefit of US$17.1 million for the year ended December 31, 2015, as a
result of our decreased results of operations, partially offset by non-recoverable tax loss carry-forwards amounting to US$15.5
million. Our effective tax rate for the year ended December 31, 2015 was 6% as compared to 25% in the year ended December 31, 2014.



(Loss) Profit for the year



|         |  | Year ended December 31,                       |          | Change from prior year
|-------- |  | --------------------------------------------- | -------- | ----------------------
|         |  | 2015                                          |          | 2014                  
|         |  | (in thousands of US$, except for percentages)
|Colombia |  |                                               | (38,959  | )                     
|Chile    |  |                                               | (176,789 | )                     
|Brazil   |  |                                               | (29,623  | )                     
|Other    |  |                                               | (39,195  | )                     
|Total    |  |                                               | (284,566 | )                     



For the year ended December 31, 2015, we
recorded a loss of US$384.6 million as a result of the reasons described above.



(Loss) Profit for the year attributable to
owners of the Company



Loss for the year attributable to owners
of the Company decreased by 2,995% to US$234.0 million, for the reasons described above. Loss attributable to non-controlling interest
decreased by 744% to US$50.5 million for the year ended December 31, 2015 as compared to the prior year.



| | B. | Liquidity and capital resources
| | -- | -------------------------------



Overview



Our financial condition and liquidity is
and will continue to be influenced by a variety of factors, including:



| | · | changes in oil and natural gas prices and our ability to generate cash flows from our operations;
| | - | -------------------------------------------------------------------------------------------------



| | · | our capital expenditure requirements;
| | - | -------------------------------------



| | · | the level of our outstanding indebtedness and the interest we are obligated to pay on this indebtedness; and
| | - | ------------------------------------------------------------------------------------------------------------



| | · | changes in exchange rates which will impact our generation of cash flows from operations when measured in US$, and the real.
| | - | ----------------------------------------------------------------------------------------------------------------------------



Our principal sources of liquidity have
historically been contributed shareholder equity, debt financings and cash generated by our operations.



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Since 2005 to 2016, we have raised approximately
US$200 million in equity offerings at the holding company level and more than US$500 million through debt arrangements with multilateral
agencies such as the IFC, gas prepayment facilities with Methanex, international bond issuances and bank financings, described
further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.



We have also raised US$180.9 million to
date through our strategic partnership with LGI following the sale of minority interests in our Colombian and Chilean operations.



We initially funded our 2012 expansion
into Colombia through a US$37.5 million loan, cash on hand and a subsequent sale of a minority interest in our Colombian operations
to LGI. We subsequently restructured our outstanding debt in February 2013, by issuing US$300.0 million aggregate principal amount
of Notes due 2020, a portion of the proceeds of which we used to prepay the US$37.5 million loan and to redeem all of our outstanding
Notes due 2015. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Agreements
with LGI.”



In February 2014, we commenced trading
on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted
to and exercised by the underwriters, through the issuance of 13,999,700 common shares.



In March 2014, we borrowed US$70.5 million
pursuant to a five-year term (including annual principal amortization in March and September of each year starting in 2015) variable
interest secured loan, secured by the benefits we receive under the Purchase and Sale Agreement for Natural Gas with Petrobras,
equal to 6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das Contas acquisition, and funded the remaining
amount with cash on hand. In March 2015, we reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting
to approximately US$15 million), which will be divided pro-rata during the remaining principal installments, starting in March
2016 and (ii) to increase the variable interest rate equal to the 6-month LIBOR + 4.0%.



In February, 2013, we issued US$300.0 million
aggregate principal amount of senior secured notes due 2020. The Notes due 2020 mature on February 11, 2020 and bear interest at
a fixed rate of 7.50% and a yield of 7.625% per year. Interest on the Notes due 2020 is payable semi-annually in arrears on February
11 and August 11 of each year. The Indenture governing our Notes due 2020 contain incurrence-based limitations on the amount of
indebtedness we can incur. During 2015, and impacted by the current low oil price environment, our leverage ratio (as defined in
the Indenture) and the interest coverage (as defined in the Indenture) did not meet certain thresholds included in the 2020 Bond
Indenture. This situation may limit our capacity to incur additional indebtedness, other than permitted debt, as specified in the
indenture governing the Notes.



In December 2015, we entered into an offtake
and prepayment agreement with Trafigura under which we will sell a portion of our Colombian crude oil production to Trafigura in
exchange for advance payments of up to US$100 million, subject to applicable volumes corresponding to the terms of the agreement.
Funds committed by Trafigura were available to us upon request until September 2016.



In February 2017, the availability period
under the prepayment agreement with Trafigura was extended until June 30, 2017. This extension provides us with available funds
upon request from Trafigura to be repaid by us on a monthly basis through future oil deliveries over the period between January
2017 and December 2018.



We believe that our current operations
and 2017 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating
cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we
would examine measures such as further capital expenditure program reductions, pre-sale agreements, disposition of assets, or issuance
of equity, among others.



Capital expenditures



In the past, we have funded our capital
expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through
cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and
natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview—2017
Strategy and Outlook.”



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In the year ended December 31, 2016, we
made total capital expenditures of US$39.3 million (US$26.2 million, US$7.8 million, US$1.7 million and US$3.6 million in Colombia,
Chile, Argentina and Brazil, respectively).



In the year ended December 31, 2015, we
made total capital expenditures of US$48.8 million (US$30.7 million, US$12.4 million, US$0.1 million and US$5.6 million in Colombia,
Chile, Argentina and Brazil, respectively).



Cash flows



The following table sets forth our cash
flows for the periods indicated:



|                                                     |  | Year ended December 31,
|---------------------------------------------------- |  | -----------------------
|                                                     |  | 2016                   
|                                                     |  | (in thousands of US$)  
|Cash flows provided by (used in)                     |  |                        
|Operating activities                                 |  |                        
|Investing activities                                 |  |                        
|Financing activities                                 |  |                        
|Net (decrease) increase in cash and cash equivalents |  |                        



Cash flows provided by operating activities



For the year ended December 31, 2016, cash
provided by operating activities was US$82.9 million, a 220% increase from US$25.9 million for the year ended December 31, 2015,
resulting from cost reduction efforts, lower income tax paid and increased funds from working capital, including customer advance
payments from Trafigura.



For the year ended December 31, 2015, cash
provided by operating activities was US$25.9 million, a 88.8% decrease from US$230.7 million for the year ended December 31, 2014,
resulting from the decline in oil and natural gas prices in 2015 as compared to 2014.



Cash flows used in
investing activities



For the year ended December 31, 2016, cash
used in investing activities was US$39.3 million, a 20% decrease from US$48.8 million for the year ended December 31, 2015. This
decrease was related to lower capital expenditures in Colombia, Chile and Brazil in 2016 as compared to 2015, despite having similar
activity levels.



For the year ended December 31, 2015, cash
used in investing activities was US$48.8 million, a 85.8% decrease from US$344.0 million for the year ended December 31, 2014.
This decrease was related to our Brazilian acquisitions, which occurred in the first quarter of 2014. This amount was complemented
by a decrease of US$189.2 million in capital expenditures mainly resulting from lower wells drilled in 2015 as compared to 2014
(7 wells drilled in 2015 compared to 53 wells drilled in 2014).



Cash flows used in financing activities



Cash used in financing activities was US$51.1
million for the year ended December 31, 2016, compared to US$18.0 million for the year ended December 31, 2015. This change was
principally the result of principal payments related to Itau Loan and dividends distribution to non-controlling interest.



Cash used in financing activities was US$18.0
million for the year ended December 31, 2015, compared to cash provided by financing activities of US$124.7 million for the year
ended December 31, 2014. This change was principally the result of cash received in the 2014 period from the funds recovered from
our initial public offering and listing of our common shares on the NYSE in February 2014 amounting to US$90.9 million and the
US$70.5 million loan entered into with Itaú BBA International plc used to fund the Rio das Contas acquisition. Cash used
in financing activities in 2015 is composed mainly of interest payments amounting to US$25.8 million, partially offset by US$7.0
million of proceeds from borrowings.



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Indebtedness



As of December 31, 2016 and 2015, we had
total outstanding indebtedness of US$358.7 million and US$378.7 million, respectively, as set forth in the table below.







|                                                             |  | As
of December 31,   
|------------------------------------------------------------ |  | ---------------------
|                                                             |  | 2016                 
|                                                             |  | (in thousands of US$)
|BCI Loans                                                    |  |                      
|Bond GeoPark Latin America Agencia en Chile (Notes due 2020) |  |                      
|Banco de Chile                                               |  |                      
|Rio das Contas Credit Facility                               |  |                      
|Total                                                        |  |                      



Our material outstanding indebtedness as
of December 31, 2016 is described below.



Notes due 2020



General



On February 11, 2013, we issued US$300.0
million aggregate principal amount of senior secured notes due 2020. The Notes due 2020 mature on February 11, 2020 and bear interest
at a fixed rate of 7.50% and a yield of 7.625% per year. Interest on the Notes due 2020 is payable semi-annually in arrears on
February 11 and August 11 of each year.



Ranking



The Notes due 2020 constitute senior obligations
of Agencia, secured by a first lien on certain collateral (as described below). The Notes due 2020 rank equally in right of payment
with all senior existing and future obligations of Agencia (except those obligations preferred by operation of Bermuda and Chilean
law, including, without limitation, labor and tax claims); effectively senior to all unsecured debt of Agencia and GeoPark Latin
America, to the extent of the value of the collateral; senior in right of payment to all existing and future subordinated indebtedness
of Agencia and GeoPark Latin America; and effectively junior to any future secured obligations of Agencia and its subsidiaries
(other than additional notes issued pursuant to the indenture governing the Notes due 2020) to the extent secured by assets constituting
with a security interest on assets not constituting collateral, in each case to the extent of the value of the collateral securing
such obligations.



Guarantees



The Notes due 2020 are guaranteed unconditionally
on an unsecured basis by us, all of our wholly-owned subsidiaries, and any subsidiary that guarantees any of our debt, subject
to certain exceptions.



Collateral



The notes are secured by a first-priority
perfected security interest in certain collateral, which consists of: 80% of the equity interests of each of GeoPark Chile and
GeoPark Colombia held by Agencia, and loans of the net proceeds of the Notes due 2020 made by Agencia to each of GeoPark Fell and
GeoPark Llanos SAS. Except for certain immaterial subsidiaries and other exceptions, we and Agencia are also required to pledge
the equity interests of our subsidiaries.



The Notes due 2020 are also secured on
a first-priority basis by intercompany loans, disbursed to subsidiaries, in an aggregate amount at any one time that does not exceed
US$300.0 million.



Optional redemption



We may, at our option, redeem all or part
of the Notes due 2020, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and
unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month
period beginning on February 11 of the years indicated below:



|Year           | Percentage
|-------------- | ----------
|2017           | 103.750%  
|2018           | 101.875%  
|2019 and after | 100.000%  

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Change of control



Upon the occurrence of certain events constituting
a change of control, we are required to make an offer to repurchase all outstanding Notes due 2020, at a purchase price equal to
101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect
thereof) thereon to the date of purchase.



Covenants



The Notes due 2020 contain customary covenants,
which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including
restrictions on our ability to pay dividends), incurrence of liens, transfer, prepayment or modification of certain collateral,
guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates,
engaging in certain businesses and merger or consolidation with or into another company.



In the event the Notes due 2020 receive
investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch,
and no default has occurred or is continuing under the indenture governing the Notes due 2020, certain of these restrictions, including,
among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions
on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with
affiliates will no longer be applicable.



The indenture governing our Notes due 2020
includes incurrence test covenants that provide, among other things, that, the debt to EBITDA ratio should not exceed 2.5 and the
EBITDA to Interest ratio should exceed 3.5. As of the date of this annual report, the Company’s debt to EBITDA ratio was
4.6 and the EBITDA to interest ratio was 2.7, 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 our
capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of
permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including
but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions). As
of the date of this annual report, we are in compliance with all indenture provisions.



Events of default



Events of default under the indenture governing
the Notes due 2020 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period
of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control
or as required by certain covenants in the indenture governing the Notes due 2020; the notes, or the security documents in relation
thereto that continues for a period of 60 consecutive days after written notice to Agencia; cross payment default relating to debt
with a principal amount of US$15.0 million or more, and cross-acceleration default following a judgment for US$15.0 million or
more; bankruptcy and insolvency events; invalidity or denial or disaffirmation of a guarantee of the notes; and failure to maintain
a perfected security interest in any collateral having a fair market value in excess of US$15.0 million, among others. The occurrence
of an event of default would permit or require the principal of and accrued interest on the Notes due 2020 to become or to be declared
due and payable.



Banco de Chile



During December 2015, we entered into a
loan agreement with Banco de Chile for US$7.0 million to finance the start-up of the new Ache gas field in the Fell Block. The
interest rate applicable to this loan is LIBOR plus 2.35% per year. The interest and the principal will be paid on a monthly basis
with a 6-month grace period and final maturity on December 2017.



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BCI Loan



During February 2016, we executed a loan
agreement with Banco de Crédito e Inversiones (BCI) to finance the acquisition of vehicles for our Chilean operations. The
interest rate applicable to this loan is 4.14% per annum. The interest and the principal will be paid on monthly basis, with final
maturity on February 2019.



LGI Line of Credit



As of December 31, 2016, the aggregate
outstanding amount under the LGI Line of Credit was US$27.8 million. This corresponds to a loan granted by LGI to GeoPark Chile
for financing Chilean operations in our Tierra del Fuego blocks. The maturity of this loan is July 2020 and the applicable interest
rate is 8% per year.



See “Item 4. Information on the Company—B.
Business Overview—Significant Agreements—Agreements with LGI.”



Rio das Contas Credit Facility



We financed our Rio das Contas acquisition
in part through our Brazilian subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas Credit
Facility”) with Itaú BBA International plc, which is secured by the benefits GeoPark receives under the Purchase and
Sale Agreement for Natural Gas with Petrobras. The facility matures five years from March 28, 2014, which was the date of disbursement
and bears interest at a variable interest rate equal to the 6-month LIBOR + 3.9%. The facility agreement includes customary events
of default, and subject our Brazilian subsidiary to customary covenants, including the requirement that it maintain a ratio of
net debt to EBITDA of up to 3.5x 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. We have the option to prepay the facility in
whole or in part, at any time, subject to a pre-payment fee to be determined under the contract.



In March 2015, we reached an agreement
to: (i) extend the principal payments that were due in 2015 (amounting to approximately US$15 million), which will be divided pro-rata
during the remaining principal installments, starting in March 2016 and (ii) to increase the variable interest rate equal to the
6-month LIBOR + 4.0%. As a result of the above, in March 2016, September 2016 and March 2017 we paid US$30 million in aggregate
corresponding to principal payments under the current principal amortization schedule.



Other Agreements



In December 2015, we entered into an offtake
and prepayment agreement with Trafigura under which we sell and deliver a portion of our Colombian crude oil production. Pricing
will be determined by future spot market prices, net of transportation costs. The agreement also provides us with prepayment of
up to US$100 million from Trafigura. Funds committed will be made available to us upon request and will be repaid by us on a monthly
basis through future oil deliveries over the period of the contract, which is 2.5 years, including a 6-month grace period. According
to the terms of the prepayment agreement, we are required to pay interest of LIBOR plus 5% per year on outstanding amounts. In
addition, under the prepayment agreement, we are required to maintain certain coverage ratios linking: (i) future payments to the
value of estimated future oil deliveries (net of transportation discounts) during the term of the offtake agreement and (ii) collections
to payments within specified periods, with the possibility of delivering additional volumes to meet such ratios in the upcoming
3-month period. As of March 31, 2017, outstanding amounts related to the prepayment agreement amount to US$20 million.



| | C. | Research and development, patents and licenses, etc.
| | -- | ----------------------------------------------------



See “Item 4. Information on the Company——B.
Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to Properties.”



| | D. | Trend information
| | -- | -----------------



For a discussion of Trend information,
see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information
on the Company –B. Business Overview—2017 Strategy and Outlook.”



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| | E. | Off-balance sheet arrangements
| | -- | ------------------------------



We did not have any off-balance sheet arrangements
as of December 31, 2016 or as of December 31, 2015.



| | F. | Tabular disclosure of contractual obligations
| | -- | ---------------------------------------------



In accordance with the terms of our concessions,
we are required to pay royalties in connection with our crude oil and natural gas production. See Note 31 to our Consolidated Financial
Statements.



The table below sets forth our committed
cash payment obligations as of December 31, 2016.



|                                  |  | Total                 |         | Less than one year |  | One to three years |         | Three to five years |  | More than five years
|--------------------------------- |  | --------------------- | ------- | ------------------ |  | ------------------ | ------- | ------------------- |  | --------------------
|                                  |  | (in thousands of US$)
|Debt obligations(1)               |  |                       | 447,326 |                    |  |                    | 48,958  |                     |  |                     
|Operating lease obligations(2)    |  |                       | 86,963  |                    |  |                    | 67,752  |                     |  |                     
|Pending investment commitments(3) |  |                       | 69,756  |                    |  |                    | 4,630   |                     |  |                     
|Asset retirement obligations      |  |                       | 29,862  |                    |  |                    | 306     |                     |  |                     
|Total contractual obligations     |  |                       | 633,907 |                    |  |                    | 121,646 |                     |  |                     




| | (1) | Refers to principal and interest undiscounted cash flows. Interest payment breakdown included in Debt Obligations is as follows
(i) less than one year: US$24.3 million; one to three years: US$45.9 million and three to five years: US$22.5 million. At December
31, 2016 the outstanding long-term borrowing affected by variable rates amounted to US$54.5 million representing 15% of total borrowings,
which was composed of the loan from Itaú International BBA plc and the loan from Banco de Chile that has a floating interest
rate based on LIBOR. See Note 3: “Interest rate risk” to our Consolidated Financial Statements.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Reflects the future aggregate minimum lease payments under non-cancellable operating lease agreements.
| | --- | ------------------------------------------------------------------------------------------------------



| | (3) | Includes capital commitments in Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13 concessions in Brazil,
three blocks in Argentina and the Llanos 32, VIM-3, and Llanos 34 Blocks in Colombia. See “Item 4. Information on the Company—B.
Business Overview—Our operations” and Note 31(b) to our Consolidated Financial Statements.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | G. | Safe harbor
| | -- | -----------



See “Forward-Looking Statements.”



ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES



| | A. | Directors and senior management
| | -- | -------------------------------



Board of directors



Our Board of Directors is composed of eight
members. At every annual general meeting, one-third of the Directors retire from office. Our Directors can hold office for such
term as the Shareholders may determine or, in the absence of such determination, until the next annual general meeting or until
their successors are elected or appointed or their office is otherwise vacated. The Directors whose term has expired may offer
themselves for re-election at each election of Directors. The term for the current Directors expires on the date of our next annual
shareholders’ meeting, to be held in 2017.



The current members of the Board of Directors
were appointed at our annual general meeting held on June 30, 2016. The table below sets forth certain information concerning our
current board of directors. All ages are as of March 31, 2017.



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|Name                        | Position                                                        | Age | At the
        Company since
|--------------------------- | --------------------------------------------------------------- | --- | ----------------------------
|Gerald E. O’Shaughnessy     | Chairman and Director                                           | 68  | 2002                        
|James F. Park               | Chief Executive Officer, Deputy Chairman and Director           | 61  | 2002                        
|Carlos A. Gulisano (3)      | Director                                                        | 66  | 2010                        
|Juan Cristóbal Pavez (1)(2) | Director                                                        | 46  | 2008                        
|Peter Ryalls (1)(2)         | Director                                                        | 66  | 2006                        
|Robert Bedingfield (1)(2)   | Director                                                        | 68  | 2015                        
|Pedro Aylwin Chiorrini      | Director, Director of Legal and Governance, Corporate Secretary | 57  | 2003                        
|Michael D. Dingman          | Director                                                        | 85  | 2017                        




| | (1) | Member of the Audit Committee.
| | --- | ------------------------------



| | (2) | Independent director under SEC Audit Committee rules.
| | --- | -----------------------------------------------------



| | (3) | Carlos Gulisano joined the Company in 2002 as an advisor.
| | --- | ---------------------------------------------------------



Biographical information
of the current members of our Board of Directors is set forth below. Unless otherwise indicated, the current business addresses
for our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile.



Gerald E. O’Shaughnessy
has been our Chairman and a member of our board of directors since he co-founded the company in 2002. Following his graduation
from the University of Notre Dame with degrees in government (1970) and law (1973), Mr. O’Shaughnessy was engaged in the
practice of law in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas business over his entire business career,
starting in 1976 with Lario Oil and Gas Company, where he served as Senior Vice President and General Counsel. He later formed
The Globe Resources Group, a private venture firm whose subsidiaries provided seismic acquisition and processing, well rehabilitation
services, sophisticated logistical operations and submersible pump works for Lukoil and other companies active in Russia during
the 1990s.  Mr. O’Shaughnessy is also founder and owner of BOE Midstream, LLC, which owns and operates the Bakken Oil
Express, a crude by rail transloading and storage terminal in North Dakota, serving oil producers and marketing companies in the
Bakken Shale Oil play. Over the past 25 years, Mr. O’Shaughnessy has also founded and operated companies engaged in banking,
wealth management products and services, investment desktop software, computer and network security, and green clean technology,
as well as other venture investments, Mr. O’Shaughnessy has also served on a number of non-profit boards of directors, including
the Board of Economic Advisors to the Governor of Kansas, the I.A. O’Shaughnessy Family Foundation, the Wichita Collegiate
School, the Institute for Humane Studies, The East West Institute and The Bill of Rights Institute, the Timothy P. O’Shaughnessy
Foundation and is a member of the Intercontinental Chapter of Young Presidents Organization and World Presidents’ Organization.



James F. Park has served
as our Chief Executive Officer and as a member of our board of directors since co-founding the Company in 2002. He has extensive
experience in all phases of the upstream oil and gas business, with a strong background in the acquisition, implementation and
management of international joint ventures in North America, South America, Asia, Europe and the Middle East. He holds a degree
in geophysics from the University of California at Berkeley and has worked as a research scientist in earthquake and tectonic at
the University of Texas. In 1978, Mr. Park joined Basic Resources International Limited, an oil and gas exploration company, which
pioneered the development of commercial oil and gas production in Central America. As a senior executive of Basic Resources International
Limited, Mr. Park was closely involved in the development of grass-roots exploration activities, drilling and production operations,
surface and pipeline construction and crude oil marketing and transportation, and with legal and regulatory issues, and raising
substantial investment funds. He remained a member of the board of directors of Basic Resources International Limited until the
company was sold in 1997. Mr. Park is also a member of the board of directors of Energy Holdings and has also been involved in
oil and gas projects in California, Louisiana, Argentina, Yemen and China. Mr. Park is a member of the AAPG and SPE and has lived
in Latin America since 2002.



Carlos Gulisano has been
a member of our board of directors since June 2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate degree
in petroleum engineering and a PhD in geology from the University of Buenos Aires and has authored or co-authored over 40 technical
papers. He is a former adjunct professor at the Universidad del Sur, a former thesis director at the University of La Plata, and
a former scholarship director at CONICET, the national technology research council, in Argentina. Dr. Gulisano is a respected leader
in the fields of petroleum geology and geophysics in South America and has over 35 years of successful exploration, development
and management experience in the oil and gas industry. In addition to serving as an advisor to GeoPark since 2002 and as Managing
Director from February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera Argentina San Jorge S.A. and Chevron San
Jorge S.A. and has led teams credited with significant oil and gas discoveries, including those in the Trapial field in Argentina.
He has worked in Argentina, Bolivia, Peru, Ecuador, Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also
an independent consultant on oil and gas exploration and production.



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Juan Cristóbal Pavez
has been a member of our board of directors since August 2008. He holds a degree in commercial engineering from the Pontifical
Catholic University of Chile and an MBA from the Massachusetts Institute of Technology. He has worked as a research analyst at
Grupo CB and later as a portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, an investment company, as Chief
Executive Officer, where he focused mainly on investments in capital markets and real estate. While at Santana, he was appointed
Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s main assets. In 1999, Mr. Pavez co-founded Eventures,
an internet company. Since 2001, he has served as Chief Executive Officer at Centinela, a company with a diversified global portfolio
of investments, with a special focus in the energy industry, through the development of wind parks and run-of-the-river hydropower
plants. Mr. Pavez is also a board member of Grupo Security, Vida Security and Hidroelétrica Totoral. Over the last few years
he has been a board member of several companies, including Quintec, Enaex, CTI and Frimetal.



Peter Ryalls has been a member
of our board of directors since April 2006. Mr. Ryalls started his career working as a wireline engineer for Schlumberger in West
Africa, returning to the UK in 1976 to study for his Master’s degree in Petroleum Engineering at Imperial College, London
following which he joined Mobil North Sea. He moved to Unocal Corporation in 1979 where he held increasingly senior positions,
including as Managing Director of Unocal UK in Aberdeen, Scotland, and where he developed extensive experience in offshore production
and drilling operations. In 1994, Mr. Ryalls represented Unocal Corporation in the Azerbaijan International Operating Company as
Vice President of Operations and was responsible for production, drilling, reservoir engineering and logistics. In 1998, Mr. Ryalls
became General Manager for Unocal in Argentina. He also served as Vice President of Unocal’s Gulf of Mexico onshore oil and
gas business and as Vice President of Global Engineering and Construction, where he was responsible for the implementation of all
major capital projects ranging from deep water developments in Indonesia and the Gulf of Mexico to conventional oil and gas projects
in Thailand. Mr. Ryalls is also an Independent Petroleum Consultant advising on international oil and gas development projects
both onshore and offshore.



Robert Bedingfield has been
a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a Certified
Public Accountant. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners
with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices,
as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies;
including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen
Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee
Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on
the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. Since 2013,
Mr. Bedingfield has also served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International
Corp (SAIC).



Pedro Aylwin has served as
a member of our board of directors since July 2013 and as our Director of Legal and Governance since April 2011. From 2003 to 2006,
Mr. Aylwin worked for us as an advisor on governance and legal matters. Mr. Aylwin holds a degree in law from the Universidad de
Chile and an LLM from the University of Notre Dame. Mr. Aylwin has extensive experience in the natural resources sector. Mr. Aylwin
is also a partner at the law firm Aylwin, Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where he represented mining, chemical
and oil and gas companies in numerous transactions. From 2006 until 2011, he served as Lead Manager and General Counsel at BHP
Billiton, Base Metals, where he was in charge of legal and corporate governance matters on BHP Billiton’s projects, operations
and natural resource assets in South America, North America, Asia, Africa and Australia.



Michael D. Dingmanis a successful
international investor, businessman and philanthropist, with more than 50 years of experience. Mr. Dingman has an extensive and
successful career on Wall Street as partner of Butnham & Company, and he also was Chairman and Chief Director of industrial
corporations including Wheelabrator-Frye, Signal, AlliedSignal, the Henley Group and Fisher-Scientific. His wide experience in
the energy industry includes working with the Liedtke family of Pennzoil at Pogo Producing Company and as an early investor of
Sidanco, one of Russia’s largest oil companies. Currently, he is Founder, President and CEO of the Shipston Group. Mr.
Dingman is a former director of Ford Motor Company (21 years), Time and then Time Warner (24 years), and the Mellon Bank, Temple
Industries, Temple-Inland, Continental Telephone and Teekay Shipping. He is the founder of the “Michael D. Dingman Center
for Entrepreneurship” at the University of Maryland and he is a benefactor and former member of the Boston Museum of Fine
Arts and the John A. Hartford Foundation.



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Executive officers



Our executive officers are responsible
for the management and representation of our company. The table below sets forth certain information concerning our executive officers.
All ages are as of March 31, 2017.



|Name                   | Position                                                            | Age | At the
        Company since
|---------------------- | ------------------------------------------------------------------- | --- | ----------------------------
|James F. Park          | Chief Executive Officer and Director                                | 61  | 2002                        
|Andrés Ocampo          | Chief Financial Officer                                             | 39  | 2010                        
|Pedro Aylwin Chiorrini | Director, Director of Legal and Governance, and Corporate Secretary | 57  | 2003                        
|Augusto Zubillaga      | Chief Operating Officer                                             | 47  | 2006                        
|Alberto Matamoros      | Director for Argentina, Brazil, Chile and Peru                      | 45  | 2014                        
|Marcela Vaca           | Director for Colombia                                               | 48  | 2012                        
|Carlos Murut           | Director of Development                                             | 60  | 2006                        
|Salvador Minniti       | Director of Exploration                                             | 62  | 2007                        
|Horacio Fontana        | Director of Drilling                                                | 59  | 2008                        
|Agustina Wisky         | Director of Business Management                                     | 40  | 2002                        
|Guillermo Portnoi      | Director of New Business                                            | 41  | 2006                        
|Stacy Steimel          | Director of Shareholder Value                                       | 57  | 2017                        



Biographical information
of the members of our executive officers is set forth below. Unless otherwise indicated, the current business addresses for our
executive officers is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile.



Andrés Ocampo has
served as our Chief Financial Officer since November 2013. He previously served as our Director of Growth and Capital (from January
2011 through October 2013), and has been with our company since July 2010. Mr. Ocampo graduated with a degree in Economics from
the Universidad Católica Argentina. He has more than 16 years of experience in business and finance. Before joining our
company, Mr. Ocampo worked at Citigroup and served as Vice President Oil & Gas and Soft Commodities at Crédit Agricole
Corporate & Investment Bank.



Augusto Zubillaga has served
as our Chief Operating Officer since May 2015. He previously served in other management positions throughout the Company including
as Operations Director, Argentina Director and Production Director. He previously served as our Production Director. He is a petroleum
engineer with more than 23 years of experience in production, engineering, well completions, corrosion control, reservoir management
and field development. He has a degree in petroleum engineering from the Instituto Tecnológico de Buenos Aires. Prior to
joining our company, Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. At Chevron San Jorge
S.A., he led multi-disciplinary teams focused on improving production, costs and safety, and was the leader of the Asset Development
Team, which was responsible for creating the field development plan and estimating and auditing the oil and gas reserves of the
Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San Jorge S.A. team that was responsible for identifying business
opportunities and working with the head office on the establishment of best business practices. He has authored several industry
papers, including papers on electrical submersible pump optimization, corrosion control, water handling and intelligent production
systems.



Alberto Matamoros has been
our Director for Argentina, Brazil, Chile and Peru since March 2016 and Director for Chile since January 2015. He is an industrial
engineer and has an MBA, with more than 20 years of experience in the Oil & Gas industry. He started his career in the Argentinian
oil company ASTRA, as a Production Engineer of La Ventana-Vizcacheras Block in the province of Mendoza (1997-2000). He then joined
Chevron, where he worked as a Production Engineer in El Trapial Block in the province of Neuquén for three years. Later,
he became a Field Engineering Manager, also for three years, in Buenos Aires, and then moved to Kern County, California, to lead
the production team. His experience in Chevron enabled him to manage different technical and administrative teams, designing and
executing working plans focused in the optimization of resources. In 2014, he joined GeoPark to be part of the Corporate Operation
team before being selected as the new Country Manager of GeoPark in Chile. Matamoros holds a degree in Industrial Engineering from
the Universidad Nacional del Sur and an MBA in IAE, from the Business School of Universidad Austral of Buenos Aires, Argentina.



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Marcela Vaca has been our
Director for Colombia since August 2012. Ms. Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá,
Colombia, a Master’s Degree in commercial law from the same university and an LLM from Georgetown University. She has served
in the legal departments of a number of companies in Colombia, including Empresa Colombiana de Carbon Ltda (which later merged
with INGEOMINAS), and from 2000 to 2003, she served as Legal and Administrative Manager at GHK Company Colombia. Prior to joining
our company in 2012, Ms. Vaca served for nine years as General Manager of the Hupecol Group where she was responsible for supervising
all areas of the company as well as managing relationships with Ecopetrol, ANH, the Colombian Ministry of Mines and Energy, the
Colombian Ministry of Environment and other governmental agencies. At the Hupecol Group, Ms. Vaca was also involved in the structuring
of the Hupecol Group’s asset development and sales strategy.



Carlos Murut has been our
Director of Development since January 2012. He previously served as our Development Manager. Mr. Murut holds a master’s degree
in petroleum geology from the University of Buenos Aires where he also undertook postgraduate studies in reservoir engineering,
specializing in field exploitation. He also completed a Business Management Development Program at Austral University. Mr. Murut
has over 40 years of experience working for international and major oil companies, including YPF S.A., Tecpetrol S.A., Petrolera
Argentina San Jorge S.A. and Chevron San Jorge S.A.



Salvador Minniti has been
our Director of Exploration since January 2012. He previously served as our Exploration Manager. He holds a bachelor degree in
geology from National University of La Plata and has a graduate degree from the Argentine Oil and Gas Institute in oil geology.
Mr. Minniti has over 35 years of experience in oil exploration and has worked with YPF S.A., Petrolera Argentina San Jorge S.A.
and Chevron Argentina.



Horacio Fontana has been
our Corporate Drilling Manager since March 2012. He previously served as our Engineer Manager. He holds a degree in civil engineering
from Rosario National University and is also a graduate from the Argentine Oil and Gas Institute, National University of Buenos
Aires, with a specialty in oilfield exploitation and an extensive background in drilling operations. He has recently taken part
in a Management Development Program at IAE Business School of Austral University. Mr. Fontana has over 31 years of drilling experience
in major Argentine companies such as YPF S.A., Petrolera Argentina San Jorge and Chevron.



Agustina Wisky has worked
with our Company since it was founded in November 2002, and has served as our Director of People since 2012 until December 2016
and is currently our Director of Business Management. Mrs. Wisky is a public accountant, and also holds a degree in human resources
from the Universidad Austral—IAE. She has 15 years of experience in the oil industry. Before joining our company, Mrs. Wisky
worked at AES Gener and PricewaterhouseCoopers.



Guillermo Portnoi has worked
with our Company since June 2006 and has been our Director of Business Management since May 2015 until December 2016 and is currently
our Director of New Business. Previously, he also served as our Director of Administration and Finance. Mr. Portnoi is a public
accountant and holds an MBA from Universidad Austral—IAE. He has more than 14 years of experience in the oil industry. Before
joining our company, Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers, where he counted several major
oil companies as his clients.



Stacy Steimel joined GeoPark
in February 2017 as our Shareholder Value Director. Mrs. Steimel has more than 20 years of experience in the financial sector as
Fund Manager and subsequently as regional CEO for PineBridge Investments, ex-AIG Investments in Latin America. Before AIG,
Mrs. Steimel held positions in the US Treasury Department and at the InterAmerican Development Bank. She holds an MBA from
the Pontificia Universidad Católica de Chile, an MA in Latin American Studies from the University of Texas at Austin and
a BA from the College of William and Mary.



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| | B. | Compensation
| | -- | ------------



Executive compensation



For the year ended December 31, 2016, we
accrued or paid approximately US$2.6 million, in the aggregate, to the members of our board of directors (including our executive
directors) for their services in all capacities. During this same period, we accrued or paid approximately US$6.0 million, in the
aggregate, to the members of our senior management (excluding our executive directors) for their services in all capacities. An
amount of US$0.8 million corresponds to the accrual or payment for discretionary bonus payments granted to the Company’s
executive directors based on the Company’s performance in 2016. Recipients of such bonuses were given the opportunity to
receive their bonus payments in shares, cash or a combination of both. Gerald E. O’Shaughnessy, James F. Park and Pedro Aylwin
are our executive directors.



Director Contracts



It is our current policy that executive
directors enter into indefinite term contracts with the Company that may be terminated at any time by either party subject to certain
notice requirements.



Gerald E. O’Shaughnessy has entered
into a service contract with the Company to act as Chairman at an annual salary of US$250,000. James F. Park has entered
into a service contract with the Company to act as Chief Executive Officer at an annual salary of US$500,000. The payment of a
bonus to Mr. O’Shaughnessy or Mr. Park is at our discretion. They each also received equity awards described below under
“Equity Incentive Compensation.” Our agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that restrict
them, for a period of 12 months following termination of employment, from soliciting senior employees of the Company and, for a
period of six months following a termination of employment, from competing with the Company.



Pedro Aylwin, who was appointed as an executive
director in July 2013, has entered into a service contract with the Company to act as Director of Legal and Governance, and as
such has decided to forego his director fees. He instead received in 2016 a salary of approximately US$246,000 and bonus of US$125,000
for his services as a member of senior management.



The following chart summarizes payments
made to our executive directors for the year ended December 31, 2016:



|                        | Cash
        payment                     
|----------------------- | -----------------------------------------
|                        | Executive
        Directors’
        Fees
|Gerald E. O’Shaughnessy | US$250,000                               
|James F. Park           | US$500,000                               



Bonus payments above were approved by the
Compensation Committee in September 2016 and reflect awards for previous years’ performance including the discretionary bonus
payments made based on our performance in 2015.



Non-Executive Director Contracts



The current annual fees paid to our non-executive
Directors correspond to US$80,000 to be settled in cash and US$100,000 to be settled in stock, 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 applies.
A Director who serves as a member of any Board Committees receives an annual fee of US$10,000. Total payment due shall be calculated
on an aggregate basis for Directors serving in more than one Committee. The Chairman fee is not added to the member’s fee
while serving for the same Committee. Payments of Chairmen and Committee members’ fees are made quarterly in arrears and
settled in cash only.



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The following chart summarizes payments
made to our non-executive directors for the year ended December 31, 2016.



|Non-Executive
        Director | Non-Executive
        Directors’ Fees in US$ | Fees
        paid in
        Common Shares (1)
|------------------------------ | -------------------------------------------- | ----------------------------------------------
|Juan Cristóbal Pavez(2)        | 110,000                                      | 32,403                                        
|Peter Ryalls (3)               | 120,000                                      | 32,403                                        
|Carlos Gulisano (4)            | 110,000                                      | 32,403                                        
|Robert Bedingfield (5)         | 100,000                                      | 32,403                                        




| | (1) | The numbers in this column are equal to 129,612 Common Shares (which amount equals to US$400,000).
| | --- | --------------------------------------------------------------------------------------------------



| | (2) | Compensation Committee Chairman and Member of Audit Committee.
| | --- | --------------------------------------------------------------



| | (3) | Technical Committee Chairman, Member of Audit Committee and Member of Compensation Committee.
| | --- | ---------------------------------------------------------------------------------------------



| | (4) | Nomination Committee Chairman and Member of Technical Committee.
| | --- | ----------------------------------------------------------------



| | (5) | Audit Committee Chairman
| | --- | ------------------------



Pension and retirement benefits



We do not maintain any defined benefit
pension plans or any other retirement programs for our employees or directors.



Equity Incentive Compensation



Performance-Based
Employee Long-Term Incentive Program



In November 2007, our shareholders voted
to authorize the board of directors to use up to a maximum of 12% of our issued share capital for the purposes of granting equity
awards to our employees and other service providers. The shareholders also authorized the board of directors to adopt programs
for this purpose and to determine specific conditions and broadly defined guidelines for such programs. Pursuant to this authorization,
we established the Stock Awards Plan and the Value Creation Plan.



Stock Awards Plan



The purpose of the Stock Awards Plan is
to align the interests of our management, employees and key advisors with those of shareholders. Under the Stock Awards Plan, the
board of directors, or its designee, may award options or performance shares. An option confers the right to acquire a specified
number of common shares of the Company at an exercise price equal to the par value of the common shares subject to such an option.
A performance share confers a conditional right to acquire a specified number of common shares for zero or nominal consideration,
subject to the achievement of performance conditions and other vesting terms.



On December 17, 2014, we registered 3,435,600
shares with the U.S. SEC for shares to be issued under the Stock Awards Plan. The following table sets forth the common share awards
granted to our executive directors, management and key employees under the Stock Awards Plan commencing in 2008 through March 2017.



|Number
        of underlying common shares outstanding | Grant
        date | Vesting
        date | Expiration
        date
|------------------------------------------------------ | ------------------ | -------------------- | -----------------------
|976,211(1)                                             | 12/15/2008         | 12/15/2012           | 12/15/2018             
|817,600(1)                                             | 12/15/2010         | 12/15/2014           | 12/15/2020             
|478,000(1)                                             | 12/15/2011         | 12/15/2015           | 12/15/2021             
|720,000(2)                                             | 11/23/2012         | 11/23/2015           | 11/23/2016             
|379,500                                                | 12/15/2012         | 12/15/2016           | 12/15/2022             
|500,000                                                | 12/31/2014         | 12/31/2017           | 12/31/2022             
|1,619,105 (3)                                          | 06/30/2016         | 06/30/2019           | 06/30/2026             




| | (1) | Pedro Aylwin holds 40,000 shares of the 2008 award, 25,000 shares of the 2010 award and 12,000 shares of the 2011 award.
| | --- | ------------------------------------------------------------------------------------------------------------------------



|(2) | James F. Park received 450,000 shares of such awards, and Gerald E. O’Shaughnessy received 270,000 shares of such awards.
|--- | -------------------------------------------------------------------------------------------------------------------------



| | (3) | Vesting of these common share awards was subject to the achievement of certain minimum financial and operational targets during
a performance period that runs through 2016 to 2018. If such conditions are not achieved as of the vesting date, only the equivalent
of one monthly salary will be issued in shares.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





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Our executive directors, senior
management and key employees who have received option awards or common share awards under the Stock Awards Plan authorize the
Company to deposit any common shares they have received under this plan in our Employee Benefit Trust (“EBT”). The
EBT is held to facilitate holdings and dispositions of those common shares by the participants thereof. Under the terms of the
EBT, each participant is entitled to receive any dividends we may pay which correspond to their common shares held by the trust,
according to instructions sent by the Company to the trust administrator. The trust provides that Mr. James F. Park is entitled
to vote all the common shares held in the trust.



Value Creation Plan



On December 10, 2015, the Board of Directors
approved a renewal of the VCP for a new period of three years, with new rewards granted on January 1, 2016. Under the current VCP,
if as of December 31, 2018, our share price has increased by 12% per year according to the plan conditions, VCP participants will
receive awards with an aggregate value equal to 10% of the excess above the market capitalization threshold generated by this share
price (assuming that the share capital of the Company had remained at the same level as applicable at the time of establishment
of the VCP: 59,535,614 shares). The awards will vest and be paid in common shares 50% on December 31, 2018, and the remaining 50%
on December 31, 2019. As in the previous VCP, the total number of common shares granted pursuant to this plan shall not exceed
5% of the issued share capital of the Company.



Non-Executive Director
Plan



In
August 2014, our Board of Directors adopted the Non-Executive Director Plan in order to grant shares to non-executive directors
as part of their compensation program for serving as directors. In accordance with the resolutions adopted by our board of directors
on May 20, 2014, our non-executive directors are paid their quarterly fees in the form of equity awards granted under the Non-Executive
Director Plan. Under the Non-Executive Director Plan, the compensation committee may award common shares, restricted share units
and other share-based awards that may be denominated or payable in common shares or factors that influence the value of common
shares. The maximum number of common shares available for issuance under the Non-Executive Director Plan is 1,000,000 common shares.



Potential dilution
resulting from Equity Incentive Compensation Plans



The percentage of total share capital that
could be awarded to our directors, management and key employees under the Stock Awards Plan and the Non-Executive Director Plan
described above would represent approximately 12% of our issued common shares. In accordance with existing equity compensation
plans as of the date of this annual report, there are approximately 0.49 million shares that could vest until December 31, 2017,
representing approximately 0.82% of our current total issued share capital.



Share Repurchase
Program



On April 5, 2016, we announced that we
would resume our Share Repurchase Program of up to US$10 million of common shares, par value US$0.001 per share. The Share Repurchase
Program began on April 5, 2016 and expired at the close of business on November 11, 2016. The share repurchases may be made from
time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise, and are subject to
market and business conditions, levels of available liquidity, cash requirements for other purposes, regulatory, and other relevant
factors. The shares repurchased will be used to offset, in part, any expected dilution effects resulting from our employee incentive
schemes, including grants under our Stock Award Plan and the Non-Executive Director Plan.



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| | C. | Board practices
| | -- | ---------------



Overview



Our Board of Directors is responsible for
establishing our strategic goals, ensuring that the necessary resources are in place to achieve these goals and reviewing our management
and financial performance. Our board of directors directs and monitors the company in accordance with a framework of controls,
which enable risks to be assessed and managed through clear procedures, lines of responsibility and delegated authority. Our board
of directors also has responsibility for establishing our core values and standards of business conduct and for ensuring that these,
together with our obligations to our shareholders, are understood throughout the company.



Board composition



Our bye-laws and board resolutions provide
that the board of directors consist of a minimum of three and a maximum of nine members. All of our directors were elected at our
annual shareholders’ meeting held on June 30, 2016. Their term expires on the date of our next annual shareholders’
meeting, to be held in 2017. The board of directors meets at least on a quarterly basis.



Committees of our board of directors



Our board of directors has established
an Audit Committee, a Compensation Committee, a Nomination Committee, a Technical Committee and a Disclosure Committee. The composition
and responsibilities of each committee are described below. Members serve on the Audit Committee for a period of three years. For
the Compensation and Nomination Committees, members serve for a period of one year. For the Technical Committee and Disclosures
Committee, members serve on these committees until their resignation or until otherwise determined by our board of directors. In
the future, our board of directors may establish other committees to assist with its responsibilities.



Audit Committee



The Audit Committee is composed of three
directors: Mr. Peter Ryalls, Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield (who currently serves as Chairman of the
committee). We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez and Robert Bedingfield are independent,
as such term is defined under SEC rules applicable to foreign private issuers.



The Audit Committee’s responsibilities
include: (a) approving our financial statements; (b) reviewing financial statements and formal announcements relating to our performance;
(c) assessing the independence, objectivity and effectiveness of our external auditors; (d) making recommendations for the appointment,
re-appointment and removal of our external auditors and approving their remuneration and terms of engagement; (e) implementing
and monitoring policy on the engagement of external auditors supplying non-audit services to us; (f) obtaining, at our expense,
outside legal or other professional advice on any matters within its terms of reference and securing the attendance at its meetings
of outsiders with relevant experience and expertise if it considers it necessary; and (g) reviewing our arrangements for our employees
to raise concerns about possible wrongdoing in financial reporting or other matters and the procedures for handling such allegations,
and ensuring that these arrangements allow proportionate and independent investigation of such matters and appropriate follow-up
action.



Compensation Committee



The Compensation Committee is composed
of three directors. The current members of the compensation committee are Mr. Juan Cristóbal Pavez (who serves as Chairman
of the committee) and Mr. Peter Ryalls. Currently there is a vacancy created by the resignation of Mr. Steve J. Quamme effective
March 19, 2015.



The Compensation Committee meets at least
twice a year, and its specific responsibilities include: (a) recommending to the board of directors, the remuneration policy for
the Chief Executive Officer, the Chairman, our executive directors and other members of executive management; (b) reviewing the
performance of our executive directors and members of executive management; and (c) reviewing all incentive compensation plans,
equity-based plans, and all modifications to such plans as well as administering and granting awards under all such plans and approving
plan payouts; and (d) reviewing and making recommendations to the Board with respect to the adoption or modification of executive
officer and director share ownership guidelines and monitor compliance with any adopted share ownership guidelines.



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Nomination Committee



The Nomination Committee is composed of
three directors. The members of the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. Carlos Gulisano (who serves
as Chairman of the committee) and Mr. Pedro Aylwin.



The Nomination Committee meets at least
twice a year and its responsibilities include: (a) reviewing the structure, size and composition of the board of directors and
making recommendations to the board of directors in respect of any required changes; (b) identifying, nominating and submitting
for approval by the board of directors candidates to fill vacancies on the board of directors as and when they arise; (c) making
recommendations to the board of directors with respect to the membership of the Audit Committee and Compensation Committee in consultation
with the chairman of each committee, and with respect to the appointment of any director or executive officer or other officer
other than the position of the Chairman and Chief Executive Officer and (d) succession planning for directors and senior executives.



Technical Committee



The Technical Committee is composed of
three directors along with the Chief Operating Officer. The members of the Technical Committee are Mr. Peter Ryalls (who serves
as Chairman of the committee), Mr. Carlos Gulisano, Mr. James Park and Mr. Augusto Zubillaga.



The Technical Committee’s responsibilities
include: (a) overseeing the technical studies and evaluations of the Company’s properties and proposals to acquire new properties
and/or relinquish existing ones as well as reviewing project plans; (b) reviewing the Annual Reserve Report, the Company’s
environmental programs and their effectiveness and the Company’s health and safety program and its effectiveness; and (c)
providing a forum for ideas and solutions for the key technical people within the Company.



Disclosure Committee



The Disclosure Committee is composed of
Mr. James Park, Mr. Andrés Ocampo, and certain other officers or managers per request.



The Disclosure Committee’s responsibilities
include (a) review and approval of filings with the SEC and press releases, (b) review of presentations to analysts, investors
and rating agencies and (c) establishment of disclosure controls and procedures.



Liability insurance



We maintain liability insurance coverage
for all of our directors and officers, the level of which is reviewed annually.



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| | D. | Employees
| | -- | ---------



As of December 31, 2016, we had approximately
345 employees, representing a decrease of 2% from December 31, 2015.



The following table sets forth a breakdown
of our employees by geographic segment for the periods indicated.



|          |  | Year
ended December 31,
|--------- |  | -----------------------
|          |  | 2016                   
|Colombia  |  |                        
|Chile     |  |                        
|Brazil    |  |                        
|Argentina |  |                        
|Peru      |  |                        
|Total     |  |                        

From time to time, we also utilize the
services of independent contractors to perform various field and other services as needed. As of December 31, 2016, 35 of our employees
were represented by labor unions or covered by collective bargaining agreements. We believe that relations with our employees are
satisfactory.



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| | E. | Share ownership
| | -- | ---------------



As of March 15, 2017, members of our board
of directors and our senior management held as a group 19,706,042 of our common shares and 33% of our outstanding share capital.



The following table shows the share ownership
of each member of our board of directors and senior management as of March 15, 2017.



|Shareholder                                           |  | Common shares |            | Percentage of outstanding common shares
|----------------------------------------------------- |  | ------------- | ---------- | ---------------------------------------
|Gerald E. O’Shaughnessy(1)                            |  |               | 7,276,649  |                                        
|James F. Park(2)                                      |  |               | 7,891,269  |                                        
|Juan Cristóbal Pavez(3)                               |  |               | 2,951,510  |                                        
|Carlos Gulisano                                       |  |               | 179,923    |                                        
|Michael D. Dingman                                    |  |               | 1,800      |                                        
|Pedro Aylwin                                          |  |               | 220,859    |                                        
|Peter Ryalls                                          |  |               | 109,831    |                                        
|Robert Bedingfield                                    |  |               | 69,843     |                                        
|Augusto Zubillaga                                     |  |               | *          |                                        
|Alberto Matamoros                                     |  |               | *          |                                        
|Marcela Vaca                                          |  |               | *          |                                        
|Dimas Coelho                                          |  |               | *          |                                        
|Carlos Murut                                          |  |               | *          |                                        
|Salvador Minniti                                      |  |               | *          |                                        
|Jose Díaz                                             |  |               | *          |                                        
|Horacio Fontana                                       |  |               | *          |                                        
|Ruben Marconi                                         |  |               | *          |                                        
|Agustina Wisky                                        |  |               | *          |                                        
|Guillermo Portnoi                                     |  |               | *          |                                        
|Andrés Ocampo                                         |  |               | *          |                                        
|Sub-total senior management ownership of less than 1% |  |               | 1,004,358  |                                        
|Total                                                 |  |               | 19,706,042 |                                        




*	Indicates ownership of less
than 1% of outstanding common shares.



| | (1) | Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, The Globe Resources Group
Inc., and other investment vehicles. 6,705,947 of these common shares have been pledged pursuant to lending arrangements.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | 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 1,575,315 common shares held as of March 14, 2017 in the EBT described under “Item
6. Directors, Senior Management and Employees—B. Compensation—Stock Awards Plan.” Although Mr. Park has voting
rights with respect to all the common shares held in the trust, Mr. Park disclaims beneficial ownership over those common shares.
1,073,201 of these common shares have been pledged pursuant to lending arrangements.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (3) | Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected
as being held by Mr. Pavez include 73,706 common shares held by him personally.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





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| |  | 
| |  | 



ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS



| | A. | Major shareholders
| | -- | ------------------



The following table presents the beneficial
ownership of our common shares as of March 15, 2017:



|Shareholder                         |  | Common shares |            | Percentage of outstanding common shares
|----------------------------------- |  | ------------- | ---------- | ---------------------------------------
|James F. Park(1)                    |  |               | 7,891,269  |                                        
|Gerald E. O’Shaughnessy(2)          |  |               | 7,276,649  |                                        
|Manchester Financial Group, L.P.(3) |  |               | 5,080,661  |                                        
|IFC Equity Investments(4)           |  |               | 3,456,594  |                                        
|Juan Cristóbal Pavez(5)             |  |               | 2,951,510  |                                        
|Other shareholders                  |  |               | 33,284,198 |                                        
|Total                               |  |               | 59,940,881 |                                        




| | (1) | 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 1,575,315 common shares held as of March 14, 2017 in the employee benefit trust described
under “Item 6. Directors, Senior Management and Employees—B. Compensation— Stock Awards Plan.” 1,073,201
of these common shares have been pledged pursuant to lending arrangements. The information set forth above and listed in the table
is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC prior to March 31,
2017.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | Held directly and indirectly through GP Investments LLP, GPK Holdings LLC and The Globe Resources Group Inc., and other investment
vehicles. 6,705,947 of these common shares have been pledged pursuant to lending arrangements.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (3) | Held directly and indirectly through Manchester Financial Group, L.P., Manchester Financial Group, Inc., Douglas F. Manchester
and Papa Doug Trust u/t/d/ January 11, 2010. The information set forth above and listed in the table is based solely on the disclosure
set forth in Manchester Financial Group, L.P.’s most recent Schedule 13G filed with the SEC prior to March 31, 2017.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (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 Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being
held by Mr. Pavez include 73,706 common shares held by him personally.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Principal shareholders do not have any
different or special voting rights in comparison to any other common shareholder.



According to our transfer agent, as of
March 27, 2017, we had 35 shareholders registered in the U.S. and there were a total of 19 shareholders of record. Since some of
the shares are held by nominees, the number of shareholders may not be representative of the number of beneficial owners.



| | B. | Related party transactions
| | -- | --------------------------



We have entered into the following transactions
with related parties:



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LGI Chile Shareholders’ Agreements



In 2010, we formed a strategic partnership
with LGI to acquire and develop jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired a 20% equity interest
in GeoPark Chile and a 14% equity interest in GeoPark TdF, for a total consideration of US$148.0 million, plus additional equity
funding of US$18.0 million through 2014. On May 20, 2011, in connection with LGI’s investment in GeoPark Chile, we and LGI
entered into the LGI Chile Shareholders’ Agreements, setting forth our and LGI’s respective rights and obligations
in connection with LGI’s investment in our Chilean oil and gas business. Specifically, the LGI Chile Shareholders’
Agreements provide that the boards of each of GeoPark Chile and GeoPark TdF will consist of four directors; as long as LGI holds
at least 5% of the voting shares of GeoPark Chile or GeoPark TdF, as applicable, LGI has the right to elect one director and such
director’s alternate, while the remaining directors, and alternates, are elected by us. Additionally, the agreements require
the consent of LGI or its appointed director in order for GeoPark Chile or GeoPark TdF, as applicable, to be able to take certain
actions, including, among others: making any decision to terminate or permanently or indefinitely suspend operations in or surrender
our blocks in Chile (other than as required under the terms of the relevant CEOP for such blocks); selling our blocks in Chile
to our affiliates; making any change to the dividend, voting or other rights that would give preference to or discriminate against
the shareholders of these companies; entering into certain related party transactions; and creating a security interest over our
blocks in Chile (other than in connection with a financing that benefits our Chilean subsidiaries). The LGI Chile Shareholders’
Agreements also provide that: (i) if LGI or either Agencia or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark
TdF, as applicable, the transferring shareholder must make an offer to sell those shares to the other shareholder before selling
them to a third party; and (ii) any sale to a third party is subject to tag-along and drag-along rights, and the non-transferring
shareholder has the right to object to a sale to the third-party if it considers such third-party to be not of a good reputation
or one of our direct competitors. We and LGI also agreed to vote our common shares or otherwise cause GeoPark Chile or GeoPark
TdF, as applicable, to declare dividends only after allowing for retentions to meet anticipated future investments, costs and obligations.
See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Agreements with LGI—LGI
Chile Shareholders’ Agreements.”



LGI Colombia Agreements



On December 18, 2012, we, Agencia, GeoPark
Colombia and LGI entered into the LGI Colombia Shareholders’ Agreement and a subscription share agreement, pursuant to which
LGI acquired a 20% interest in GeoPark Colombia SAS. Further, on January 8, 2014, following an internal corporate reorganization
of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark Latin America entered into a new members’
agreement with LGI (“LGI Colombia Members’ Agreement”), that sets out substantially similar rights and obligations
to the LGI Colombia Shareholders’ Agreement in respect of our oil and gas business in Colombia. We refer to the LGI Colombia
Shareholders’ Agreement and the LGI Colombia Members’ Agreement collectively as the LGI Colombia Agreements. The LGI
Colombia Agreements provide that the board of GeoPark Colombia SAS will consist of four directors; as long as LGI holds at least
14% of GeoPark Colombia SAS, LGI has the right to elect one director and such director’s alternate, while the remaining directors,
and alternates, are elected by us. Additionally, the LGI Colombia Agreements require the consent of LGI or the LGI appointed director
for GeoPark Colombia SAS to be able to take certain actions, including, among others: making any decision to terminate or permanently
or indefinitely suspend operations in or surrender our blocks in Colombia (other than as required under the terms of the relevant
concessions for such blocks); creating a security interest over our blocks in Colombia; approving of GeoPark Colombia SAS’s
annual budget and work programs and the mechanisms for funding any such budget or program; entering into any borrowings other than
those provided in an approved budget or incurred in the ordinary course of business to finance working capital needs; granting
any guarantee or indemnity to secure liabilities of parties other than those of our Colombian subsidiaries; changing the dividend,
voting or other rights that would give preference to or discriminate against the shareholders of GeoPark Colombia SAS; entering
into certain related party transactions; and disposing of any material assets other than those provided for in an approved budget
and work program. The LGI Colombia Agreements also provide that: (i) if either we or LGI decide to sell our respective shares in
GeoPark Colombia SAS, the transferring shareholder must make an offer to sell those shares to the other shareholder before selling
those shares to a third party; and (ii) any sale to a third party is subject to tag-along and drag-along rights, and the non-transferring
shareholder has the right to object to a sale to the third-party if it considers such third-party to be not of a good reputation
or one of our direct competitors. We and LGI also agreed to vote our common shares or otherwise cause GeoPark Colombia to declare
dividends only after allowing for retentions for approved work programs and budgets, capital adequacy and tied surplus requirements
of GeoPark Colombia, working capital requirements, banking covenants associated with any loan entered into by GeoPark Colombia
or our other Colombian subsidiaries and operational requirements.



In addition, our agreement with LGI in
Colombia allows us to earn back up to 12% of our equity participation in GeoPark Colombia, following certain recovery factors of
LGI `s initial investments as follows: (i) if the recovery factor is between one and two times, our incremental equity share is
4%; if the recovery factor is between two to three, three to four, four to five, and above five, our incremental equity increases
by an additional 2% each time, for up to a 12%, so that LGI participation could be reduced from current 20% to 8%. Recovery factor
is measured considering realized dividends or other distributions over the original investments



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See “Item 4. Information on the Company—B.
Business Overview—Significant Agreements—Agreements with LGI—LGI Colombia Agreements.”



IFC Subscription and Shareholders’
Agreement



On February 7, 2006, in order to finance
the exploration, development and exploitation of our blocks in Chile and Argentina and the acquisition of additional exploration,
development and exploitation blocks in Latin America, we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Investors,
entered into an agreement (“IFC Subscription and Shareholders’ Agreement”), pursuant to which IFC agreed to subscribe
and pay for 2,507,161 of our common shares, representing approximately 10.5% of our then-outstanding common shares, at an aggregate
subscription price of US$10.0 million (or approximately US$3.99 per common share).



We agreed, for so long as IFC is a shareholder
in the company, among other things, to: ensure that our operations are in compliance with certain environmental and social guidelines;
appoint and maintain a technically qualified individual to be responsible for the environmental and social management of our activities;
maintain certain forms of insurance coverage, including coverage for public liability and director’s and officer’s
liability reasonably acceptable to IFC, and in respect of certain of our operations; not undertake certain prohibited activities;
and ensure that no prohibited payments are made by us or on our or the Lead Investors’ behalf, in respect of our operations.



We also agreed to provide to IFC, within
30 days of the end of the first half of the year, copies of our unaudited consolidated financial statements for the period (prepared
under IFRS), a report on our capital expenditures for the period, a comprehensive report on the progress of the exploration, development
and exploitation of our blocks in Latin America and a statement of all related party transactions during the period, with a certification
by a company officer that these were on an arm’s-length basis; within 90 days of the end of our fiscal year, copies of our
audited consolidated financial statements for the year (prepared under IFRS), a management letter from our auditors in respect
of our financial control procedures, accounting and management information systems and any litigation, an annual monitoring report
confirming compliance with national or local requirements and the environmental and social requirements mandated by the agreement,
a report indicating any payments in the year to any governmental authority in connection with the documents governing our Chilean
and Argentine blocks and certificates of insurance, with a certificate of our insurer confirming that effectiveness of our policies
and payment of all applicable premiums; within 45 days before each fiscal year begins, a proposed annual business plan and budget
for the upcoming year; within 3 days after its occurrence, notification of any incident that had or may reasonably be expected
to have an adverse effect on the environment, health or safety; copies of notices, reports or other communications between us and
our board of directors or shareholders; and, within five days of receipt thereof, copies of any reports, correspondence, documentation
or notices from any third-party, governmental authority or state-owned company that could reasonably be expected to materially
impact our operations. Mr. O’Shaughnessy and Mr. Park have also agreed to procure that shareholders holding 51% of our common
shares cause us to comply with the covenants above.



Executive Directors’ Service Agreements



We have entered into service contracts
with certain of our executive directors. See “Item 6. Directors, Senior Management and Employees—B. Compensation—Executive
compensation—Director Contracts.”



For further information relating to our
related party transactions and balances outstanding as of December 31, 2016, 2015 and 2014, please see Note 32 to our Consolidated
Financial Statements.



| | C. | Interests of Experts and Counsel
| | -- | --------------------------------



Not applicable.



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ITEM 8. FINANCIAL INFORMATION



| | A. | Consolidated statements and other financial information
| | -- | -------------------------------------------------------



Financial statements



See “Item 18. Financial Statements,”
which contains our audited financial statements prepared in accordance with IFRS.



Legal proceedings



From time to time, we 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, we receive notice of environmental, health and safety violations. It
is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial
position and results of operations.



In Brazil, GeoPark Brasil is a party to
a class action filed by the Federal Prosecutor’s Office regarding a concession agreement of exploratory Block PN-T-597, which
the ANP initially awarded GeoPark Brasil in the 12th oil and gas bidding round held in November 2013. The Brazilian Federal Court
issued an injunction against the ANP and GeoPark Brasil in December 2013 that prohibited GeoPark Brasil’s execution of the
concession agreement until the ANP conducted studies on whether drilling for unconventional resources would contaminate the dams
and aquifers in the region. On July 17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession agreement, which
included a clause prohibiting GeoPark Brasil from conducting unconventional exploration activity in the area. Despite the clause
containing the prohibition, the judge in the case concluded that the concession agreement should not be executed. Thus, GeoPark
Brasil requested that the ANP comply with the decision and annul the concession agreement, which the ANP ́s Board did on October
9, 2015. The annulment reverted the status of all parties to the status quo ante, which maintains GeoPark Brasil’s
right to the block.



Dividends and dividend policy



Holders of common shares will be entitled
to receive dividends, if any, paid on the common shares.



We have never declared or paid any cash
dividends on our common shares. We intend to retain all of our future earnings, if any, generated by our operations for the development
and growth of our business. Accordingly, we do not expect to pay cash dividends on our common shares in the foreseeable future.
Because we are a holding company with no direct operations, we will only be able to pay dividends from our available cash on hand
and any funds we receive from our subsidiaries. The terms of our indebtedness may restrict us from paying dividends. Mainly resulting
from the impact of the decline in oil prices, we have recorded accumulated losses amounting to US$260.5 million as of December
31, 2016, which further limits our ability to pay dividends in the foreseeable future.



Under the Bermuda Companies Act, we may
not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable
to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than our liabilities.
We do not presently have any reasonable grounds for believing that, if we were to declare or pay a dividend on our common shares
outstanding, we would thereafter be unable to pay our liabilities as they became due or that the realizable value of our assets
would thereafter be less than our liabilities.



Additionally, any decision to pay dividends
in the future, and the amount of any distributions, is at the discretion of our board of directors and our shareholders, and will
depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors.
See “Item 3. Key Information—D. Risk factors—Risks related to our common shares—We have never declared
or paid, and do not intend to pay in the foreseeable future, cash dividends on our common shares, and, consequently, your only
opportunity to achieve a return on your investment is if the price of our stock appreciates” and “—We are a holding
company dependent upon dividends from our subsidiaries, which may be limited by law and by contract from making distributions to
us, which would affect our financial condition, including the ability to pay dividends on the common shares,” as well as
“Item 10. Additional Information—B. Memorandum of association and bye-laws.”



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| | B. | Significant changes
| | -- | -------------------



A discussion of the significant changes
in our business can be found under “Item 4. Information on the Company—B. Business Overview.”



ITEM 9. THE OFFER AND LISTING



| | A. | Offering and listing details
| | -- | ----------------------------



Not applicable.



| | B. | Plan of distribution
| | -- | --------------------



Not applicable.



| | C. | Markets
| | -- | -------



On February 6, 2014 we completed our initial
public offering and listed our common shares on the NYSE.



Our common shares have been listed on the
NYSE under the symbol “GPRK” since February 7, 2014. They were previously listed on the AIM under the symbol “GPK”
until February 19, 2014, and, from 2009 to 2015 had been admitted to trade on the Santiago Offshore Stock Exchange (Bolsa Offshore
de la Bolsa de Comercio de Santiago).



The table below presents, for the periods
indicated, the annual, quarterly and monthly high and low closing prices (in US$) of our common shares on the NYSE.



|                                                 |  | Common shares  
|------------------------------------------------ |  | ---------------
|                                                 |  | High           
|                                                 |  | (US$ per share)
|Annual price history                             |  |                
|2014 (from February 7 through December 31, 2014) |  |                
|2015                                             |  |                
|2016                                             |  |                
|2017 (through April 6, 2017)                     |  |                
|Quarterly price history                          |  |                
|1st Quarter 2016                                 |  |                
|2nd Quarter 2016                                 |  |                
|3rd Quarter 2016                                 |  |                
|4th Quarter 2016                                 |  |                
|1st Quarter 2017                                 |  |                
|2nd Quarter 2017 (through April 6, 2017)         |  |                
|Monthly price history                            |  |                
|November 2016                                    |  |                
|December 2016                                    |  |                
|January 2017                                     |  |                
|February 2017                                    |  |                
|March 2017                                       |  |                
|April 2017 (through April 6, 2017)               |  |                




Source: NYSE Connect



| | D. | Selling shareholders
| | -- | --------------------



Not applicable.



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| | E. | Dilution
| | -- | --------



Not applicable.



| | F. | Expenses of the issue
| | -- | ---------------------



Not applicable.



ITEM 10. ADDITIONAL INFORMATION



| | A. | Share capital
| | -- | -------------



Not applicable.



| | B. | Memorandum of association and bye-laws
| | -- | --------------------------------------



The following description of our memorandum
of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions
of our memorandum of association and bye-laws.



General



We are an exempted company with limited
liability incorporated under the laws of Bermuda with registration number 33273 from the Registrar of Companies. The rights of
our shareholders will be governed by Bermuda law and by our memorandum of association and bye-laws. Bermuda company law differs
in some material respects from the laws generally applicable to Delaware corporations. Below is a summary of some of those material
differences.



Because the following statements are summaries,
they do not discuss all aspects of Bermuda law that may be relevant to us and to our shareholders.



Share capital and bye-laws



Our share capital consists of common shares
only. Our authorized share capital consists of 5,171,949,000 common shares of par value US$0.001 per share. As of the date of this
annual report, there are 60,028,985 common shares outstanding. All of our issued and outstanding common shares are fully paid and
non-assessable. We also have an employee incentive program, pursuant to which we have granted share awards to our senior management
and certain key employees. See “Item 6. Directors, Senior Management and Employees.”



According to our bye-laws, if our share
capital is divided into different classes of shares, the rights attached to any class (unless otherwise provided by the terms of
issue of the shares of that class) may, whether or not the Company is being wound-up, be varied with the consent in writing of
the holders of at least two-thirds of the issued shares of that class or with the sanction of a resolution passed by a majority
of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum
shall be two persons at least, in person or by proxy, holding or representing one-third of the issued shares of the class. The
rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise
expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further
shares ranking pari passu therewith.



Our bye-laws give our board of directors
the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of
the bye-laws and any resolution of the shareholders to the contrary.



Common shares



Holders of our common shares are entitled
to one vote per share on all matters submitted to a vote of holders of common shares. Subject to preferences that may be applicable
to any issued and outstanding preference shares, holders of common shares are entitled to receive such dividends, if any, as may
be declared from time to time by our board of directors out of funds legally available for dividend payments. Holders of common
shares have no redemption, sinking fund, conversion, exchange or other subscription rights. In the event of our liquidation, the
holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of
our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.



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Board composition



Our bye-laws provide that our board of
directors will determine the maximum size of the board, provided that it shall be not be composed of fewer than three directors.
The maximum number of directors currently allowed is nine directors and our board of directors currently consists of eight directors.



Election and removal of directors



Our bye-laws provide that our directors
shall hold office for such term as the shareholders shall determine or, in the absence of such determination, until the next annual
general meeting or until their successors are elected or appointed or their office is otherwise vacated. Directors whose term has
expired may offer themselves for re-election at each election of the directors.



Under our bye-laws, a director may be removed
by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy
at any general meeting of the shareholders in accordance with the provisions of our bye-laws. Notice convened for the purpose of
removing the director, containing a statement of the intention to do so, must be served on such director not less than 14 days
before the meeting.



Any vacancy created by the removal of a
director at a special general meeting may be filled at that meeting by the election of another director in his or her place or,
in the absence of any such election, by the board of directors. Any other vacancy, including a newly created directorship, may
be filled by our board of directors.



Proceedings of board of directors



Our bye-laws provide that our business
shall be managed by or under the direction of our board of directors. Our board of directors may act by the affirmative vote of
a majority of the directors present at a meeting at which a quorum is present. The quorum necessary for the transaction of business
at meetings of the board of directors shall be the presence of a majority of the board of directors from time to time. Our bye-laws
also provide that resolutions unanimously signed by all directors are valid as if they had been passed at a meeting of the board
duly called and constituted.



Duties of directors



Under Bermuda common law, members of a
board of directors owe a fiduciary duty to the Company to act in good faith in their dealings with or on behalf of the company,
and to exercise their powers and fulfill the duties of their office honestly. This duty has the following essential elements: (1)
a duty to act in good faith in the best interests of the company; (2) a duty not to make a personal profit from opportunities that
arise from the office of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the purpose
for which such powers were intended. The Bermuda Companies Act also imposes a duty on directors of a Bermuda company, to act honestly
and in good faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably
prudent person would exercise in comparable circumstances. In addition, the Bermuda Companies Act imposes various duties on directors
with respect to certain matters of management and administration of the company.



The Bermuda Companies Act provides that
in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that
such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted
honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment,
he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either
wholly or partly, from any liability on such terms as the court may think fit. This provision has been interpreted to apply only
to actions brought by or on behalf of the company against the directors.



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By comparison, under Delaware law, the
business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers,
directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and
deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably
available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees.
The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes
to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears
the burden of rebutting the presumptions afforded to directors by the “business judgment rule.” If the presumption
is not rebutted, the business judgment rule attaches to protect the directors and their decisions. Where, however, the presumption
is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing,
Delaware courts subject directors’ conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat
to corporate control and approval of a transaction resulting in a sale of control of the corporation.



Interested directors



Pursuant to our bye-laws, a director shall
declare the nature of his interest in any contract or arrangement with the company as required by the Bermuda Companies Act. A
director so interested shall not, except in particular circumstances set out in our bye-laws, be entitled to vote or be counted
in the quorum at a meeting in relation to any resolution in which he has an interest, which is to his knowledge, a material interest
(otherwise than by virtue of his interest in shares or debentures or other securities of or otherwise in or through the company).
A director will be liable to us for any secret profit realized from the transaction. In contrast, under Delaware law, such a contract
or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each
case if the material facts as to the interested director’s relationship or interests are disclosed or are known to the disinterested
directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified.
Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal
benefit.



Indemnification of directors and officers



Bermuda law provides generally that a Bermuda
company may indemnify its directors and officers against any loss arising from or liability which by virtue of any rule of law
would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust except in cases where
such liability arises from fraud or dishonesty of which such director or officer may be guilty in relation to the company.



Our bye-laws provide that we shall indemnify
our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, or to recover
any gain, personal profit or advantage to which such director is not legally entitled, and (by incorporation of the provisions
of the Bermuda Companies Act) that we may advance monies to our officers and directors for costs, charges and expenses incurred
by our officers and directors in defending any civil or criminal proceeding against them on the condition that the officers and
directors repay the monies if any allegation of fraud or dishonesty is proved against them provided, however, that, if the Bermuda
Companies Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking ,by or on
behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from
which there is no further right to appeal that such indemnitee is not entitled to be indemnified for such expenses under this Bye-law
or otherwise. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have,
individually or in right of the company, against any of the company’s directors or officers for any act or failure to act
in the performance of such director’s or officers’ duties, except with respect to any fraud or dishonesty, or to recover
any gain, personal profit or advantage to which such director is not legally entitled.



Meetings of shareholders



Under Bermuda law, a company is required
to convene the annual general meeting of shareholders each calendar year, unless the shareholders in a general meeting, elect to
dispense with the holding of annual general meetings. Under Bermuda law and our bye-laws, a special general meeting of shareholders
may be called by the board of directors and may be called upon the requisition of shareholders holding not less than 10% of the
paid-up capital of the company carrying the right to vote at general meetings of shareholders.



Our bye-laws provide that, at any general
meeting of the shareholders, the presence in person or by proxy of two or more shareholders representing in excess of 50% of the
total issued voting shares of the company shall constitute a quorum for the transaction of business unless the company only has
one shareholder, in which case such shareholder shall constitute a quorum. Unless otherwise required by law or by our bye-laws,
shareholder action requires a resolution adopted by a majority of votes cast by shareholders at a general meeting at which a quorum
is present.



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Shareholder proposals



Under Bermuda law, shareholders holding
at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting
to which the requisition relates or any group composed of at least 100 or more shareholders may require a proposal to be submitted
to an annual general meeting of shareholders. Under our bye-laws, any shareholders wishing to nominate a person for election as
a director or propose business to be transacted at a meeting of shareholders must provide (among other things) advance notice,
as set out in our bye-laws. Shareholders may only propose a person for election as a director at an annual general meeting.



Shareholder action by written consent



Our bye-laws provide that, except for the
removal of auditors and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by
the shareholders through the unanimous written consent of the shareholders who would be entitled to vote on the matter at the general
meeting.



Amendment of memorandum of association
and bye-laws



Our memorandum of association and bye-laws
may be amended with the approval of a majority of our board of directors and by a resolution by a majority of the votes cast by
shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance
with the provisions of the bye-laws.



Business combinations



A Bermuda company may engage in a business
combination pursuant to a tender offer, amalgamation, merger or sale of assets. The amalgamation or merger of a Bermuda company
with another company generally requires the amalgamation or merger agreement to be approved by the company’s board of directors
and by its shareholders. Shareholder approval is not required where (a) a holding company and one or more of its wholly-owned subsidiary
companies amalgamate or merge or (b) two or more wholly-owned subsidiary companies of the same holding company amalgamate or merge.
Under the Bermuda Companies Act (save for such “short-form amalgamations”), unless a company’s bye-laws provide
otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass a resolution to approve the amalgamation
or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued
shares of the company. Our bye-laws provide that an amalgamation or merger will require the approval of our board of directors
and of our shareholders by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so)
vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under
Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder
who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder’s
shares may, within one month of the notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the value
of those shares.



Under the Bermuda Companies Act, we are
not required to seek the approval of our shareholders for the sale of all or substantially all of our assets. However, Bermuda
courts will view decisions of the English courts as highly persuasive and English authorities suggest that such sales do require
shareholder approval. Our bye-laws provide that the directors shall manage the business of the Company and may exercise all such
powers as are not, by the Bermuda Companies Act or by these Bye-laws, required to be exercised by the Company in general meeting
and may pay all expenses incurred in promoting and incorporating the company and may exercise all the powers of the Company including,
but not by way of limitation, the power to borrow money and to mortgage or charge all or any part of the undertaking property and
assets (present and future) and uncalled capital of the Company and to issue debentures and other securities, whether outright
or as collateral security for any debt, liability or obligation of the Company or any other persons.



Under Bermuda law, where an offer is made
for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror,
its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer
their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief
(within one month of the compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally,
where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to the
remaining shareholders, acquire the shares of such remaining shareholders. Dissenting shareholders have a right to apply to the
court for appraisal of the value of their shares within one month of the compulsory acquisition notice. If a dissenting shareholder
is successful in obtaining a higher valuation, that valuation must be paid to all shareholders being squeezed out or the purchaser
may cancel the purchase notice sent.



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Dividends and repurchase of shares



Pursuant to our bye-laws, our board of
directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda
law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after
the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than
its liabilities. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that
the company is, or after the repurchase would be, unable to pay its liabilities as they become due.



Shareholder suits



Class actions and derivative actions are
generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit
a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged
to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum
of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute
a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company’s
shareholders than that which actually approved it.



When the affairs of a company are being
conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders
may apply under the Bermuda Companies Act for an order of the Supreme Court of Bermuda, which may make such order as it sees fit,
including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of
any shareholders by other shareholders or by the company.



Our bye-laws contain a provision through
which we and our shareholders waive any claim or right of action that we or they have, both individually and on our behalf, against
any director or officer in relation to any action or failure to take action by such director or officer, including the breach of
any fiduciary duty, except in respect of any fraud or dishonesty of such director or officer.



Comparison of Bermuda law to Delaware
corporate law



Bermuda law differs from the laws in
effect in the United States and might afford less protection to shareholders.



Our shareholders could have more difficulty
protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda
company, we are governed by our memorandum of association and bye-laws and Bermuda company law. The provisions of the Bermuda Companies
Act, which applies to us, differs in some material respects from laws generally applicable to U.S. corporations and shareholders,
including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification
of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which
differ in certain respects from provisions of Delaware corporate law. Our shareholders approved the adoption of new bye-laws which
came into effect on February 19, 2014, being the date on which the company cancelled admission of its common shares on AIM. Because
the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders.



Interested Directors. Under our
bye-laws and the Bermuda Companies Act, a director shall declare the nature of his interest in any contract or arrangement with
the company. Our bye-laws further provide that a director so interested shall not, except in particular circumstances, be entitled
to vote or be counted in the quorum at a meeting in relation to any resolution in which he has an interest, which is to his knowledge,
a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of or otherwise in or
through the company). A director will be liable to us for any secret profit realized from the transaction. See “Item 10—B.
Memorandum of association and bye-laws—Interested Directors.”



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Amalgamations, Mergers and Similar Arrangements.
Pursuant to the Bermuda Companies Act, the amalgamation or merger of a Bermuda company with another company or corporation requires
the amalgamation or merger agreement to be approved by the company’s board of directors and, under certain circumstances,
by its shareholders. Under our bye-laws, an amalgamation or merger will require the approval of our board of directors and our
shareholders by Special Resolution, which is a resolution adopted by 65% of more of the votes cast by shareholders who (being entitled
to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws
and the quorum for any general meeting must be two or more persons, in person or by proxy, representing in excess of 50% of the
total of our issued voting shares. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another
company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation or merger and who is
not satisfied that he has been offered fair value for his shares may, within one month of notice of the shareholders meeting, apply
to the Supreme Court of Bermuda to appraise the fair value of those shares.



Under Delaware law, with certain exceptions,
a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors
and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation
participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant
to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined
by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.



Shareholders’ Suit. Class
actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would
ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company
where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation
of the company’s memorandum of association or bye-laws. When the affairs of a company are being conducted in a manner which
is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply for an order
of the Supreme Court of Bermuda regulating the conduct of the company’s affairs in the future or an order to purchase the
shares of any shareholders by other shareholders or by the company and, in the case of a purchase by the company, for the reduction
accordingly of the company’s capital, or otherwise. See “Item 10—B. Memorandum of association and bye-laws—Shareholder
Suits.”



Our bye-laws contain a provision by virtue
of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against
any director or officer in relation to any action or failure to take action by such director or officer, including the breach of
any fiduciary duty, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions
generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and
actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover
attorneys’ fees incurred in connection with such action.



Indemnification of Directors. We
may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching
to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director
or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. See “Item 10—B.
Memorandum of association and bye-laws—Enforcement of Judgments.” Our bye-laws provide that we shall indemnify our
officers and directors in respect of their acts and omissions, except in respect of their fraud or dishonesty, or to recover any
gain, personal profit or advantage to which such Director is not legally entitled, and (by incorporation of the provisions of the
Bermuda Companies Act) that we may advance money to our officers and directors for the costs, charges and expenses incurred by
our officers and directors in defending any civil or criminal proceedings against them on condition that the directors and officers
repay the money if any allegations of fraud or dishonesty is proved against them provided, however, that, if the Bermuda Companies
Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking, by or on behalf of
such indemnitee, to repay all amounts if it shall ultimately be determined by final decision that such indemnitee is not entitled
to be indemnified for such expenses under our Bye-laws or otherwise. Under Delaware law, a corporation may indemnify a director
or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement
actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer
acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation
and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his or her
conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors.



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As a result of these differences, investors
could have more difficulty protecting their interests than would shareholders of a corporation incorporated in the United States.



Tax matters. Under current Bermuda
law, we are not subject to tax on income or capital gains. We have received from the Minister of Finance under The Exempted Undertaking
Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits,
income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, then the imposition of
any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March
31, 2035. We could be subject to taxes in Bermuda after that date. This assurance is subject to the provision that it is not to
be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent
the application of any tax payable in accordance with the provisions of the Land Tax Act 1967 or otherwise payable in relation
to any property leased to us. We are incorporated in Bermuda as an exempted company and pay annual Bermuda government fees. In
addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable,
directly or indirectly, to the Bermuda government. Neither we nor our Bermuda subsidiaries employ individuals in Bermuda as at
the date of this annual report.



Access to books and records and dissemination
of information



Members of the general public have a right
to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents
include the company’s memorandum of association and any amendments thereto. The shareholders have the additional right to
inspect the bye-laws of the company, minutes of general meetings of shareholders and the company’s audited financial statements.
The company’s audited financial statements must be presented at the annual general meeting of shareholders, unless the board
and all the shareholders agree to the waiving of the audited financials. The company’s share register is open to inspection
by shareholders and by members of the general public without charge. A company is required to maintain its share register in Bermuda
but may, subject to the provisions of the Bermuda Companies Act, establish a branch register outside of Bermuda. Bermuda law does
not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.



Registrar or transfer agent



A register of holders of the common shares
is maintained by Coson Corporate Services Limited in Bermuda, and a branch register is maintained in the United States by Computershare
Trust Company, N.A., who serves as branch registrar and transfer agent.



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Enforcement
of Judgments



We are incorporated as an exempted company
with limited liability under the laws of Bermuda, and substantially all of our assets are located in Colombia, Chile, Brazil, Peru
and Argentina. In addition, most of our directors and executive officers reside outside the United States, and all or a substantial
portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors to
effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts
against us or those persons based on the civil liability provisions of the U.S. securities laws.



There is no treaty in force between the
United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters.
As a result, whether a U.S. judgment would be enforceable in Bermuda against us or our directors and officers depends on whether
the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and
officers, as determined by reference to Bermuda conflict of law rules and the judgment is not contrary to public policy in Bermuda,
has not been obtained by fraud in proceedings contrary to natural justice and is not based on an error in Bermuda law. A judgment
debt from a U.S. court that is final and for a sum certain based on U.S. federal securities laws will not be enforceable in Bermuda
unless the judgment debtor had submitted to the jurisdiction of the U.S. court, and the issue of submission and jurisdiction is
a matter of Bermuda (not U.S.) law.



An action brought pursuant to a public
or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign
capacity, may not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including
certain remedies under U.S. federal securities laws, may not be available under Bermuda law or enforceable in a Bermuda court,
as they may be contrary to Bermuda public policy. Further, no claim may be brought in Bermuda against us or our directors and officers
in the first instance for violations of U.S. federal securities laws because these laws have no extraterritorial jurisdiction under
Bermuda law and do not have force of law in Bermuda. A Bermuda court may, however, impose civil liability on us or our directors
and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. However, section
281 of the Bermuda Companies Act allows a Bermuda court, in certain circumstances, to relieve officers and directors of Bermuda
companies of liability for acts of negligence, breach of duty or trust or other defaults.



Section 98 of the Bermuda Companies Act
provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue
of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust,
except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in
relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors
against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in
their favor or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda
Companies Act.



Our bye-laws contain provisions whereby
we and our shareholders waive any claim or right of action that we have, both individually and on our behalf, against any director
or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty
of such director or officer. We may also indemnify our directors and officers in their capacity as directors and officers for any
loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of trust
of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. We
have entered into customary indemnification agreements with our directors.



No treaty exists between the United States
and Chile for the reciprocal recognition and enforcement of foreign judgments. Chilean courts, however, have enforced valid and
conclusive judgments for the payment of money rendered by competent U.S. courts by virtue of the legal principles of reciprocity
and comity, subject to review in Chile of the U.S. judgment in order to ascertain whether certain basic principles of due process
and public policy have been respected, without retrial or review of the merits of the subject matter. If a U.S. court grants a
final judgment, enforceability of this judgment in Chile will be subject to obtaining the relevant exequatur (i.e., recognition
and enforcement of the foreign judgment) according to Chilean civil procedure law in effect at that time, and depending on certain
factors (the satisfaction or non-satisfaction of which would be determined by the Supreme Court of Chile). Currently, the most
important of such factors are: the existence of reciprocity (if it can be proved that there is no reciprocity in the recognition
and enforcement of the foreign judgment between the United States and Chile, that judgment would not be enforced in Chile); the
absence of any conflict between the foreign judgment and Chilean laws (excluding for this purpose the laws of civil procedure)
and Chilean public policy; the absence of a conflicting judgment by a Chilean court relating to the same parties and arising from
the same facts and circumstances; the Chilean court’s determination that the U.S. courts had jurisdiction, that process was
appropriately served on the defendant and that the defendant was afforded a real opportunity to appear before the court and defend
its case; and the judgment being final under the laws of the country in which it was rendered. Nonetheless, we have been advised
by our Chilean counsel that there is doubt as to the enforceability in original actions in Chilean courts of liabilities predicated
solely upon U.S. federal or state securities laws.



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| | C. | Material contracts
| | -- | ------------------



See “Item 4. Information on the Company—B.
Business Overview—Significant Agreements.”



| | D. | Exchange controls
| | -- | -----------------



Not applicable.



| | E. | Taxation
| | -- | --------



The following summary contains a description
of certain Bermudian, U.S. federal income, and Chilean tax consequences of ownership and disposition of our common shares. The
summary is based upon the tax laws of Bermuda, the United States, and Chile, and regulations thereunder as of the date hereof,
which are subject to change.



Bermuda tax consideration



At the date of this annual report, there
is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable
by us or by our shareholders in respect of our common shares. We have obtained an assurance from the Minister of Finance of Bermuda
under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing
any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate
duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our common
shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable
by us in respect of real property owned or leased by us in Bermuda. We pay annual Bermuda government fees.



Material U.S. federal income tax considerations



The following is a description of the material
U.S. federal income tax consequences to U.S. Holders (as defined below) of owning and disposing of our common shares. This discussion
is not a comprehensive description of all tax considerations that may be relevant to a particular person’s decision to hold
our common shares. This discussion applies only to a U.S. Holder that holds our common shares as capital assets for tax purposes.
In addition, it does not describe all of the tax consequences that may be relevant in light of the U.S. Holder’s particular
circumstances, including alternative minimum tax and Medicare contribution tax consequences and differing tax consequences applicable
to a U.S. Holder subject to special rules, such as:



| | · | certain financial institutions;
| | - | -------------------------------



| | · | a dealer or trader in securities who uses a mark-to-market method of tax accounting;
| | - | ------------------------------------------------------------------------------------



| | · | a person holding common shares as part of a straddle, wash sale or conversion transaction or entering into a constructive sale
with respect to the common shares;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a person whose functional currency for U.S. federal income tax purposes is not the US$;
| | - | ---------------------------------------------------------------------------------------



| | · | a partnership or other entities classified as partnerships for U.S. federal income tax purposes;
| | - | ------------------------------------------------------------------------------------------------



| | · | a tax-exempt entity, including an “individual retirement account” or “Roth IRA;”
| | - | --------------------------------------------------------------------------------



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| | · | a person that owns or is deemed to own 10% or more of our voting stock;
| | - | -----------------------------------------------------------------------



| | · | a person who acquired our shares pursuant to the exercise of an employee stock option or otherwise as compensation; or
| | - | ----------------------------------------------------------------------------------------------------------------------



| | · | a person holding common shares in connection with a trade or business conducted outside of the United States.
| | - | -------------------------------------------------------------------------------------------------------------



If an entity that is classified as a partnership
for U.S. federal income tax purposes holds common shares, the U.S. federal income tax treatment of a partner will generally depend
on the status of the partner and the activities of the partnership. Partnerships holding common shares and partners in such partnerships
should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares.



This discussion is based on the Internal
Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary
and proposed Treasury regulations, all as of the date hereof, any of which is subject to change, possibly with retroactive effect.
U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning
and disposing of our common shares in their particular circumstances.



A “U.S. Holder” is a beneficial
owner of our common shares for U.S. federal income tax purposes that is:



| | · | a citizen or individual resident of the United States;
| | - | ------------------------------------------------------



| | · | a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any
state therein or the District of Columbia; or
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.
| | - | -----------------------------------------------------------------------------------------------------------



This discussion assumes that we are not,
and will not become, a passive foreign investment company, as described below.



Taxation of distributions



Distributions paid on our common shares,
other than certain pro rata distributions of common shares, will generally be treated as dividends to the extent paid out
of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not
maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions will
generally be reported to U.S. Holders as dividends. Dividends paid by qualified foreign corporations to certain non-corporate U.S.
Holders may be taxable at favorable rates. A foreign corporation is treated as a qualified foreign corporation with respect to
dividends paid on stock that is readily tradable on a securities market in the United States, such as the NYSE where our common
shares are traded. Non-corporate U.S. Holders should consult their tax advisers to determine whether the favorable rate will apply
to dividends they receive and whether they are subject to any special rules that limit their ability to be taxed at this favorable
rate.



A dividend generally will be included in
a U.S. Holder’s income when received, will be treated as foreign-source income to U.S. Holders and will not be eligible for
the dividends-received deduction generally available to U.S. corporations under the Code with respect to dividends paid by domestic
corporations.



Sale or other taxable disposition of common
shares



Gain or loss realized on the sale or other
taxable disposition of our common shares will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder
held our common shares for more than one year. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential
rates. The deductibility of capital losses is subject to limitations. The amount of the gain or loss will equal the difference
between the U.S. Holder’s tax basis in the common shares disposed of and the amount realized on the disposition. If a Chilean
tax is withheld on the sale or disposition of the common shares, a U.S. Holder’s amount realized will include the gross amount
of the proceeds of the sale or disposition before deduction of the Chilean tax. See “—Chilean tax on transfers of shares”
for a description of when a disposition may be subject to taxation by Chile. This gain or loss will generally be U.S.-source gain
or loss for foreign tax credit purposes. U.S. Holders should consult their tax advisers as to whether the Chilean tax on gains
may be creditable against the U.S. Holder’s U.S. federal income tax on foreign-source income from other sources.



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Passive foreign investment company rules



We believe that we were not a “passive
foreign investment company,” or PFIC, for U.S. federal income tax purposes for 2016, and we do not expect to be a PFIC in
the foreseeable future. However, because the composition of our income and assets will vary over time, there can be no assurance
that we will not be a PFIC for any taxable year. The determination of whether we are a PFIC is made annually and is based upon
the composition of our income and assets (including the income and assets of, among others, entities in which we hold at least
a 25% interest), and the nature of our activities.



If we were a PFIC for any taxable year
during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain
pledges) of our common shares would generally be allocated ratably over the U.S. Holder’s holding period for the common shares.
The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed
as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals
or corporations for that year, as appropriate, and an interest charge would be imposed on the tax on such amount. Further, to the
extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions
on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, that distribution
would be subject to taxation in the same manner as gain, as described immediately above. Certain elections may be available that
would result in alternative treatments (such as mark-to-market treatment) of our common shares. U.S. Holders should consult their
tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative
treatments would be in their particular circumstances.



Information reporting and backup withholding



Payments of dividends and sales proceeds
that are made within the United States or through certain U.S.-related financial intermediaries generally are subject to information
reporting, and may be subject to backup withholding, unless (1) the U.S. Holder is a corporation or other exempt recipient or (2)
in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not
subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit
against the U.S. Holder’s U.S. federal income tax liability and may entitle it to a refund, provided that the required information
is timely furnished to the Internal Revenue Service.



Chilean tax on transfers of shares



In September 2012, Article 10 of the Chilean
Income Tax Law Decree Law No. 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes on the indirect transfer
of shares, equity rights, interests or other rights in the equity, control or profits of a Chilean entity as well as transfers
of other assets and property of permanent establishments or other businesses in Chile. The 2014 tax reform introduced a measure
which obliges the company from which shares are transferred to pay taxes if the entity which undertakes the transfer of shares
fails to do so.



The indirect transfer rules apply to sales
of shares of an entity:



| | · | If such entity is an offshore holding company located in a black-listed tax haven jurisdiction as determined by Chilean tax
law, or a black-listed jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean resident holds 5% or more
of such entity, or such entity’s rights to equity, control or profits, or 50% or more of such entity’s rights to equity
or profits are held by residents in black-listed jurisdictions; or
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | the shares or rights transferred represent 10% or more of the offshore holding company (considering dispositions by related
persons and over the preceding 12-month period) and the underlying Chilean Assets indirectly transferred, in the proportion indirectly
owned by the seller, (a) are valued in an amount equal to or higher than UTA 210,000 (approximately US$200 million) (adjusted by
the Chilean inflation unit of reference) or (b) represent 20% or more of the market value of the interest held by such seller in
such offshore holding company.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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As a result of these rules, a capital gain
tax of 35% will be applied by the Chilean tax authorities to the sale of any of our common shares if either of the above alternatives
are met. This rate might be subject to change in the short term, as discussed herein.



The 35% rate is calculated pursuant to
one of the following methods, as determined by the seller:



| | · | the sale price of the shares minus the acquisition cost of such shares, multiplied by the percentage or proportion of the part
of the underlying Chilean Assets’ fair market value (which assets are deemed to be “indirectly transferred” by
virtue of the sale of shares) to the fair market value of the shares of the seller; or
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | the portion of the sales price of the shares equal to the proportion of the fair market value of the underlying Chilean Assets,
minus the corresponding proportion in the tax cost of such Chilean Assets for the corresponding holding entity.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



However, the seller may opt to be taxed
as if the underlying Chilean Assets had been sold directly in which case a different set of tax rules may apply.



The tax is payable by the seller of the
shares; however, the buyer shall make a provisional withholding unless the seller declares and pays the tax within the month following
the sale, payment, remittance or it is credited into its account or is put at its disposal. Also, if the seller fails to declare
and pay this tax, and the buyer has not complied with its withholding obligations, the Chilean tax authority (Servicio de Impuestos
Internos) may charge such tax directly to any of them. In addition, the Chilean tax authority may require us, the seller, the
buyer, or its representative in Chile, to file an affidavit with the information necessary to assess this tax.



Based on information available to us, (i)
no Chilean resident holds 5% or more of our rights to equity, control or profits; or (ii) residents in black-listed jurisdictions
hold 50% or more of our rights to equity, control or profits. Therefore, we do not believe the indirect transfer rules will apply
to transfers of our common shares, unless the shares or rights transferred represent 10% or more of the company and the other conditions
described above are met (considering dispositions by related persons and over the preceding 12-month period).



However, there can be no assurance that,
at any time in the future, a Chilean resident will not hold 5% or more of our rights to equity, control or profits or that residents
in black-listed jurisdictions will not hold 50% or more of our rights to equity, control or profits. If this were to occur, all
sales of our common shares would be subject to the indirect transfer tax referred to above.



Our expectations regarding the indirect
transfer rules are based on our understandings, analysis and interpretation of these enacted indirect transfer rules, which are
subject to additional interpretation and rule-making by the Chilean authorities. As such, there is uncertainty relating to the
application by Chilean authorities of the indirect transfer rules on us.



See “Item 3. Key Information—D.
Risk Factors—Risks related to our common shares—The transfer of our common shares may be subject to capital gains taxes
pursuant to indirect transfer rules in Chile.”



| | F. | Dividends and paying agents
| | -- | ---------------------------



Not applicable.



| | G. | Statement by experts
| | -- | --------------------



Not applicable.



| | H. | Documents on display
| | -- | --------------------



We are subject to the informational requirements
of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, including annual reports
on Form 20-F and reports on Form 6-K. You may inspect and copy reports and other information filed with the SEC at the Public Reference
Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by
calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that contains reports and other information
about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov.



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| | I. | Subsidiary information
| | -- | ----------------------



Not applicable.



ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK



We are exposed to a variety of market risks,
including commodity price risk, interest rate risk, currency risk and credit (counterparty and customer) risk. The term “market
risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency
exchange rates.



For further information on our market risks,
please see Note 3 to our Consolidated Financial Statements.



ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES



| | A. | Debt securities
| | -- | ---------------



Not applicable.



| | B. | Warrants and rights
| | -- | -------------------



Not applicable.



| | C. | Other securities
| | -- | ----------------



Not applicable.



| | D. | American Depositary Shares
| | -- | --------------------------



Not applicable.



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PART II



ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES



| | A. | Defaults
| | -- | --------



No matters to report.



| | B. | Arrears and delinquencies
| | -- | -------------------------



No matters to report.



ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY
HOLDERS AND USE OF PROCEEDS



Not applicable.



ITEM 15. CONTROLS AND PROCEDURES



| | A. | Disclosure Controls and Procedures
| | -- | ----------------------------------



As of December 31, 2016, under the supervision
and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an
evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e)
under the Exchange Act). There are inherent limitations to the effectiveness of any disclosure controls and procedures system,
including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures
can provide only reasonable assurance of achieving their control objectives.



Based on such evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to provide reasonable assurance
that the information we are required to disclose in the reports we file or submit under the Exchange Act is (1) recorded, processed,
summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and communicated
to our management to allow timely decisions regarding required disclosures.



| | B. | Management’s Annual Report on Internal Control
over Financial Reporting
| | -- | -----------------------------------------------------------------------



Our management is responsible for establishing
and maintaining an adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.



Our internal control over financial reporting
is a process designed by, or under the supervision of, our principal executive and principal financial officers, management and
other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial
statements for external reporting purposes, in accordance with generally accepted accounting principles. These include those policies
and procedures that:



| | · | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions
of our assets;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------



| | · | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements, in
accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance
with authorization of our management and directors; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our
assets that could have a material effect on our financial statements.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting
cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projections of, and any evaluation
of effectiveness of the internal controls in future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



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Under the supervision and with the participation
of our management, including our Chief Executive Officer, our Chief Financial Officer, and our Director of Legal and Governance,
we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016, based
on the criteria established in Internal Control - Integrated Framework of the Committee of Sponsoring Organizations of the Treadway
Commission (2013).



Based on this assessment, management believes
that, as of December 31, 2016, its internal control over financial reporting was effective based on those criteria.



| | C. | Attestation Report of the Registered Public Accounting
Firm
| | -- | -----------------------------------------------------------



Not applicable.



| | D. | Changes in Internal Control over Financial Reporting
| | -- | ----------------------------------------------------



There
have been no changes in our internal control over financial reporting during the period covered by this annual report on Form 20-F
that have materially affected or reasonably likely to materially affect our internal control over financial reporting.



ITEM 16. RESERVED



ITEM 16A. Audit committee financial expert



We have determined that Mr. Peter Ryalls,
Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield are independent, as such term is defined under SEC rules applicable
to foreign private issuers. In addition, Mr. Robert Bedingfield and Mr. Juan Cristobal Pavez are regarded as audit committee financial
experts.



ITEM 16B. Code of Conduct



We have adopted a code of conduct applicable
to the board of directors and all employees. Since its effective date on September 24, 2012, we have not waived compliance with
or amended the code of conduct.



ITEM 16C. Principal Accountant Fees and Services



Amounts billed by PwC for audit and other
services were as follows:



|                |  | 2016                 |      | 2015
|--------------- |  | -------------------- | ---- | ----
|                |  | (in millions of US$)
|Audit fees      |  |                      | 0.49 |     
|Tax fees        |  |                      | 0.13 |     
|Other fees paid |  |                      | —    |     
|Total           |  |                      | 0.62 |     



Audit Fees



Audit fees are fees billed for professional
services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that
are normally provided by the accountant in connection with statutory and regulatory filings or engagements for those fiscal years.
It includes the audit of our Consolidated Financial Statements and other services that generally only the independent accountant
reasonably can provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with
the SEC.



Audit-Related Fees



Audit-related fees are fees billed for
assurance and related services that are reasonably related to the performance of the audit or review of our Consolidated Financial
Statements and not reported under the previous category. These services would include, among others: accounting consultations and
audits in connection with acquisitions, internal control reviews, attest services that are not required by statue or regulation
and consultation concerning financial accounting and reporting standards.



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Tax Fees



Tax fees are fees billed for professional
services for tax compliance, tax advice and tax planning.



Pre-Approval Policies and Procedures



Following the listing of our common shares
on the NYSE, the Audit Committee proposes the appointment of the independent auditor to the Board to be put to shareholders for
approval at the Annual General meeting. The committee oversees the auditor selection process for new auditors and ensures key partners
in the appointed firm are rotated in accordance with best practices. Also, following our NYSE listing, the Audit Committee is required
to pre-approve the audit and non-audit fees and services performed by the Company’s auditors in order to be sure that the
provision of such services does not impair the audit firm’s independence.



All of the audit fees, audit-related fees
and tax fees described in this item 16C have been approved by the Audit Committee.



ITEM 16D. Exemptions from the listing standards for audit
committees



None.



ITEM 16E. Purchases of equity securities by the issuer
and affiliated purchasers



The following table reflects purchases
of our common shares by or on behalf of us or by any affiliated purchaser in 2016.



|2016 |                             | Total number of common shares purchased |  | Average price paid per common share (US$) |         | Total number of common shares purchased as part of publicly announced plans or programs |  | Maximum number (or approximate dollar value) of common shares that may yet be purchased under the plans or programs
|---- | --------------------------- | --------------------------------------- |  | ----------------------------------------- | ------- | --------------------------------------------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------
|     | January 1 to January 31     |                                         |  |                                           | -       |                                                                                         |  |                                                                                                                    
|     | February 1 to February 28   |                                         |  |                                           | -       |                                                                                         |  |                                                                                                                    
|     | March 1 to March 31         |                                         |  |                                           | -       |                                                                                         |  |                                                                                                                    
|     | April 1 to April 30         |                                         |  |                                           | 7,432   |                                                                                         |  |                                                                                                                    
|     | May 1 to May 31             |                                         |  |                                           | 6,179   |                                                                                         |  |                                                                                                                    
|     | June 1 to June 30           |                                         |  |                                           | 257,528 |                                                                                         |  |                                                                                                                    
|     | July 1 to July 31           |                                         |  |                                           | 136,360 |                                                                                         |  |                                                                                                                    
|     | August 1 to August 31       |                                         |  |                                           | 29,780  |                                                                                         |  |                                                                                                                    
|     | September 1 to September 30 |                                         |  |                                           | 35,100  |                                                                                         |  |                                                                                                                    
|     | October 1 to October 31     |                                         |  |                                           | 86,489  |                                                                                         |  |                                                                                                                    
|     | November 1 to November 30   |                                         |  |                                           | 30,000  |                                                                                         |  |                                                                                                                    
|     | December 1 to December 31   |                                         |  |                                           | -       |                                                                                         |  |                                                                                                                    
|     | Total                       |                                         |  |                                           | 588,868 |                                                                                         |  |                                                                                                                    





In December 2015, the Board of Directors
approved a program to repurchase up to US$10 million of common shares, par value US$0.001 per share of the Company. This Repurchase
Program began on December 19, 2014 and expired on August 18, 2015. The Shares repurchased are 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.



On April 5, 2016, we announced that we
would resume our repurchase program of up to US$10 million of common shares, par value US$0.001 per share. The Repurchase Program
resumed on April 5, 2016 and expired on August 10, 2016. The shares repurchased were used to offset, in part, any dilution effects
resulting from our employee incentive schemes, including grants under our Stock Award Plan and the Limited Non-Executive Director
Plan.



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On September 19, 2016, we announced that
we would resume our repurchase program of up to US$10 million of common shares, par value US$0.001 per share. The Repurchase Program
resumed on September 19, 2016 and expired on November 13, 2016. The shares repurchased were used for grants from our employee incentive
schemes, including grants under our Stock Award Plan and the Limited Non-Executive Director Plan.



ITEM 16F. Change in registrant’s certifying accountant



Not applicable.



ITEM 16G. Corporate governance



Our common shares are listed on the NYSE.
We are therefore required to comply with certain of the NYSE’s corporate governance listing standards (“NYSE Standards”).
As a foreign private issuer, we may follow our home country’s corporate governance practices in lieu of most of the NYSE
Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt
in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary
of those differences is provided as follows.



Director independence



The NYSE Standards require a majority of
the membership of NYSE-listed company boards to be composed of independent directors. Neither Bermuda law, the law of our country
of incorporation, nor our memorandum of association or bye-laws require a majority of our board to consist of independent directors.



Non-management directors’ executive
sessions



The NYSE Standards require non-management
directors of NYSE-listed companies to meet at regularly scheduled executive sessions without management. Our memorandum of association
and bye-laws do not require our non-management directors to hold such meetings.



Committee member composition



The NYSE Standards require domestic NYSE-listed
domestic companies to have a nominating/corporate governance committee and a compensation committee that are composed entirely
of independent directors. Bermuda law, the law of our country of incorporation, does not impose similar requirements.



Independence of the compensation committee
and its advisers



On January 11, 2013, the SEC approved NYSE
listing standards that require that the board of directors of a domestic listed company consider two factors (in addition to the
existing general independence tests) in the evaluation of the independence of compensation committee members: (i) the source of
compensation of the director, including any consulting, advisory or other compensatory fees paid by the listed company, and (ii)
whether the director has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate
of a subsidiary of the listed company. In addition, before selecting or receiving advice from a compensation consultant or other
adviser, the compensation committee of a listed company will be required to take into consideration six specific factors, as well
as all other factors relevant to an adviser’s independence.



Foreign private issuers such as us will
be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we
will not be required to implement the NYSE listing standards relating to compensation committees of domestic listed companies.
All of the members of our compensation committee are independent, and the charter of our compensation committee does not require
the compensation committee to consider the independence of any advisers that assist them in fulfilling their duties.



Additional audit committee functions



The NYSE standards require that audit committees
of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements,
engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary.
For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order
to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review
a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these
procedures. Finally, audit committees are responsible for designing and implementing an internal audit function that assesses the
company’s risk management processes and systems of internal control on an ongoing basis.



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Foreign private issuers such as us are
exempt from these additional requirements if home country practice is followed. Bermuda law does not impose similar requirements,
and consequently, our audit committee does not perform these additional functions. Our Audit Committee is composed exclusively
of independent auditors.



Miscellaneous



In addition to the above differences, we
are not required to: make our audit and compensation committees prepare a written charter that addresses either purposes and responsibilities
or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity
compensation plans in certain cases; or adopt and make publicly available corporate governance guidelines.



We are incorporated under, and are governed
by, the laws of Bermuda. For a summary of some of the differences between provisions of Bermuda law applicable to us and the laws
applicable to companies incorporated in Delaware and their shareholders, See “Item 10. Additional Information—B. Memorandum
of association and bye-laws.”



ITEM 16H. Mine safety disclosure



Not applicable.



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PART III



ITEM 17. Financial statements



We have responded to Item 18 in lieu of
this item.



ITEM 18. Financial statements



Financial Statements are filed as part
of this annual report, see pages F-1 to F-76 to this annual report.



ITEM 19. Exhibits



|Exhibit no. | Description                                                                                                                                                                                                                                                                                                                                                                                                
|----------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1.1         | Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                                                                                                                                                                          
|1.2         | Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                                                                                                                                                                             
|1.3         | Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                                                                                                                                                                                      
|1.4         | Form of amended and restated bye-laws (incorporated herein by reference to Exhibit 3.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                                                                                                                                                                 
|2.2         | Indenture, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Limited, GeoPark Latin America Limited and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                             
|2.3         | Share Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Chile S.A., GeoPark Colombia S.A. and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                     
|2.4         | Intercompany Loan Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Fell S.p.A., GeoPark Llanos SAS and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                           
|2.5         | Supplemental Indenture, dated December 20, 2013, among GeoPark Latin America Limited Agencia en Chile, GeoPark Latin America Limited, GeoPark Limited, GeoPark Latin America Coöperatie U.A. and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.5 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on January 21, 2014).
|4.1         | Special Contract for the Exploration and Exploitation of Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and Cordex Petroleums Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                     
|4.2         | Exploration and Production Contract regarding exploration for and exploitation of hydrocarbons in the La Cuerva Block, dated April 16, 2008, between the Colombian Agencia Nacional de Hidrocarburos and Hupecol Caracara LLC (incorporated herein by reference to Exhibit 10.12 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).       
|4.3         | Exploration and Production Contract regarding exploration for and exploitation of hydrocarbons in the Llanos 34 Block, dated March 13, 2009, between the Colombian Agencia Nacional de Hidrocarburos and Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit 10.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).    
|4.4         | Subscription and Shareholders Agreement, dated February 7, 2006, among the International Finance Corporation, GeoPark Holdings Limited, Gerald O’Shaughnessy and James F. Park (incorporated herein by reference to Exhibit 10.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                       

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|Exhibit no. | Description
|----------- | -----------

|4.5  | Subscription Agreement, dated May 20, 2011, among LG International Corporation, GeoPark Chile Limited Agencia en Chile, GeoPark Chile S.A. and GeoPark Holdings Limited (incorporated herein by reference to Exhibit 10.6 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).        
|---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.6  | Shareholders’ Agreement, dated May 20, 2011, among LG International Corporation, GeoPark Chile Limited Agencia en Chile and GeoPark Chile S.A. (incorporated herein by reference to Exhibit 10.7 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                 
|4.7  | Subscription Agreement, dated December 18, 2012, among LG International Corporation, GeoPark Chile Limited Agencia en Chile, GeoPark Colombia S.A. and GeoPark Holdings Limited (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
|4.8  | Shareholders’ Agreement, dated December 18, 2012, among LG International Corporation, GeoPark Chile Limited Agencia en Chile and GeoPark Colombia S.A. (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                         
|4.9  | Subordinated Loan Agreement, dated December 18, 2012, between LG International Corporation and Winchester Oil & Gas S.A. (incorporated herein by reference to Exhibit 10.10 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                      
|4.10 | Subscription Agreement, dated October 18, 2011, among LG International Corporation and GeoPark TdF S.A. (incorporated herein by reference to Exhibit 10.11 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                                       
|4.11 | Shareholders’ Agreement, dated October 4, 2011, among LG International Corporation, GeoPark TdF S.A. and GeoPark Chile S.A. (incorporated herein by reference to Exhibit 10.12 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                                   
|4.12 | Quota Purchase Agreement, dated May 14, 2013, between Panoro Energy do Brasil Ltda. and GeoPark Brasil Exploracão e Producão de Petróleo e Gás Ltda (incorporated herein by reference to Exhibit 10.13 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                           
|4.13 | Purchase and Sale Agreement for Crude Oil and Condensate of Fell Block between Empresa Nacional del Petróleo (ENAP) and GeoPark Fell S.p.A. (incorporated herein by reference to Exhibit 10.14 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).                                   
|4.14 | Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.15 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).†                                                          
|4.15 | First Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.16 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).†                          
|4.16 | Second Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.7 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on September 26, 2013).                         
|4.17 | Third Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.18 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).†                          
|4.18 | Fourth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.19 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).†                         
|4.19 | Fifth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. dated April 1, 2014. (incorporated herein by reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2015)†                                         

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|Exhibit no. | Description
|----------- | -----------

|4.20 | Sixth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. dated May 1, 2015 (incorporated herein by reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F filed with the SEC on April 15, 2016). †                      
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.21 | Seventh Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. dated April 1, 2016.* †                                                                                                                                                     
|4.22 | Contract for the sale and Purchase of Natural Gas 2017-2027 between GeoPark Fell SpA and Methanex Chile SpA dated March 31, 2017. *†                                                                                                                                                                                             
|4.23 | Members’ Agreement, dated January 8, 2014, among GeoPark Latin America Coöperatie U.A., GeoPark Colombia Coöperatie U.A. and LG International Corporation (incorporated herein by reference to Exhibit 10.20 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on January 21, 2014).
|4.24 | Loan Agreement no. 4131, dated March 28, 2014, between Itaú BBA International plc and GeoPark Brasil Exploracão e Produção de Petróleo e Gás Ltda. (incorporated herein by reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2014).                                          
|4.25 | Addendum and Amendment to Loan Agreement no. 4131, dated March 12, 2015, between Itaú BBA International plc and GeoPark Brasil Exploracão e Produção de Petróleo e Gás Ltda. (incorporated herein by reference to Exhibit 4.22 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2015)                 
|4.26 | Prepayment Agreement for an Amount of up to US$100,000,000, dated December 18, 2015, among C.I. Trafigura Petroleum Colombia SAS, GeoPark Colombia SAS and GeoPark Ltd. (incorporated herein by reference to Exhibit 4.25 to the Company’s Annual Report on Form 20-F filed with the SEC on April 15, 2016.                      
|4.27 | Amendment Agreement No. 1 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated September 1, 2016 relating to the  Prepayment Agreement dated December 18, 2015.*                                                                                                                             
|4.28 | Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December 16, 2016 relating to the  Prepayment Agreement dated December 18, 2015.*                                                                                                                             
|4.29 | Amendment Agreement No. 3 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated February 13, 2017 relating to the  Prepayment Agreement dated December 18, 2015.*                                                                                                                             
|8.1  | Subsidiaries of GeoPark Limited.*                                                                                                                                                                                                                                                                                                
|12.1 | Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*                                                                                                                                                                                                                                                        
|12.2 | Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*                                                                                                                                                                                                                                                        
|13.1 | Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*                                                                                                                                                                                                         
|13.2 | Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*                                                                                                                                                                                                         
|15.1 | Consent of Price Waterhouse & Co. S.R.L., Argentina.*                                                                                                                                                                                                                                                                            
|15.2 | Consents of DeGolyer and MacNaughton to use its report.*                                                                                                                                                                                                                                                                         
|99.1 | Reserves Report of DeGolyer and MacNaughton dated March 11, 2017, for reserves in Chile, Colombia, Peru, Brazil as of December 31, 2016.*                                                                                                                                                                                        




| | * | Filed with this Annual Report on Form 20-F.
| | - | -------------------------------------------



| | † | Confidential treatment of certain provisions of these
exhibits has been requested with the SEC. Omitted material for which confidential treatment has been requested has been filed
separately with the SEC.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Glossary
of oil and natural gas terms



The terms defined in this section are used
throughout this annual report:



“appraisal well” means a well
drilled to further confirm and evaluate the presence of hydrocarbons in a reservoir that has been discovered.



“API” means the American Petroleum
Institute’s inverted scale for denoting the “light” or “heaviness” of crude oils and other liquid
hydrocarbons.



“bbl” means one stock tank barrel,
of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.



“bcf” means one billion cubic
feet of natural gas.



“bcm” means billion cubic meters.



“boe” means barrels of oil equivalent,
with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.



“boepd” means barrels of oil equivalent
per day.



“bopd” means barrels of oil per
day.



“British thermal unit” or “btu”
means the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.



“basin” means a large natural
depression on the earth’s surface in which sediments generally brought by water accumulate.



“CEOP” (Contrato Especial de
Operación) means a special operating contract the Chilean signs with a company or a consortium of companies for the
exploration and exploitation of hydrocarbon wells



“completion” means the process
of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in
the case of a dry hole, the reporting of abandonment to the appropriate agency.



“developed acreage” means the
number of acres that are allocated or assignable to productive wells or wells capable of production.



“developed reserves” are expected
quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment
has been installed or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become
unavailable, it may be necessary to reclassify developed reserves as undeveloped.



“development well” means a well
drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.



“dry hole” means a well found
to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production
expenses and taxes.



“E&P Contract” means exploration
and production contract



“economic interest” means an indirect
participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires.



“economically producible” means
a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.



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“exploratory well” means a well
drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive
of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development
well, a service well, or a stratigraphic test well as those items are defined below.



“field” means an area consisting
of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or
stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious
strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent
fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition
are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest,
etc.



“formation” means a layer of rock
which has distinct characteristics that differ from nearby rock.



“mbbl” means one thousand barrels
of crude oil, condensate or natural gas liquids.



“mboe” means one thousand barrels
of oil equivalent.



“mcf” means one thousand cubic
feet of natural gas.



“Measurements” include:



| | · | “m” or “meter” means one meter, which equals approximately 3.28084 feet;
| | - | ------------------------------------------------------------------------



| | · | “km” means one kilometer, which equals approximately 0.621371 miles;
| | - | --------------------------------------------------------------------



| | · | “sq. km” means one square kilometer, which equals approximately 247.1 acres;
| | - | ----------------------------------------------------------------------------



| | · | “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent to approximately
0.15898 cubic meters;
| | - | ----------------------------------------------------------------------------------------------------------------------



| | · | “boe” means one barrel of oil equivalent, which equals approximately 160.2167 cubic meters, determined using the
ratio of 6,000 cubic feet of natural gas to one barrel of oil;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | “cf” means one cubic foot;
| | - | --------------------------



| | · | “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, respectively;
| | - | --------------------------------------------------------------------------------------



| | · | “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, respectively;
| | - | --------------------------------------------------------------------------------------



| | · | “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, respectively; and
| | - | -----------------------------------------------------------------------------------------



| | · | “pd” means per day.
| | - | -------------------





“metric ton” or “MT”
means one thousand kilograms. Assuming standard quality oil, one metric ton equals 7.9 bbl.



“mmbbl” means one million barrels
of crude oil, condensate or natural gas liquids.



“mmboe” means one million barrels
of oil equivalent.



“mmbtu” means one million British
thermal units.



“NYMEX” means The New York Mercantile
Exchange.



“net acres” means the percentage
of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has a 50% interest in 100 acres
owns 50 net acres.



“productive well” means a well
that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production
exceed production expenses and taxes.



“prospect” means a potential trap
which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate
a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir,
seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least
not in commercial volumes.



“proved developed reserves” means
those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.



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“proved reserves” means estimated
quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions,
as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation
S-X 4-10(a)(2).



“proved undeveloped reserves”
means are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery
projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to
improved recovery projects.



“reasonable certainty” means a
high degree of confidence.



“recompletion” means the process
of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish
or increase existing production.



“reserves” means estimated remaining
quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there
will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and
all permits and financing required to implement the project.



“reservoir” means a porous and
permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable
rock or water barriers and is individual and separate from other reservoirs.



“royalty” means a fractional undivided
interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of
development, operations or maintenance.



“service well” means a well drilled
or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection,
water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for
in-situ combustion.



“shale” means a fine grained sedimentary
rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively
large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock.
Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.



“spacing” means the distance between
wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, and is often
established by regulatory agencies).



“spud” means the very beginning
of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of
drilling the well to the authorized total depth.



“stratigraphic test well” means
a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily
are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified
as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as
(i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.



“tcm” means trillion cubic meters.



“undeveloped reserves” are quantities
expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulation, (2) from deepening
existing wells to a different (but known) reservoir, (3) from infill wells that will increase recover, or (4) where a relatively
large expenditure (e.g., when compared to the cost of drilling a new well) is required to (a) recomplete an existing well
or (b) install production or transportation facilities for primary or improved recovery projects.



“unit” means the joining of all
or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without
regard to separate property interests. Also, the area covered by a unitization agreement.



“wellbore” means the hole drilled
by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.



“working interest” means the right
granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners
bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.



“workover” means operations in
a producing well to restore or increase production.



155


Table of Contents


SIGNATURES



The registrant hereby certifies that it
meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual
report on its behalf.









| | GEOPARK LIMITED
| | ---------------
| | By:            
| |                
| |                

Date: April 11, 2017



156


Table of Contents


Index to
Consolidated Financial Statements



|Audited Annual Consolidated Financial Statements—GeoPark Limited                                                          | Page
|------------------------------------------------------------------------------------------------------------------------- | ----
|Report of Independent Registered Public Accounting Firm                                                                   | F-2 
|Consolidated Statements of Income and Comprehensive Income for the Fiscal Years Ended December 31, 2016 and 2015          | F-3 
|Consolidated Statement of Financial Position as of December 31, 2016 and 2015                                             | F-4 
|Consolidated Statements of Changes in Shareholders’ Equity for the Fiscal Years Ended December 31, 2016 and 2015          | F-5 
|Consolidated Statements of Cash Flows for the Fiscal Years ended December 31, 2016 and 2015                               | F-6 
|Notes to the Audited Annual Consolidated Financial Statements for the Fiscal Years Ended December 31, 2016, 2015 and 2014 | F-7 










Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December
31, 2016, 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/ Ezequiel L. Mirazon
        (Partner) | 
|------------------------------------------------------------------------------------------------------- | 

Ezequiel L. Mirazon



Autonomous City of Buenos Aires, Argentina
March 6, 2017



F-2


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


|
|



CONSOLIDATED STATEMENT OF INCOME

|Amounts in US$  ́000                                                                                   | Note  | 2016     | 2015      | 2014     
|----------------------------------------------------------------------------------------------------- | ----- | -------- | --------- | ---------
|REVENUE                                                                                               | 7     | 192,670  | 209,690   | 428,734  
|Commodity risk management contracts                                                                   | 36    | (2,554)  | -         | -        
|Production and operating costs                                                                        | 8     | (67,235) | (86,742)  | (131,419)
|Geological and geophysical expenses                                                                   | 11    | (10,282) | (13,831)  | (13,002) 
|Administrative expenses                                                                               | 12    | (34,170) | (37,471)  | (45,867) 
|Selling expenses                                                                                      | 13    | (4,222)  | (5,211)   | (24,428) 
|Depreciation                                                                                          |       | (75,774) | (105,557) | (100,528)
|Write-off of unsuccessful efforts                                                                     | 19    | (31,366) | (30,084)  | (30,367) 
|Impairment loss reversed (recognised) for non-financial assets                                        | 19-35 | 5,664    | (149,574) | (9,430)  
|Other expenses                                                                                        |       | (1,344)  | (13,711)  | (1,849)  
|OPERATING (LOSS) PROFIT                                                                               |       | (28,613) | (232,491) | 71,844   
|Financial costs                                                                                       | 14    | (34,101) | (35,655)  | (27,622) 
|Foreign exchange gain (loss)                                                                          |       | 13,872   | (33,474)  | (23,097) 
|(LOSS) PROFIT BEFORE INCOME TAX                                                                       |       | (48,842) | (301,620) | 21,125   
|Income tax (expense) benefit                                                                          | 16    | (11,804) | 17,054    | (5,195)  
|(LOSS) PROFIT FOR THE YEAR                                                                            |       | (60,646) | (284,566) | 15,930   
|Attributable to:
        
        Owners of the Company                                               |       | (49,092) | (234,031) | 8,085    
|Non-controlling interest                                                                              |       | (11,554) | (50,535)  | 7,845    
|(Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Basic   | 18    | (0.82)   | (4.05)    | 0.14     
|(Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Diluted | 18    | (0.82)   | (4.05)    | 0.14     



CONSOLIDATED STATEMENT OF COMPREHENSIVE
INCOME



|Amounts in US$  ́000                                          |  | 2016     | 2015      | 2014   
|------------------------------------------------------------ |  | -------- | --------- | -------
|(Loss) Profit for the year                                   |  | (60,646) | (284,566) | 15,930 
|Other comprehensive income:                                  |  |          |           |        
|Items that may be subsequently reclassified to (loss) profit |  |          |           |        
|Currency translation difference                              |  | 7,102    | (1,001)   | (2,448)
|Total comprehensive (Loss) Income for the year               |  | (53,544) | (285,567) | 13,482 
|Attributable to:
        
        Owners of the Company      |  | (41,990) | (235,032) | 5,637  
|Non-controlling interest                                     |  | (11,554) | (50,535)  | 7,845  



The notes on pages 7 to 76 are an integral
part of these consolidated financial statements.



F-3


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


CONSOLIDATED STATEMENT OF FINANCIAL POSITION



|Amounts in US$   ́000                         | Note | 2016      | 2015     
|-------------------------------------------- | ---- | --------- | ---------
|ASSETS                                       |      |           |          
|NON CURRENT ASSETS                           |      |           |          
|Property, plant and equipment                | 19   | 473,646   | 522,611  
|Prepaid taxes                                | 21   | 2,852     | 1,172    
|Other financial assets                       | 24   | 19,547    | 13,306   
|Deferred income tax asset                    | 17   | 23,053    | 34,646   
|Prepayments and other receivables            | 23   | 241       | 220      
|TOTAL NON CURRENT ASSETS                     |      | 519,339   | 571,955  
|CURRENT ASSETS                               |      |           |          
|Inventories                                  | 22   | 3,515     | 4,264    
|Trade receivables                            | 23   | 18,426    | 13,480   
|Prepayments and other receivables            | 23   | 7,402     | 11,057   
|Prepaid taxes                                | 21   | 15,815    | 19,195   
|Other financial assets                       | 24   | 2,480     | 1,118    
|Cash at bank and in hand                     | 24   | 73,563    | 82,730   
|TOTAL CURRENT ASSETS                         |      | 121,201   | 131,844  
|TOTAL ASSETS                                 |      | 640,540   | 703,799  
|TOTAL EQUITY                                 |      |           |          
|Equity attributable to owners of the Company |      |           |          
|Share capital                                | 25   | 60        | 59       
|Share premium                                |      | 236,046   | 232,005  
|Reserves                                     |      | 130,118   | 123,016  
|Accumulated losses                           |      | (260,459) | (208,428)
|Attributable to owners of the Company        |      | 105,765   | 146,652  
|Non-controlling interest                     |      | 35,828    | 53,515   
|TOTAL EQUITY                                 |      | 141,593   | 200,167  
|LIABILITIES                                  |      |           |          
|NON CURRENT LIABILITIES                      |      |           |          
|Borrowings                                   | 26   | 319,389   | 343,248  
|Provisions and other long-term liabilities   | 27   | 42,509    | 42,450   
|Deferred income tax liability                | 17   | 2,770     | 16,955   
|Trade and other payables                     | 28   | 34,766    | 19,556   
|TOTAL NON CURRENT LIABILITIES                |      | 399,434   | 422,209  
|CURRENT LIABILITIES                          |      |           |          
|Borrowings                                   | 26   | 39,283    | 35,425   
|Derivative financial instrument liabilities  |      | 3,067     | -        
|Current income tax liabilities               |      | 5,155     | 208      
|Trade and other payables                     | 28   | 52,008    | 45,790   
|TOTAL CURRENT LIABILITIES                    |      | 99,513    | 81,423   
|TOTAL LIABILITIES                            |      | 498,947   | 503,632  
|                                             |      |           |          
|TOTAL EQUITY AND LIABILITIES                 |      | 640,540   | 703,799  



The consolidated financial statements were
approved by the Board of Directors on 6 March 2017.



The notes on pages 7 to 76 are an integral
part of these consolidated financial statements.



F-4


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


CONSOLIDATED STATEMENT OF CHANGES IN EQUITY



|                                                        | Attributable to owners of the Company |                                |                               
|------------------------------------------------------- | ------------------------------------- | ------------------------------ | ------------------------------
|Amount in US$ '000                                      | Share
        
        Capital        | Share
        
        Premium | Other
        
        Reserve
|Equity at 1 January 2014                                | 44                                    | 120,426                        | 127,527                       
|Comprehensive income:                                   |                                       |                                |                               
|Profit for the year                                     | -                                     | -                              | -                             
|Currency translation differences                        | -                                     | -                              | -                             
|Total Comprehensive Income for the Year 2014            | -                                     | -                              | -                             
|Transactions with owners:                               |                                       |                                |                               
|Proceeds from issue of shares (Note 25)                 | 14                                    | 90,848                         | -                             
|Proceeds from transaction with Non-controlling interest | -                                     | -                              | -                             
|Share-based payment (Note 29)                           | -                                     | -                              | -                             
|Repurchase of shares (Note 25)                          | -                                     | (388)                          | -                             
|Total 2014                                              | 14                                    | 90,460                         | -                             
|Balances at 31 December 2014                            | 58                                    | 210,886                        | 127,527                       
|Comprehensive income:                                   |                                       |                                |                               
|Loss for the year                                       | -                                     | -                              | -                             
|Currency translation differences                        | -                                     | -                              | -                             
|Total Comprehensive Loss for the Year 2015              | -                                     | -                              | -                             
|Transactions with owners:                               |                                       |                                |                               
|Share-based payment (Note 29)                           | 1                                     | 22,734                         | -                             
|Repurchase of shares (Note 25)                          | -                                     | (1,615)                        | -                             
|Total 2015                                              | 1                                     | 21,119                         | -                             
|Balances at 31 December 2015                            | 59                                    | 232,005                        | 127,527                       
|Comprehensive income:                                   |                                       |                                |                               
|Loss for the year                                       | -                                     | -                              | -                             
|Currency translation differences                        | -                                     | -                              | -                             
|Total Comprehensive Loss for the Year 2016              | -                                     | -                              | -                             
|Transactions with owners:                               |                                       |                                |                               
|Share-based payment (Note 29)                           | 1                                     | 6,032                          | -                             
|Repurchase of shares (Note 25)                          |                                       | (1,991)                        | -                             
|Dividends distribution to non-controlling interest      | -                                     | -                              | -                             
|Total 2016                                              | 1                                     | 4,041                          | -                             
|Balances at 31 December 2016                            | 60                                    | 236,046                        | 127,527                       



The notes on pages 7 to 76 are an integral
part of these consolidated financial statements.



F-5


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


CONSOLIDATED STATEMENT OF CASH FLOW



|Amounts in US$ '000                                            | Note  | 2016     | 2015      | 2014     
|-------------------------------------------------------------- | ----- | -------- | --------- | ---------
|Cash flows from operating activities                           |       |          |           |          
|(Loss) Profit for the year                                     |       | (60,646) | (284,566) | 15,930   
|Adjustments for:                                               |       |          |           |          
|Income tax expense (benefit)                                   | 16    | 11,804   | (17,054)  | 5,195    
|Depreciation                                                   |       | 75,774   | 105,557   | 100,528  
|Allowance for doubtful accounts                                | 13-23 | -        | -         | 741      
|Loss on disposal of property, plant and equipment              |       | 14       | 2,000     | 590      
|Impairment loss (reversed) recognised for non-financial assets | 19-35 | (5,664)  | 149,574   | 9,430    
|Write-off of unsuccessful efforts                              | 19    | 31,366   | 30,084    | 30,367   
|Accrual of borrowing’s interests                               |       | 27,940   | 28,460    | 25,754   
|Amortisation of other long-term liabilities                    | 27    | (2,924)  | (703)     | (468)    
|Unwinding of long-term liabilities                             | 27    | 2,693    | 2,575     | 1,972    
|Accrual of share-based payment                                 |       | 3,367    | 8,223     | 8,373    
|Foreign exchange (gain) loss                                   |       | (13,872) | 33,474    | 23,097   
|Unrealized loss on commodity risk management contracts         | 36    | 3,068    | -         | -        
|Income tax paid                                                |       | (1,956)  | (7,625)   | (1,306)  
|Changes in working capital                                     | 5     | 11,920   | (24,104)  | 10,543   
|Cash flows from operating activities – net                     |       | 82,884   | 25,895    | 230,746  
|Cash flows from investing activities                           |       |          |           |          
|Purchase of property, plant and equipment                      |       | (39,306) | (48,842)  | (238,047)
|Acquisitions of companies, net of cash acquired                |       | -        | -         | (114,967)
|Collections related to financial leases                        |       | -        | -         | 8,973    
|Cash flows used in investing activities – net                  |       | (39,306) | (48,842)  | (344,041)
|Cash flows from financing activities                           |       |          |           |          
|Proceeds from borrowings                                       |       | 186      | 7,036     | 67,633   
|Proceeds from cash calls from related parties                  |       | 5,210    | 2,400     | 16,563   
|Proceeds from transaction with non-controlling interest        |       | -        | -         | 35       
|Proceeds from issuance of shares                               |       | -        | -         | 90,862   
|Repurchase of shares                                           |       | (1,991)  | (1,615)   | (388)    
|Principal paid                                                 |       | (22,645) | (89)      | (17,087) 
|Interest paid                                                  |       | (25,490) | (25,754)  | (24,558) 
|Dividends distribution to non-controlling interest             |       | (6,406)  | -         | -        
|Principal paid to related parties                              |       | -        | -         | (8,344)  
|Cash flows (used in) / from financing activities - net         |       | (51,136) | (18,022)  | 124,716  
|                                                               |       |          |           |          
|Net (decrease) increase in cash and cash equivalents           |       | (7,558)  | (40,969)  | 11,421   
|                                                               |       |          |           |          
|Cash and cash equivalents at 1 January                         |       | 82,730   | 127,672   | 121,105  
|Currency translation differences                               |       | (1,609)  | (3,973)   | (4,854)  
|Cash and cash equivalents at the end of the year               |       | 73,563   | 82,730    | 127,672  
|                                                               |       |          |           |          
|Ending Cash and cash equivalents are specified as follows:     |       |          |           |          
|Cash in bank                                                   |       | 73,551   | 82,720    | 127,560  
|Cash in hand                                                   |       | 12       | 10        | 112      
|Cash and cash equivalents                                      |       | 73,563   | 82,730    | 127,672  



The notes
on pages 7 to 76 are an integral part of these consolidated financial statements.



F-6


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note



| | 1 | General Information
| | - | -------------------



GeoPark Limited (the Company) is a company
incorporated under the law of Bermuda. The Registered Office address is 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.



These consolidated financial statements
were authorised for issue by the Board of Directors on 6 March 2017.



Note



| | 2 | Summary of significant accounting policies
| | - | ------------------------------------------



The principal accounting policies applied
in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied
to the years presented, unless otherwise stated.



2.1 Basis of preparation



The consolidated financial statements of
GeoPark Limited have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued
by the International Accounting Standards Board (“IASB”).



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.



F-7


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.1 Basis of preparation (continued)



2.1.1 Changes in accounting policy and
disclosure



New and amended standards adopted by
the Group



The following standards have been adopted
by the Group for the first time for the financial year beginning on or after 1 January 2016:



Annual Improvements to IFRSs – 2010-2012
Cycle and 2012 – 2014 Cycle



Disclosure Initiative - Amendments to IAS
1



Investment entities: Applying the consolidation
exception – Amendments to IFRS 10, IFRS 12 and IAS 28



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 2016 and not early adopted.



IFRS 2 “Share based payments”:
amended in June 2016 to clarify the measurement basis for cash-settled share-based payments and the accounting for modifications
that change an award from cash-settled to equity-settled. It also introduces an exception to IFRS 2 principles by requiring an
award to be treated as if it was wholly equity-settled, where an employer is obliged to withhold an amount for the employee’s
tax obligation associated with a share-based payment and pay that amount to the tax authority. It is effective for annual periods
beginning on or after January 1, 2018. The Company is currently analyzing the impact of its application on the Company’s
operating results or financial position.



IFRS 9 Financial Instruments and associated
amendments to various other standards: IFRS 9 replaces the multiple classification and measurement models in IAS 39. Classification
of debt assets will be driven by the entity’s business model for managing the financial assets and the contractual cash flow
characteristics of the financial assets. A debt instrument is measured at amortised cost if: a) the objective of the business model
is to hold the financial asset for the collection of the contractual cash flows, and b) the contractual cash flows under the instrument
solely represent payments of principal and interest. All other debt and equity instruments, including investments in complex debt
instruments and equity investments, must be recognised at fair value.



All fair value movements on financial assets
are taken through the statement of profit or loss, except for equity investments that are not held for trading, which may be recorded
in the statement of profit or loss or in reserves (without subsequent recycling to profit or loss).



F-8


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.1 Basis of preparation (continued)



2.1.1 Changes in accounting policy and
disclosure (continued)



For financial liabilities that are measured
under the fair value option entities will need to recognise the part of the fair value change that is due to changes in their own
credit risk in other comprehensive income rather than profit or loss.



The new hedge accounting rules (released
in December 2013) align hedge accounting more closely with common risk management practices. As a general rule, it will be easier
to apply hedge accounting going forward. The new standard also introduces expanded disclosure requirements and changes in presentation.
In July 2014, the IASB made further changes to the classification and measurement rules and also introduced a new impairment model.



IFRS 15 Revenue from contracts with customers
and associated amendments to various other standards: The IASB has issued a new standard for the recognition of revenue. This will
replace IAS 18 which covers contracts for goods and services and IAS 11 which covers construction contracts. The new standard is
based on the principle that revenue is recognised when control of a good or service transfers to a customer so the notion of control
replaces the existing notion of risks and rewards.



These accounting changes may have flow-on
effects on the entity’s business practices regarding systems, processes and controls, compensation and bonus plans, contracts,
tax planning and investor communications. Entities will have a choice of full retrospective application, or prospective application
with additional disclosures.



Management is evaluating the potential impact
of the new rules on the Group’s financial statements.



IFRS 16 Leases: will affect primarily the
accounting by lessees and will result in the recognition of almost all leases on balance sheet. The standard removes the current
distinction between operating and financing leases and requires recognition of an asset (the right to use the leased item) and
a financial liability to pay rentals for virtually all lease contracts. An optional exemption exists for short-term and low-value
leases. The accounting by lessors will not significantly change. Some differences may arise as a result of the new guidance on
the definition of a lease.



The Group has not yet determined to what
extent its commitments will result in the recognition of an asset and a liability for future payments and how this will affect
the Group’s profit and classification of cash flows. Some of the commitments may be covered by the exception for short-term
and low-value leases and some commitments may relate to arrangements that will not qualify as leases under IFRS 16. At this stage,
the Group does not intend to adopt the standard before its effective date.



F-9


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.1 Basis of preparation (continued)



2.1.1 Changes in accounting policy and
disclosure (continued)



IFRIC 22 “Foreign Currency Transactions
and Advance Consideration”: issued in December 2016. The interpretation addresses how to determine the date of the transaction
for the purpose of determining the exchange rate to use on initial recognition of the related asset, expense or income related
to an entity that has received or paid an advance consideration in a foreign currency. The date of the transaction is the date
on which an entity initially recognises the non-monetary asset or non-monetary liability arising from the payment or receipt of
advance consideration. It is effective for annual periods beginning on January 1, 2018. The Company is currently analysing the
impact of its application on the Company’s operating results or financial position.



Recognition of Deferred Tax Assets for Unrealised
Losses – Amendments to IAS 12: made in January 2016 clarify the accounting for deferred tax where an asset is measured at
fair value and that fair value is below the asset’s tax base.



Disclosure Initiative – Amendments
to IAS 7: Going forward, entities will be required to explain changes in their liabilities arising from financing activities. This
includes changes arising from cash flows and non-cash changes. Changes in financial assets must be included in this disclosure
if the cash flows were, or will be, included in cash flows from financing activities. Entities may include changes in other items
as part of this disclosure. However, in this case the changes in the other items must be disclosed separately from the changes
in liabilities arising from financing activities. The information may be disclosed in tabular format as a reconciliation from opening
and closing balances, but a specific format is not mandated.



Sale or contribution of assets between an
investor and its associate or joint venture – Amendments to IFRS 10 and IAS 28: The amendments clarify the accounting treatment
for sales or contribution of assets between an investor and its associates or joint ventures.



Improvements to IFRSs – 2014-2016
Cycle: amendments issued in December 2016 that are effective for periods beginning on or after January 1, 2018. The Company estimates
that these amendments will not have an impact on the Company’s operating results or financial position.



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



F-10


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.2 Going concern



The Directors regularly monitor the Group's
cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecast operational and investment
funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors
to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches.



Considering macroeconomic environment conditions,
the performance of the operations, 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.



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.



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.4 Segment reporting



Operating segments are reported in a manner
consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who
is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive
Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance,
Finance and People departments. This committee reviews the Group’s internal reporting in order to assess performance and
allocate resources. Management has determined the operating segments based on these reports.



2.5 Foreign currency translation



| | a) | Functional and presentation currency
| | -- | ------------------------------------



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



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



| | b) | Transactions and balances
| | -- | -------------------------



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



2.6 Joint arrangements



Under IFRS 11 investments in joint arrangements
are classified as either joint operations or joint ventures depending on the contractual rights and obligations 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. See Note 31 (a).



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.8 Production and operating costs



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



2.9 Financial costs



Financial costs include interest expenses,
bank charges 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 totalledUS$ 254,950 (US$ 637,390 in 2015 and US$ 3,112,317 in 2014).



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$ 31,366,000 has been recognised
in the Consolidated Statement of Income within Write-off of unsuccessful efforts (US$ 30,084,000 in 2015 and US$ 30,367,000 in
2014). See Note 19.



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.



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.10 Property, plant and equipment (continued)



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.



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 financial expense.



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.11 Provisions and other long-term liabilities
(continued)



2.11.1 Asset Retirement Obligation



The Group records the fair value of the
liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded,
the Group 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. The addition in 2016 corresponds to the deferred income related to the take or pay
provision associated to gas sales in Brazil, that Petrobras will make up in the future.



2.12 Impairment of non-financial assets



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



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



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.12 Impairment of non-financial assets
(continued)



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



During 2016 impairment loss was reversed
for an amount of US$ 5,664,000 (impairment loss recognised for US$ 149,574,000 in 2015 and US$ 9,430,000 in 2014). See Note
35. 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.



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.



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.15 Current and deferred income tax
(continued)



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$ 11,200,000.



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



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.



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.16 Financial assets (continued)



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 and Brazilian government request and are restricted for
those purposes. Current financial assets correspond to short term investments with original maturities up to twelve months and
over three months.



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.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



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 Derivatives



Derivatives financial instruments are recognised
in the statement of financial position as assets or liabilities and initially and subsequently measured at fair value through profit
and loss. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end
of the reporting period.



The market-to-market fair value of the Company's
outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques,
including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. Gains and losses arising from
changes in fair value are recognised in the statement of income in Commodity risk management contracts.



For more information about derivatives please
refer to Note 36.



2.22 Borrowings



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



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



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



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Note



| | 2 | Summary of significant accounting policies (continued)
| | - | ------------------------------------------------------



2.23 Share capital



Equity comprises the following:



| | · | "Share capital" representing
the nominal value of equity shares.
| | - | ----------------------------------------------------------------



| | · | "Share premium" representing
the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share 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.
| | - | --------------------------------------------------------------------------------------



2.24 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
Geometric Brownian Motion method.



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



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



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management
| | - | -------------------------------------



The Group is exposed through its operations
to the following financial risks:



| | · | Currency risk
| | - | -------------



| | · | Price risk
| | - | ----------



| | · | Credit risk – concentration
| | - | ---------------------------



| | · | Funding and liquidity risk
| | - | --------------------------



| | · | Interest rate risk
| | - | ------------------



| | · | Capital risk management
| | - | -----------------------



The policy for managing these risks is set
by the Board. 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 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 2016, the Argentine Peso devaluated
by 22% (52% and 31% in 2015 and 2014) against the US Dollar, the Chilean Peso revaluated by 6% (devaluated by 16% in 2015 and 2014)
and the Colombian Peso revaluated by 5% (devaluated by 32% and 24% in 2015 and 2014).



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$ 2,683,400 (US$ 1,003,300 in 2015 and post – tax profit lower by US$
621,400 in 2014).



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management (continued)
| | - | -------------------------------------------------



Currency risk (continued)



In Brazil, the functional currency is the
local currency, which is the Brazilian Real. The fluctuation of the US Dollars against the Brazilian Real does not impact the loans,
costs and revenues held in Brazilian Real; but it does impact the balances denominated in US Dollars. Such is the case of the Itaú
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 gain generated by the Brazilian subsidiary during 2016 amounted to
US$ 14,542,000 (loss of US$ 35,605,000 in 2015 and loss of US$ 17,573,000 in 2014).



During 2016, the Brazilian Real revaluated
by 17% against the US Dollar (devaluated by 47% and 13% in 2015 and 2014, respectively). If the Brazilian Real had devaluated 10%
against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 5,300,000
(post – tax loss higher by US$ 7,400,000 in 2015 and post – tax profit lower by US$ 5,660,000 in 2014).



As of 31 December 2016, 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.



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.



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 considers
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.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management (continued)
| | - | -------------------------------------------------



Price risk (continued)



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$ 23,655,000 (US$ 23,940,000 in 2015 and post tax profit lower by US$ 29,186,000 in 2014).



During October 2016, it was considered appropriate
to manage part of the exposure to the volatile crude oil price using derivatives. The Company considers these derivative contracts
to be an effective manner of properly managing commodity price risk. The Company has also obtained credit lines from related counterparties
associated to these contracts which are available to minimize the Company’s cash exposure, in case necessary (see Note 36).



Credit risk – concentration



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



In Colombia, during 2016, the Colombian
subsidiary made 90% of the oil sales to Trafigura (one of the world’s leading independent commodity trading and logistics
houses), with Trafigura accounting for 59% of consolidated revenues for the same period.



All the oil produced in Chile as well as
the gas produced by TdF Blocks (10% of total revenue, 15% in 2015 and 28% in 2014) is sold to ENAP, 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 (9% of consolidated
revenues, 7% in 2015 and 6% in 2014).



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.



In 2016, the Group executed oil prices hedges
via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative
contracts. The Group’s hedging counterparties are leading financial institutions and trading companies, therefore the Directors
do not consider there to be a significant collection risk.



See disclosure in Notes 24 and 36.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management (continued)
| | - | -------------------------------------------------



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 2016
with a cash balance of US$ 73,563,000 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 24,000 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.



Since 2015, and impacted by the 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 2016 and 2015 include:



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. Funds committed by Trafigura were 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.



On February 2017, the availability period
under the prepayment agreement with Trafigura was extended until 30 June 2017. This extension provides GeoPark with available funds
upon request from Trafigura and will repaid by the Company on a monthly basis through future oil deliveries over the period between
January 2017 and December 2018. As of the date of these Financial Statements, outstanding balances related to the prepayment agreement
amount to US$ 20,000,000.



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%.



F-24


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management (continued)
| | - | -------------------------------------------------



Interest rate risk



The Group’s interest rate risk arises
from long-term borrowings issued at variable rates, which expose the Group to 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 2016, the outstanding long-term
borrowing affected by variable rates amounted to
US$ 54,472,000, representing 15% 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 2016, 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$ 467,000
higher (post-tax loss higher by US$ 507,000 in 2015 and post-tax profit lower by US$ 312,000 in 2014).



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 2016 and 2015
the gearing ratio at year end is above such range. Measures taken by the Company in this connection are described in Note 35.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 3 | Financial Instruments-risk management (continued)
| | - | -------------------------------------------------



Capital risk management (continued)



The gearing ratios at 31 December 2016 and
2015 were as follows:



|Amounts in US$ '000 | 2016    |  | 2015    | 
|------------------- | ------- |  | ------- | 
|Net Debt            | 285,109 |  | 295,943 | 
|Total Equity        | 141,593 |  | 200,167 | 
|Total Capital       | 426,702 |  | 496,110 | 
|Gearing Ratio       | 67%     |  | 60%     | 





Note



| | 4 | Accounting estimates and assumptions
| | - | ------------------------------------



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



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



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



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



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 2016 prepared by DeGolyer and MacNaughton, an international consultancy to the oil and
gas industry based in Dallas. It incorporates many factors and assumptions including:



F-26


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 4 | Accounting estimates and assumptions (continued)
| | - | ------------------------------------------------



| | o | expected reservoir characteristics based on geological, geophysical and engineering assessments;
| | - | ------------------------------------------------------------------------------------------------



| | o | future production rates based on historical performance and expected future operating and investment
activities;
| | - | ----------------------------------------------------------------------------------------------------------------



| | o | future oil and gas prices and quality differentials;
| | - | ----------------------------------------------------



| | o | assumed effects of regulation by governmental agencies; and
| | - | -----------------------------------------------------------



| | o | future development and operating costs.
| | - | ---------------------------------------



Management believes these factors
and assumptions are reasonable based on the information available to them at the time of preparing the estimates. However, these
estimates may change substantially as additional data from ongoing development activities and production performance becomes available
and as economic conditions impacting oil and gas prices and costs change.



| | · | The Group adopts the successful efforts
method of accounting. The Management of the 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.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | 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 at the present value of the estimated future
expenditure. The liabilities recognised are based upon estimated future abandonment costs, wells subject to abandonment, time to
abandonment, and future inflation rates.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | From time to time, the 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.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



F-27


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 5 | Consolidated Statement of Cash Flow
| | - | -----------------------------------



The Consolidated Statement of Cash Flow
shows the Group's cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents
during the year.



Cash flows from operating activities are
computed from the results for the year adjusted for non-cash operating items, changes in net working capital, and 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                                    | 2016    | 2015 | 2014  | 
|------------------------------------------------------ | ------- | ---- | ----- | 
|Increase in asset retirement obligation                | 1,195   | 985  | 1,603 | 
|Increase in provisions for other long-term liabilities | 3,468   | -    | 5,636 | 
|Purchase of property, plant and equipment              | (4,657) | 830  | 1,382 | 



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                                                         | 2016    | 2015     | 2014     | 
|--------------------------------------------------------------------------- | ------- | -------- | -------- | 
|Increase in Prepaid taxes                                                   | (2,351) | (16,611) | (3,310)  | 
|Decrease / (Increase) in Inventories                                        | 466     | 2,752    | (410)    | 
|(Increase) / Decrease in Trade receivables                                  | (4,811) | 22,470   | 13,791   | 
|(Increase) / Decrease in Prepayments and other receivables and Other assets | (1,758) | 405      | 12,569   | 
|Customer advance payments                                                   | 20,000  | -        | -        | 
|Increase / (Decrease) in Trade and other payables                           | 374     | (33,120) | (12,097) | 
|                                                                            | 11,920  | (24,104) | 10,543   | 



F-28


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 6 | Segment information
| | - | -------------------



Operating segments are reported in a manner
consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who
is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive
Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance,
Finance and People departments. This committee reviews the Group’s internal reporting in order to assess performance and
allocate resources. Management has determined the operating segments based on these reports. The committee considers the business
from a geographic perspective.



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



Segment areas (geographical segments):



|Amounts
    in US$ '000                                  | Chile    | Brazil   | Colombia | Peru    | Argentina | Corporate | Total   
|-------------------------------------------------------- | -------- | -------- | -------- | ------- | --------- | --------- | --------
|2016                                                     |          |          |          |         |           |           |         
|Revenue                                                  | 36,723   | 29,719   | 126,228  | -       | -         | -         | 192,670 
|Sale
    of crude oil                                    | 18,774   | 688      | 125,731  | -       | -         | -         | 145,193 
|Sale
    of gas                                          | 17,949   | 29,031   | 497      | -       | -         | -         | 47,477  
|Realized
    gain on commodity risk management contracts | -        | -        | 514      | -       | -         | -         | 514     
|Production
    and operating costs                       | (22,169) | (8,459)  | (36,607) | -       | -         | -         | (67,235)
|Royalties                                                | (1,495)  | (2,721)  | (7,281)  | -       | -         | -         | (11,497)
|Transportation
    costs                                 | (1,170)  | -        | (1,111)  | -       | -         | -         | (2,281) 
|Share-based
    payment                                  | (138)    | (71)     | (413)    | -       | -         | -         | (622)   
|Other
    costs                                          | (19,366) | (5,667)  | (27,802) | -       | -         | -         | (52,835)
|Operating
    (loss) / profit                            | (44,969) | (645)    | 31,463   | (3,147) | 370       | (11,685)  | (28,613)
|Adjusted
    EBITDA                                      | 5,159    | 17,487   | 66,921   | (2,607) | 1,848     | (10,487)  | 78,321  
|                                                         |          |          |          |         |           |           |         
|Depreciation                                             | (31,355) | (12,974) | (31,148) | (130)   | (150)     | (17)      | (75,774)
|Reversal
    of impairment losses                        | -        | -        | 5,664    | -       | -         | -         | 5,664   
|Write-off                                                | (19,389) | (4,583)  | (7,394)  | -       | -         | -         | (31,366)
|Total
    assets                                         | 317,969  | 99,904   | 182,784  | 5,020   | 6,071     | 28,792    | 640,540 
|                                                         |          |          |          |         |           |           |         
|Employees
    (average)                                  | 102      | 10       | 138      | 11      | 80        | -         | 341     
|Employees
    at year end                                | 102      | 10       | 146      | 10      | 77        | -         | 345     
|                                                         |          |          |          |         |           |           |         



F-29


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 6 | Segment information (continued)
| | - | -------------------------------



|Amounts
    in US$ '000       | Chile     | Brazil   | Colombia | Peru    | Argentina | Corporate | Total     | 
|----------------------------- | --------- | -------- | -------- | ------- | --------- | --------- | --------- | 
|2015                          |           |          |          |         |           |           |           | 
|Revenue                       | 44,808    | 32,388   | 131,897  | -       | 597       | -         | 209,690   | 
|Sale
    of crude oil         | 29,180    | 955      | 131,897  | -       | 597       | -         | 162,629   | 
|Sale
    of gas               | 15,628    | 31,433   | -        | -       | -         | -         | 47,061    | 
|Production
    costs          | (28,704)  | (8,056)  | (48,534) | -       | (1,448)   | -         | (86,742)  | 
|Royalties                     | (1,973)   | (2,998)  | (8,150)  | -       | (34)      | -         | (13,155)  | 
|Transportation
    costs      | (2,441)   | -        | (2,068)  | -       | (2)       | -         | (4,511)   | 
|Share-based
    payment       | (132)     | -        | (234)    | -       | (197)     | -         | (563)     | 
|Other
    costs               | (24,158)  | (5,058)  | (38,082) | -       | (1,215)   | -         | (68,513)  | 
|Operating
    (loss) / profit | (180,264) | 6,639    | (37,227) | (6,719) | (2,350)   | (12,570)  | (232,491) | 
|Adjusted
    EBITDA           | (183)     | 20,460   | 66,736   | (6,520) | (684)     | (6,022)   | 73,787    | 
|                              |           |          |          |         |           |           |           | 
|Depreciation                  | (39,227)  | (13,568) | (52,434) | (129)   | (199)     | -         | (105,557) | 
|Impairment
    loss           | (104,515) | -        | (45,059) | -       | -         | -         | (149,574) | 
|Write-off                     | (25,751)  | -        | (4,333)  | -       | -         | -         | (30,084)  | 
|Total
    assets              | 381,143   | 114,974  | 153,071  | 4,287   | 3,181     | 47,143    | 703,799   | 
|                              |           |          |          |         |           |           |           | 
|Employees
    (average)       | 153       | 11       | 130      | 16      | 93        | -         | 403       | 
|Employees
    at year end     | 106       | 12       | 133      | 11      | 90        | -         | 352       | 

|                              |          |          |          |         |           |           |           | 
|----------------------------- | -------- | -------- | -------- | ------- | --------- | --------- | --------- | 
|Amounts
    in US$ '000       | Chile    | Brazil   | Colombia | Peru    | Argentina | Corporate | Total     | 
|2014                          |          |          |          |         |           |           |           | 
|Revenue                       | 145,720  | 35,621   | 246,085  | -       | 1,308     | -         | 428,734   | 
|Sale
    of crude oil         | 118,203  | 1,541    | 246,054  | -       | 1,304     | -         | 367,102   | 
|Sale
    of gas               | 27,517   | 34,080   | 31       | -       | 4         | -         | 61,632    | 
|Production
    costs          | (41,768) | (8,148)  | (80,953) | -       | (550)     | -         | (131,419) | 
|Royalties                     | (6,777)  | (2,794)  | (12,354) | -       | (241)     | -         | (22,166)  | 
|Transportation
    costs      | (6,784)  | -        | (4,663)  | -       | (87)      | -         | (11,534)  | 
|Share-based
    payment       | (763)    | -        | (423)    | -       | (433)     | -         | (1,619)   | 
|Other
    costs               | (27,444) | (5,354)  | (63,513) | -       | 211       | -         | (96,100)  | 
|Operating
    (loss) / profit | 11,733   | 10,658   | 67,212   | (2,419) | (4,321)   | (11,019)  | 71,844    | 
|Adjusted
    EBITDA           | 76,420   | 22,637   | 130,209  | (2,425) | (816)     | (5,948)   | 220,077   | 
|                              |          |          |          |         |           |           |           | 
|Depreciation                  | (37,077) | (11,613) | (51,584) | -       | (229)     | (25)      | (100,528) | 
|Impairment
    loss           | -        | -        | (9,430)  | -       | -         | -         | (9,430)   | 
|Write-off                     | (28,772) | -        | (1,564)  | -       | (31)      | -         | (30,367)  | 
|Total
    assets              | 541,481  | 151,770  | 263,070  | 4,813   | 3,839     | 74,143    | 1,039,116 | 
|                              |          |          |          |         |           |           |           | 
|Employees
    (average)       | 208      | 10       | 121      | 4       | 100       | -         | 443       | 
|Employees
    at year end     | 197      | 12       | 133      | 14      | 100       | -         | 456       | 



Approximately 20% of capital expenditure
was incurred by Chile (22% in 2015 and 66% in 2014), 67% was incurred by Colombia (66% in 2015 and 29% in 2014), 9% was incurred
by Brazil (12% in 2015, 5% in 2014) and 4% was incurred by Argentina (nil in 2015 and 2014). The capital expenditure referred does
not include total consideration for M&A activities.



F-30


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 6 | Segment information (continued)
| | - | -------------------------------



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



|Amounts in US$ '000                                    | 2016     | 2015      | 2014     
|------------------------------------------------------ | -------- | --------- | ---------
|Operating netback                                      | 122,147  | 118,027   | 274,509  
|Administrative expenses                                | (32,323) | (30,590)  | (40,340) 
|Geological and geophysical expenses                    | (11,503) | (13,650)  | (14,092) 
|Adjusted EBITDA for reportable segments                | 78,321   | 73,787    | 220,077  
|Unrealized loss on commodity risk management contracts | (3,068)  | -         | -        
|Depreciation (a)                                       | (75,774) | (105,557) | (100,528)
|Share-based payment                                    | (3,367)  | (8,223)   | (8,373)  
|Impairment and write-off of unsuccessful efforts       | (25,702) | (179,658) | (39,797) 
|Others (b)                                             | 977      | (12,840)  | 465      
|Operating (loss) profit                                | (28,613) | (232,491) | 71,844   
|Financial costs                                        | (34,101) | (35,655)  | (27,622) 
|Foreign exchange profit (loss)                         | 13,872   | (33,474)  | (23,097) 
|(Loss) Profit before tax                               | (48,842) | (301,620) | 21,125   

| | (a) | Net
                                         of capitalised costs for oil stock included in Inventories.
| | --- | --------------------------------------------------------------------------------------------------------



| | (b) | In
                                         2015 includes termination costs (see Note 35). Also includes internally capitalised costs.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------



Note



| | 7 | Revenue
| | - | -------



|Amounts in US$ '000 | 2016    | 2015    | 2014   
|------------------- | ------- | ------- | -------
|Sale of crude oil   | 145,193 | 162,629 | 367,102
|Sale of gas         | 47,477  | 47,061  | 61,632 
|                    | 192,670 | 209,690 | 428,734



Note



| | 8 | Production and operating costs
| | - | ------------------------------



|Amounts in US$ '000                   | 2016   | 2015   | 2014   
|------------------------------------- | ------ | ------ | -------
|Well and facilities maintenance       | 13,160 | 19,974 | 25,475 
|Staff costs (Note 10)                 | 10,859 | 17,999 | 16,112 
|Share-based payment (Notes 10 and 29) | 622    | 563    | 1,619  
|Royalties                             | 11,497 | 13,155 | 22,166 
|Consumables                           | 8,283  | 8,591  | 16,157 
|Transportation costs                  | 2,281  | 4,511  | 11,534 
|Equipment rental                      | 3,868  | 3,517  | 7,563  
|Safety and Insurance costs            | 2,222  | 3,239  | 5,733  
|Gas plant costs                       | 6,300  | 2,878  | 3,277  
|Field camp                            | 1,687  | 2,645  | 5,932  
|Non operated blocks costs             | 1,082  | 2,127  | 9,730  
|Other costs                           | 5,374  | 7,543  | 6,121  
|                                      | 67,235 | 86,742 | 131,419



F-31


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 9 | Depreciation
| | - | ------------



|Amounts in US$ '000                              | 2016   | 2015    | 2014   
|------------------------------------------------ | ------ | ------- | -------
|Oil and gas properties                           | 61,080 | 84,849  | 89,651 
|Production facilities and machinery              | 10,788 | 15,467  | 9,621  
|Furniture, equipment and vehicles                | 2,702  | 2,850   | 1,862  
|Buildings and improvements                       | 920    | 874     | 523    
|Depreciation of property, plant and equipment(a) | 75,490 | 104,040 | 101,657



Related to:



|Productive assets     | 71,868 | 100,316 | 99,360 
|--------------------- | ------ | ------- | -------
|Administrative assets | 3,622  | 3,724   | 2,297  
|Depreciation total(a) | 75,490 | 104,040 | 101,657

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



Note



| | 10 | Staff costs and Directors Remuneration
| | -- | --------------------------------------



|                                   | 2016   | 2015   | 2014  
|---------------------------------- | ------ | ------ | ------
|Number of employees at year end    | 345    | 352    | 456   
|Amounts in US$ '000                |        |        |       
|Wages and salaries                 | 36,059 | 40,574 | 41,593
|Share-based payments (Note 29)     | 3,367  | 8,223  | 9,178 
|Share-based payments – Cash awards | -      | -      | (805) 
|Social security charges            | 3,792  | 6,197  | 6,597 
|Director’s fees and allowance      | 2,088  | 1,238  | 1,998 
|                                   | 45,306 | 56,232 | 58,561



Recognised as follows:



|Production and operating costs      | 11,481 | 18,562 | 17,731
|----------------------------------- | ------ | ------ | ------
|Geological and geophysical expenses | 10,439 | 11,336 | 12,939
|Administrative expenses             | 23,386 | 26,334 | 27,891
|                                    | 45,306 | 56,232 | 58,561

|Board of Directors’ and key managers’ remuneration |       |        |       
|-------------------------------------------------- | ----- | ------ | ------
|Salaries and fees                                  | 7,337 | 6,549  | 11,003
|Share-based payments                               | 1,211 | 6,544  | 3,314 
|Other benefits in kind                             | 112   | 167    | 130   
|                                                   | 8,660 | 13,260 | 14,447



F-32


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 10 | Staff costs and Directors Remuneration (continued)
| | -- | --------------------------------------------------



Directors’ Remuneration



|                            | Executive
    Directors’ Fees | Executive
    Directors’ Bonus | Non-Executive
    Directors’ Fees (in US$) | Director
    Fees Paid in Shares No. of Shares | Cash
    Equivalent Total Remuneration
|--------------------------- | ----------------------------- | ------------------------------ | ------------------------------------------ | ---------------------------------------------- | --------------------------------------
|Gerald
    O’Shaughnessy    | US$
    250,000               | US$
    150,000                | -                                          | -                                              | US$
    400,000                       
|James
    F. Park           | US$
    500,000               | US$
    500,000                | -                                          | -                                              | US$
    1,000,000                     
|Pedro
    Aylwin (a)        | -                             | -                              | -                                          | -                                              | -                                     
|Peter
    Ryalls(b)         | -                             | -                              | US$
    120,000                            | 32,403                                         | US$
    220,002                       
|Juan
    Cristóbal Pavez(c) | -                             | -                              | US$
    110,000                            | 32,403                                         | US$
    210,002                       
|Carlos
    Gulisano(d)      | -                             | -                              | US$
    110,000                            | 32,403                                         | US$
    210,002                       
|Robert
    Bedingfield(e)   | -                             | -                              | US$
    100,000                            | 32,403                                         | US$
    200,002                       

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

b Technical Committee Chairman.



c Compensation Committee Chairman.



d Nomination Committee Chairman.



e Audit Committee Chairman.



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.



Note



| | 11 | Geological and geophysical expenses
| | -- | -----------------------------------



|Amounts in US$ '000                   | 2016    | 2015   | 2014    | 
|------------------------------------- | ------- | ------ | ------- | 
|Staff costs (Note 10)                 | 9,541   | 10,557 | 11,712  | 
|Share-based payment (Notes 10 and 29) | 898     | 779    | 1,227   | 
|Allocation to capitalised project     | (2,119) | (598)  | (2,317) | 
|Other services                        | 1,962   | 3,093  | 2,380   | 
|                                      | 10,282  | 13,831 | 13,002  | 



F-33


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 12 | Administrative expenses
| | -- | -----------------------



|Amounts in US$ '000                     | 2016   | 2015   | 2014  
|--------------------------------------- | ------ | ------ | ------
|Staff costs (Note 10)                   | 19,451 | 18,215 | 20,366
|Share-based payment (Notes 10 and 29)   | 1,847  | 6,881  | 5,527 
|Consultant fees                         | 3,894  | 4,115  | 6,791 
|Office expenses                         | 2,217  | 2,535  | 3,190 
|Travel expenses                         | 1,717  | 1,497  | 2,052 
|Director’s fees and allowance (Note 10) | 2,088  | 1,238  | 1,998 
|New projects                            | 885    | 559    | 2,798 
|Other administrative expenses           | 2,071  | 2,431  | 3,145 
|                                        | 34,170 | 37,471 | 45,867



Note



| | 13 | Selling expenses
| | -- | ----------------



|Amounts in US$ '000             | 2016  | 2015  | 2014  
|------------------------------- | ----- | ----- | ------
|Transportation                  | 3,559 | 4,760 | 23,106
|Selling taxes                   | 663   | 440   | 433   
|Storage                         | -     | 11    | 148   
|Allowance for doubtful accounts | -     | -     | 741   
|                                | 4,222 | 5,211 | 24,428



Note



| | 14 | Financial costs
| | -- | ---------------



|Amounts in US$ '000                            | 2016    | 2015    | 2014   
|---------------------------------------------- | ------- | ------- | -------
|Financial expenses                             |         |         |        
|Interest and amortisation of debt issue costs  | 30,571  | 30,543  | 29,466 
|Less: amounts capitalised on qualifying assets | (255)   | (637)   | (3,112)
|Bank charges and other financial costs         | 3,220   | 4,443   | 2,672  
|Unwinding of long-term liabilities (Note 27)   | 2,693   | 2,575   | 1,972  
|Financial income                               |         |         |        
|Interest received                              | (2,128) | (1,269) | (3,376)
|                                               | 34,101  | 35,655  | 27,622 



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 15 | Tax reforms in Colombia
| | -- | -----------------------



A new tax reform
has been enacted in Colombia. The legislation includes significant changes to certain corporate income tax and statutory income
tax provisions, including rate reductions and the repeal of certain corporate-level taxes. The legislation also aims to raise
tax revenue mostly by increasing the rate of the value added tax (VAT) to 19% (from 16%) and through a variety of excise taxes. Most
of the tax provisions are effective 1 January 2017.



The legislation
also includes the following provisions that are intended to simplify the corporate income tax system by:



| | · | Eliminating the “CREE” tax
on corporations and the CREE surtax (CREE is the Spanish acronym for the “fairness tax”).
| | - | --------------------------------------------------------------------------------------------------------------------



| | · | Introducing a temporary income surtax of
6% for 2017 and 4% for 2018.
| | - | ---------------------------------------------------------------------



Accordingly, with
this tax reform, the corporate income tax will have the following rate schedule (applied beyond a limited profit threshold):



| | · | 40% in 2017 (34% income tax plus 6% income
surtax)
| | - | --------------------------------------------------



| | · | 37% in 2018 (33% income tax plus 4% income
surtax)
| | - | --------------------------------------------------



| | · | 33% in 2019.
| | - | ------------



There is an increase
in the tax rate on deemed income relating to increases in a taxpayer’s net worth (i.e., the increase in the value of a taxpayer’s
assets); the rate is increased from 3% to 3.5%.



Other changes to
the income tax law are the following:



| | · | New withholding tax on dividends—with
the applicable rates for non-resident shareholders of: (1) 5% for dividends distributed out of the distributing entity’s
previously taxed profits; and (2) 35% for dividends distributed out of the distributing entity’s previously untaxed profits,
plus an additional 5% after having applied and deducted the initial 35% withholding.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | A general 15% withholding tax rate for
taxable income accrued by non-residents without a permanent establishment (certain special rates may apply).
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Lengthen the statute of limitations with
respect to tax returns and assessments.
| | - | --------------------------------------------------------------------------------



| | · | Limit loss carryforwards to 12 years.
| | - | -------------------------------------



| | · | Allow for a deduction of VAT paid on certain
acquisitions or imports of capital goods when calculating the taxpayer’s income tax liability.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------



| | · | Retain the tax on long-term capital gains
at 10% for both corporations and non-residents.
| | - | -----------------------------------------------------------------------------------------



The legislation
also revises and refines tax accounting standards based on IFRS rules.



F-35


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 16 | Income tax
| | -- | ----------



|Amounts in US$ '000           | 2016   | 2015     | 2014    
|----------------------------- | ------ | -------- | --------
|Current tax                   | 12,359 | 7,262    | 23,574  
|Deferred income tax (Note 17) | (555)  | (24,316) | (18,379)
|                              | 11,804 | (17,054) | 5,195   



The tax on the Group’s (loss) 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                                                                                   | 2016     | 2015      | 2014   
|----------------------------------------------------------------------------------------------------- | -------- | --------- | -------
|(Loss) Profit before tax                                                                              | (48,842) | (301,620) | 21,125 
|Tax losses from non-taxable jurisdictions                                                             | 12,318   | 15,852    | 5,010  
|Taxable (loss) profit                                                                                 | (36,524) | (285,768) | 26,135 
|                                                                                                      |          |           |        
|Income tax calculated at domestic tax rates applicable to Profit (Losses) in the respective countries | 809      | (62,589)  | 7,606  
|Tax losses where no deferred income tax is recognised                                                 | 6,616    | 16,325    | 148    
|Effect of currency translation on tax base                                                            | 2,840    | 6,776     | (8,128)
|Changes in the income tax rate (Note 15)                                                              | (220)    | 625       | 691    
|Non recoverable tax loss carry-forwards                                                               | -        | 15,537    | -      
|Non-taxable results (a)                                                                               | 1,759    | 6,272     | 4,878  
|Income tax                                                                                            | 11,804   | (17,054)  | 5,195  

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



Under current Bermuda law, the Company is
not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister
of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035.
Income tax rates in those countries where the Group operates (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 40%.



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



|Amounts in US$ '000             | 2016    | 2015    | 2014   
|------------------------------- | ------- | ------- | -------
|Argentina                       | 2,908   | 3,834   | 6,707  
|Chile (a)                       | 280,290 | 209,910 | 105,293
|Brazil (a)                      | 16,057  | -       | 3,191  
|Total tax losses at 31 December | 299,255 | 213,744 | 115,191

(a) Taxable losses have no expiration
date.



F-36


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 16 | Income Tax (continued)
| | -- | ----------------------



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.



Expiring dates for tax losses accumulated at
31 December 2016 are:



|Expiring date | Amounts in US$ '000 | 
|------------- | ------------------- | 
|2017          | 1,053               | 
|2020          | 873                 | 
|2021          | 982                 | 



Note



| | 17 | Deferred income tax
| | -- | -------------------



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



|Amounts in US$ '000              | 2016   | 2015   
|-------------------------------- | ------ | -------
|Deferred tax at 1 January        | 17,691 | 3,130  
|Reclassification (a)             | 574    | (6,061)
|Currency translation differences | 1,463  | (3,694)
|Income statement credit          | 555    | 24,316 
|Deferred tax at 31 December      | 20,283 | 17,691 

(a) 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 2016 and 2015 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 | 31,748                   | -                                                         | (12,523)                           | 19,225         | 
|Taxable losses                                              | 2,898                    | 1,463                                                     | (533)                              | 3,828          | 
|Total 2016                                                  | 34,646                   | 1,463                                                     | (13,056)                           | 23,053         | 
|Total 2015                                                  | 33,195                   | (3,694)                                                   | 5,145                              | 34,646         | 



F-37


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 17 | Deferred income tax (continued)
| | -- | -------------------------------



|Amounts in US$ '000                                | At the beginning of year | Credited to
        
        net profit | Reclassification (a) | At end
        
        of year
|-------------------------------------------------- | ------------------------ | --------------------------------------- | -------------------- | -------------------------------
|Deferred tax liabilities                           |                          |                                         |                      |                                
|Difference in depreciation
        rates and other | (26,016)                 | 8,708                                   | -                    | (17,308)                       
|Taxable losses                                     | 9,061                    | 4,903                                   | 574                  | 14,538                         
|Total 2016                                         | (16,955)                 | 13,611                                  | 574                  | (2,770)                        
|Total 2015                                         | (30,065)                 | 19,171                                  | (6,061)              | (16,955)                       

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



Note



| | 18 | Earnings per share
| | -- | ------------------



|Amounts in US$ '000 except for shares               | 2016       | 2015       | 2014      
|--------------------------------------------------- | ---------- | ---------- | ----------
|Numerator:                                          |            |            |           
|(Loss) Profit for the year attributable to owners   | (49,092)   | (234,031)  | 8,085     
|Denominator:                                        |            |            |           
|Weighted average number of shares used in basic EPS | 59,777,145 | 57,759,001 | 56,396,812
|(Losses) Earnings after tax per share (US$) – basic | (0.82)     | (4.05)     | 0.14      



|Amounts in US$ '000 except for shares                                                                                     | 2016 (a)   | 2015       | 2014      
|------------------------------------------------------------------------------------------------------------------------- | ---------- | ---------- | ----------
|Weighted average number of shares used in basic EPS                                                                       | 59,777,145 | 57,759,001 | 56,396,812
|Effect of dilutive potential common shares                                                                                |            |            |           
|Stock awards at US$ 0.001                                                                                                 |            | -          | 2,443,600 
|Weighted average
        number of common shares for the
        
        purposes of
        diluted earnings per shares | 59,777,145 | 57,759,001 | 58,840,412
|(Losses) Earnings after tax per share (US$) – diluted                                                                     | (0.82)     | (4.05)     | 0.14      



(a) For the year ended 31 December
2016, there were 1,390,706 (1,032,279 in 2015) of potential shares that could have a dilutive impact but were considered antidilutive
due to negative earnings.



F-38


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 19 | 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(b) | Total    
|---------------------------------------------------- |  | -------------------- | -------------------------------------------------- | ----------------------------------- | ---------------------------------- | ------------------------- | ------------------------------------ | ---------
|Cost at 1 January 2014                               |  | 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) (c)                         | (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)(a)           | 954                                                | -                                   | 272                                | 36,543                    | 12,299                               | 45,428   
|Currency translation differences                     |  | (27,522)             | (182)                                              | (2,577)                             | (92)                               | -                         | (1,510)                              | (31,883) 
|Disposals                                            |  | (241)                | (13)                                               | (1,685)                             | (84)                               | -                         | -                                    | (2,023)  
|Write-off / Impairment loss                          |  | (128,956)            | -                                                  | (13,242)                            | -                                  | (7,376)                   | (30,084) (d)                         | (179,658)
|Transfers                                            |  | 60,404               | 929                                                | 30,690                              | 895                                | (58,769)                  | (34,149)                             | -        
|Cost at 31 December 2015                             |  | 648,992              | 13,745                                             | 124,832                             | 10,518                             | 29,823                    | 87,000                               | 914,910  
|                                                     |  |                      |                                                    |                                     |                                    |                           |                                      |          
|Additions                                            |  | (3,531) (a)          | 406                                                | 466                                 | -                                  | 20,322                    | 18,181                               | 35,844   
|Currency translation differences                     |  | 16,132               | 126                                                | 2,077                               | 35                                 | 73                        | 790                                  | 19,233   
|Disposals                                            |  | -                    | (22)                                               | -                                   | -                                  | -                         | -                                    | (22)     
|Write-off / Impairment reversal                      |  | 5,664                | -                                                  | -                                   | -                                  | -                         | (31,366) (e)                         | (25,702) 
|Transfers                                            |  | 24,984               | 102                                                | 5,038                               | -                                  | (17,292)                  | (12,832)                             | -        
|Cost at 31 December 2016                             |  | 692,241              | 14,357                                             | 132,413                             | 10,553                             | 32,926                    | 61,773                               | 944,263  
|Depreciation and write-down at 1 January 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)
|Depreciation                                         |  | (61,080)             | (2,702)                                            | (10,788)                            | (920)                              | -                         | -                                    | (75,490) 
|Disposals                                            |  | -                    | 8                                                  | -                                   | -                                  | -                         | -                                    | 8        
|Currency translation differences                     |  | (2,486)              | (38)                                               | (296)                               | (16)                               | -                         | -                                    | (2,836)  
|Depreciation and write-down at 31 December 2016      |  | (384,739)            | (10,049)                                           | (71,698)                            | (4,131)                            | -                         | -                                    | (470,617)
|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  



|Carrying amount at 31
        
        December 2016 |  | 307,502 | 4,308 | 60,715 | 6,422 | 32,926 | 61,773 | 473,646
|---------------------------------------------------- |  | ------- | ----- | ------ | ----- | ------ | ------ | -------



F-39


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016




Note



| | 19 | Property, plant and equipment (continued)
| | -- | -----------------------------------------



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



(b) Exploration wells movement
and balances are shown in the table below; seismic and other exploratory assets amount to US$ 53,523,000 (US$ 64,094,000 in 2015
and US$ 99,939,000 in 2014).



|Amounts in US$ '000                   | Total    | 
|------------------------------------- | -------- | 
|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   | 
|Additions                             | 15,088   | 
|Write-offs                            | (19,949) | 
|Transfers                             | (9,795)  | 
|Exploration wells at 31 December 2016 | 8,250    | 



As of 31 December 2016, there were two exploratory
wells that have been capitalised for a period less than a year amounting to US$ 8,250,000.



(c) 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.



(d) 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.



(e) Corresponds to the write-off
of five wells drilled in previous years in the Chilean blocks for which no additional work would be performed, the loss generated
by the write-off of the seismic cost for Llanos 62 Block in Colombia generated by the relinquishment of the area in September 2016.
In addition, during September 2016, five blocks in Brazil were relinquished so the associated investment was written off.



F-40


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



20       Subsidiary
undertakings



The following chart illustrates main companies
of the Group structure as of 31 December 2016 (a):







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



F-41


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



20       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)          
|                 | 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)                                       |  |  | 80%
    (a) (c)       
|                 | GeoPark
    Latin America Coöperatie U.A. (The Netherlands)               |  |  | 100%                  
|                 | GeoPark
    Colombia Coöperatie U.A. (The Netherlands)                    |  |  | 80%
    (a) (c)       
|                 | GeoPark
    S.A.C. (Peru)                                                 |  |  | 100%
    (a)          
|                 | GeoPark
    Perú S.A.C. (Peru)                                            |  |  | 100%
    (a)          
|                 | GeoPark
    Operadora del Perú S.A.C. (Peru)                              |  |  | 100%
    (a)          
|                 | GeoPark
    Peru Coöperatie U.A. (The Netherlands)                        |  |  | 100%                  
|                 | GeoPark
    Brazil Coöperatie U.A. (The Netherlands)                      |  |  | 100%                  
|                 | GeoPark
    Colombia E&P S.A.(Panama)                                     |  |  | 100%
    (b)          
|                 | GeoPark
    Colombia E&P Sucursal Colombia(Colombia)                      |  |  | 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)           
|                 | 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
    Block (Argentina)                                              |  |  | 18%                   
|                 | Sierra
    del Nevado Block (Argentina)                                   |  |  | 18%                   
|                 | CN-V
    Block (Argentina)                                                |  |  | 50%
    (e)           
|                 | Manati
    Field (Brazil)                                                 |  |  | 10%                   

| | (a) | Indirectly
                                         owned.
| | --- | ----------------------------------------------------------



| | (b) | Dormant
                                         companies.
| | --- | -----------------------------------------------------------



| | (c) | LG
                                         International has 20% 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-42


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 21 | Prepaid taxes
| | -- | -------------



|Amounts in US$ '000            | 2016   | 2015   | 
|------------------------------ | ------ | ------ | 
|V.A.T.                         | 14,052 | 14,486 | 
|Income tax payments in advance | 4,517  | 4,844  | 
|Other prepaid taxes            | 98     | 1,037  | 
|Total prepaid taxes            | 18,667 | 20,367 | 
|Classified as follows:         |        |        | 
|Current                        | 15,815 | 19,195 | 
|Non current                    | 2,852  | 1,172  | 
|Total prepaid taxes            | 18,667 | 20,367 | 



Note



22       Inventories



|Amounts in US$ '000  |  | 2016  | 2015  | 
|-------------------- |  | ----- | ----- | 
|Crude oil            |  | 1,521 | 2,120 | 
|Materials and spares |  | 1,994 | 2,144 | 
|                     |  | 3,515 | 4,264 | 



Note



23       Trade
receivables and Prepayments and other receivables



|Amounts in US$ '000                         | 2016   | 2015   | 
|------------------------------------------- | ------ | ------ | 
|Trade receivables                           | 18,426 | 13,480 | 
|                                            | 18,426 | 13,480 | 
|To be recovered from co-venturers (Note 32) | 3,311  | 4,634  | 
|Related parties receivables (Note 32)       | 42     | 38     | 
|Prepayments and other receivables           | 4,290  | 6,605  | 
|                                            | 7,643  | 11,277 | 
|Total                                       | 26,069 | 24,757 | 
|                                            |        |        | 
|Classified as follows:                      |        |        | 
|Current                                     | 25,828 | 24,537 | 
|Non current                                 | 241    | 220    | 
|Total                                       | 26,069 | 24,757 | 



Trade receivables that are aged by less
than three months are not considered impaired. As of 31 December 2016, there are no balances (US$ 51,000 in 2015) that were aged
by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no
balances due between 31 days and 90 days as of 31 December 2016 and 2015.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 23 | Trade receivables and Prepayments and other receivables
(continued)
| | -- | -------------------------------------------------------------------



Movements on the Group provision for impairment
are as follows:



|Amounts in US$ '000              | 2016 | 2015  | 
|-------------------------------- | ---- | ----- | 
|At 1 January                     | 596  | 774   | 
|Foreign exchange loss / (income) | 145  | (178) | 
|                                 | 741  | 596   | 





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



24       Financial
instruments by category



|Amounts in US$ '000                           | Loans and receivables
|--------------------------------------------- | ---------------------
|                                              |                      
|Assets as per statement of financial position |                      
|Trade receivables                             |                      
|To be recovered from co-venturers (Note 32)   |                      
|Other financial assets (a)                    |                      
|Cash at bank and in hand                      |                      
|                                              |                      



(a) 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.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 24 | Financial instruments by category (continued)
| | -- | ---------------------------------------------



|Amounts in US$ '000                                | Other financial liabilities at amortised cost |        
|-------------------------------------------------- | --------------------------------------------- | -------
|                                                   | 2016                                          | 2015   
|Liabilities as per statement of financial position |                                               |        
|Trade payables                                     | 23,650                                        | 25,906 
|Payables to related parties (Note 32)              | 27,801                                        | 21,045 
|To be paid to co-venturers (Note 32)               | 1,614                                         | 113    
|Borrowings                                         | 358,672                                       | 378,673
|                                                   | 411,737                                       | 425,737



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                                     | 2016   | 2015   | 
|------------------------------------------------------- | ------ | ------ | 
|Trade receivables                                       |        |        | 
|Counterparties with an external credit rating (Moody’s) |        |        | 
|B2                                                      | 7,056  | -      | 
|B3                                                      | -      | 5,834  | 
|Baa3                                                    | 3,729  | 6,315  | 
|Counterparties without an external credit rating        |        |        | 
|Group1 (a)                                              | 7,641  | 1,331  | 
|Total trade receivables                                 | 18,426 | 13,480 | 



(a) Group 1 – existing customers
(more than 6 months) with no defaults in the past.



All trade receivables are denominated in US
Dollars, except in Brazil where are denominated in Brazilian Real.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 24 | Financial instruments by category (continued)
| | -- | ---------------------------------------------



|Cash at bank and other financial assets
        (a)                                                                 |  |        |        | 
|------------------------------------------------------------------------------------------------------------------- |  | ------ | ------ | 
|Amounts in US$ '000                                                                                                 |  | 2016   | 2015   | 
|Counterparties with an external credit rating
        (Moody’s,
        
        S&P, Fitch, BRC Investor Services) |  |        |        | 
|A1                                                                                                                  |  | 813    | 862    | 
|A2                                                                                                                  |  | -      | 46,272 | 
|Aa2                                                                                                                 |  | -      | 460    | 
|Aa3                                                                                                                 |  | 42,798 | -      | 
|A3                                                                                                                  |  | -      | 1,675  | 
|AAA                                                                                                                 |  | 14     | -      | 
|Baa2                                                                                                                |  | 4,094  | -      | 
|Ba1                                                                                                                 |  | -      | 3,705  | 
|Baa1                                                                                                                |  | 100    | 105    | 
|Ba3                                                                                                                 |  | 3,497  | -      | 
|B3                                                                                                                  |  | 10     | -      | 
|Baa3                                                                                                                |  | -      | 29,425 | 
|Caa2                                                                                                                |  | -      | 160    | 
|BBB-                                                                                                                |  | -      | 56     | 
|Counterparties without an external credit rating                                                                    |  | 44,252 | 14,424 | 
|Total                                                                                                               |  | 95,578 | 97,144 | 



(a) The remaining balance sheet
item ‘cash at bank and in hand’ corresponds to cash on hand amounting to US$ 12,000 (US$ 10,000 in 2015).



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 2016         |                  |                       |                       |              | 
|Borrowings                  | 48,958           | 43,304                | 355,064               | -            | 
|Trade payables              | 23,650           | -                     | -                     | -            | 
|Payables to related parties | 1,561            | 1,561                 | 22,018                | -            | 
|                            | 74,169           | 44,865                | 377,082               | -            | 
|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               | -            | 



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 25 | Share capital
| | -- | -------------



|Issued share capital                         | 2016          | 2015          | 
|-------------------------------------------- | ------------- | ------------- | 
|Common stock (amounts in US$ ‘000)           | 60            | 59            | 
|The share capital is distributed as follows: |               |               | 
|Common shares, of nominal US$ 0.001          | 59,940,881    | 59,535,614    | 
|Total common shares in issue                 | 59,940,881    | 59,535,614    | 
|                                             |               |               | 
|Authorised share capital                     |               |               | 
|US$ per share                                | 0.001         | 0.001         | 
|                                             |               |               | 
|Number of common shares (US$ 0.001 each)     | 5,171,949,000 | 5,171,949,000 | 
|Amount in US$                                | 5,171,949     | 5,171,949     | 



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



Common shares



As of 31 December 2016, 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 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                       
|Stock awards                          | Feb 2016 | 0.3                      | 59.8                      | 59                       
|Stock awards                          | Dec 2016 | 0.5                      | 60.3                      | 60                       
|Stock awards                          | Dec 2016 | 0.1                      | 60.4                      | 60                       
|Buyback program                       | Dec 2016 | (0.6)                    | 59.8                      | 60                       
|Shares outstanding at the end of 2016 |          |                          | 59.8                      | 60                       



F-47


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 25 | Share capital (continued)
| | -- | -------------------------



Stock Award Program and Other Share Based
Payments



On 15 December 2016, 379,500 common shares
were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 3,940,000.



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 8 February 2016, 468,405 shares were
issued to Executive Directors and key management as bonus compensation, generating a share premium of US$ 1,512,000.



On 6 September 2016, 8,333 shares were issued
pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 38,000.



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 2016, the Company issued 137,897
(99,555 in 2015 and 2,301 in 2014) shares to Non-Executive Directors in accordance with contracts as compensation, generating a
share premium of US$ 541,848 (US$ 486,692 in 2015 and US$ 22,413 in 2014). 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. During 2016, the Repurchase Program began on 6 April 2016 and then was resumed during the year until November
2016. 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 2016, 2015 and 2014, the Company purchased 588,868, 370,074 and 73,082 common shares for a total amount of US$ 1,991,000,
US$ 1,615,000 and US$ 388,000, respectively. These transactions had no impact on the Company’s results.



F-48


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 26 | Borrowings
| | -- | ----------



|Amounts in US$ '000                              | 2016    | 2015    | 
|------------------------------------------------ | ------- | ------- | 
|Outstanding amounts as of 31 December            |         |         | 
|Notes GeoPark Latin America Agencia en Chile (a) | 304,059 | 302,495 | 
|Banco Itaú (b)                                   | 49,763  | 69,142  | 
|Banco de Chile (c)                               | 4,709   | 7,036   | 
|Banco de Crédito e Inversiones (d)               | 141     | -       | 
|                                                 | 358,672 | 378,673 | 
|Classified as follows:                           |         |         | 
|Current                                          | 39,283  | 35,425  | 
|Non current                                      | 319,389 | 343,248 | 



The fair value of these financial
instruments at 31 December 2016 amounts to US$ 346,180,000 (US$ 352,410,000 in 2015). The fair values are based on cash flows
discounted using a rate based on the borrowing rate of 7.60% (2015: 7.51%) and are within level 2 of the fair value
hierarchy.



(a) During February 2013, the Company successfully
placed US$ 300 million 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., GeoPark Colombia Cooperatie U.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 the 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 4.6 times and the EBITDA to Interest ratio was 2.7 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.



(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.



F-49


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 26 | Borrowings (continued)
| | -- | ----------------------



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.
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) to
increase the variable interest rate to six-month LIBOR + 4.0%. As a result of the above, in March and September 2016 the Company
paid US$ 10,000,000 respectively corresponding to principal payments under the current principal amortization schedule.



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.



(c) 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.



(d) During February 2016, GeoPark executed
a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of vehicles for the
Chilean operation. The interest rate applicable to this loan is 4.14% per annum. The interest and the principal will be paid on
monthly basis, with final maturity on February 2019.



As of the date of these consolidated financial
statements, the Group has available credit lines for over US$ 31,000,000.



F-50


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 27 | Provisions and other long-term liabilities
| | -- | ------------------------------------------



|Amounts in US$ ‘000            | Asset retirement obligation | Deferred
        Income | Other   | Total  
|------------------------------ | --------------------------- | ----------------------- | ------- | -------
|At 1 January 2015              | 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 
|Addition to provision          | 1,195                       | 1,375                   | 2,686   | 5,256  
|Recovery of abandonments costs | (5,504)                     | -                       | -       | (5,504)
|Foreign currency translation   | 1,614                       | -                       | -       | 1,614  
|Exchange difference            | (1,614)                     | -                       | 538     | (1,076)
|Amortisation                   | -                           | (2,924)                 | -       | (2,924)
|Unwinding of discount          | 2,554                       | -                       | 139     | 2,693  
|At 31 December 2016            | 29,862                      | 3,484                   | 9,163   | 42,509 



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. The addition in
2016 corresponds to the deferred income related to the take or pay provision associated to gas sales in Brazil, that Petrobras
will make up in the future.



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.
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. So, the additions in 2016 reflects the future contingent payments in connection with claims of third
parties.



F-51


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 28 | Trade and other payables
| | -- | ------------------------



|Amounts in US$ '000                      | 2016   | 2015   | 
|---------------------------------------- | ------ | ------ | 
|V.A.T                                    | 1,102  | 908    | 
|Trade payables                           | 23,650 | 25,906 | 
|Payables to related parties (a)(Note 32) | 27,801 | 21,045 | 
|Customer advance payments (Note 3)       | 20,000 | -      | 
|Staff costs to be paid                   | 7,749  | 6,702  | 
|Royalties to be paid                     | 1,503  | 2,475  | 
|Taxes and other debts to be paid         | 3,355  | 8,197  | 
|To be paid to co-venturers (Note 32)     | 1,614  | 113    | 
|                                         | 86,774 | 65,346 | 
|Classified as follows:                   |        |        | 
|Current                                  | 52,008 | 45,790 | 
|Non current                              | 34,766 | 19,556 | 

(a)The outstanding
amount corresponds to advanced cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s
blocks. The expected maturity of these balances is July 2020 and the applicable interest rate is 8% per annum.



The average credit period (expressed as
creditor days) during the year ended 31 December 2016 was 44 days (2015: 38 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



| | 29 | 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.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 29 | Share-based payment (continued)
| | -- | -------------------------------



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



| | · | All employees are eligible.
| | - | ---------------------------



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



| | · | Vesting period is three years.
| | - | ------------------------------



| | · | Each employee could receive up to three
salaries by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should
be above US$ 3 and obtain the Company minimum production, adjusted EBITDA and reserves target for the year of vesting.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Also during 2016, 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.



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 loss / profit
|--------------------------------------------- | --------------------------- | ------------------------------ | -------------------- | -------------------- | ---------------------- | ------------------------------------
|2016                                          | 2015                        | 2014                           |                     
|2016                                          | -                           | 1,619,105                      | -                    | -                    | 1,619,105              | 445                                 
|2014                                          | 500,000                     | -                              | 10,000               | -                    | 490,000                | 821                                 
|2013                                          | -                           | -                              | -                    | -                    | -                      | -                                   
|2012                                          | 379,500                     | -                              | -                    | 379,500              | -                      | 855                                 
|2011                                          | -                           | -                              | -                    | -                    | -                      | -                                   
|2010                                          | -                           | -                              | -                    | -                    | -                      | -                                   
|Subtotal                                      |                             |                                |                      |                      |                        | 2,121                               
|Stock
    options to Executive Directors      | -                           | -                              | -                    | -                    | -                      | -                                   
|Shares
    granted to Non-Executive Directors | 8,285                       | 129,612                        | -                    | 137,897              | -                      | 400                                 
|VCP
    2013                                  | -                           | -                              | -                    | -                    | -                      | -                                   
|VCP
    2016                                  | -                           | -                              | -                    | -                    | -                      | 934                                 
|Executive
    Directors Bonus                 | 123,839                     | -                              | 100,619              | 23,220               | -                      | (325)                               
|Key
    Management Bonus                      | 445,185                     | 82,306                         | -                    | 445,185              | 82,306                 | 202                                 
|Stock
    awards for service contracts        | -                           | 8,333                          | -                    | 8,333                | -                      | 35                                  
|                                              | 1,456,809                   | 1,839,356                      | 110,619              | 994,135              | 2,191,411              | 3,367                               



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



F-53


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 30 | Interests in Joint operations
| | -- | -----------------------------



The Group has interests in 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 recognized in the consolidated statement of
financial position and statement of income:



|Subsidiary
        /
        
        Joint
        operation    | Interest | PP&E
        
        E&E
        Assets | Other
        
        Assets | Total
        
        Assets | Total
        
        Liabilities | NET
    ASSETS/ (LIABILITIES) | Revenue | Operating
    (loss)profit
|---------------------------------------------------------------- | -------- | ---------------------------------------- | ----------------------------- | ----------------------------- | ---------------------------------- | ----------------------------- | ------- | --------------------------
|2016                                                             |          |                                          |                               |                               |                                    |                               |         |                           
|GeoPark
    Magallanes Ltda.                                     |         
|Tranquilo
    Block                                              | 50%      | -                                        | 55                            | 55                            | (424)                              | (369)                         | -       | (40)                      
|GeoPark
    TdF S.A.                                             |          |                                          |                               |                               |                                    |                               |         |                           
|Flamenco
    Block                                               | 50%      | 15,108                                   | -                             | 15,108                        | (93)                               | 15,015                        | 1,004   | (1,988)                   
|Campanario
    Block                                             | 50%      | 29,718                                   | -                             | 29,718                        | (1)                                | 29,717                        | -       | (399)                     
|Isla
    Norte Block                                             | 60%      | 9,920                                    | -                             | 9,920                         | (1)                                | 9,919                         | 5       | (438)                     
|Colombia
    SAS                                                 |          |                                          |                               |                               |                                    |                               |         |                           
|Yamu/Carupana
    Block                                          | 89,5%    | 3,418                                    | -                             | 3,418                         | (2,289)                            | 1,129                         | 18      | (307)                     
|Llanos
    34 Block                                              | 45%      | 79,811                                   | 693                           | 80,504                        | (3,943)                            | 76,561                        | 125,400 | 83,193                    
|Llanos
    32 Block                                              | 10%      | 3,819                                    | -                             | 3,819                         | (211)                              | 3,608                         | 2,303   | 1,043                     
|GeoPark
    Brazil Exploração y Produção de Petróleo e Gas Ltda. |         
|Manati
    Field                                                 | 10%      | 54,166                                   | 15,791                        | 69,957                        | (8,442)                            | 61,515                        | 29,719  | 20,945                    
|                                                                 |          |                                          |                               |                               |                                    |                               |         |                           



F-54


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 30 | Interests in Joint operations (continued)
| | -- | -----------------------------------------



|Subsidiary
        /
        
        Joint
        operation    | Interest        | PP&E
        E&E
Assets | Other
        Assets | Total
        Assets | Total
        Liabilities | NET
    ASSETS/ (LIABILITIES) | Revenue | Operating
    (loss)profit
|---------------------------------------------------------------- | --------------- | ----------------------- | -------------------- | -------------------- | ------------------------- | ----------------------------- | ------- | --------------------------
|2015                                                             |                 |                         |                      |                      |                           |                               |         |                           
|GeoPark
    Magallanes Ltda.                                     |                
|Tranquilo
    Block                                              | 50%             | -                       | 45                   | 45                   | (2)                       | 43                            | -       | (69)                      
|GeoPark
    TdF S.A.                                             |                 |                         |                      |                      |                           |                               |         |                           
|Flamenco
    Block                                               | 50%             | 14,932                  | -                    | 14,932               | (53)                      | 14,879                        | 1,810   | (51,411)                  
|Campanario
    Block                                             | 50%             | 27,570                  | -                    | 27,570               | (10)                      | 27,560                        | 13      | (7,267)                   
|Isla
    Norte Block                                             | 60%             | 8,583                   | -                    | 8,583                | (16)                      | 8,567                         | 355     | (5,661)                   
|Colombia
    SAS                                                 |                 |                         |                      |                      |                           |                               |         |                           
|Llanos
    17 Block                                              | 36.84%          | -                       | -                    | -                    | (93)                      | (93)                          | 3       | (6,325)                   
|Yamu/Carupana
    Block                                          | 89,5%           | 3,569                   | 2,061                | 5,630                | (2,235)                   | 3,395                         | 1,409   | (16,552)                  
|Llanos
    34 Block                                              | 45%             | 76,667                  | 429                  | 77,096               | (3,295)                   | 73,801                        | 114,276 | 53,049                    
|Llanos
    32 Block                                              | 10%             | 3,106                   | 96                   | 3,202                | (213)                     | 2,989                         | 8,258   | (1,343)                   
|GeoPark
    Brazil Exploração y Produção de Petróleo e Gas Ltda. |                
|Manati
    Field                                                 | 10%             | 50,801                  | 12,930               | 63,731               | (10,395)                  | 53,336                        | 32,388  | 20,354                    
|2014                                                             |                 |                         |                      |                      |                           |                               |         |                           
|GeoPark
    Magallanes Ltda.                                     |                
|Tranquilo
    Block                                              | 50%             | 109                     | -                    | 109                  | (125)                     | (16)                          | -       | (220)                     
|GeoPark
    TdF S.A.                                             |                 |                         |                      |                      |                           |                               |         |                           
|Flamenco
    Block                                               | 50%             | 35,110                  | -                    | 35,110               | (1,653)                   | 33,457                        | 4,385   | (6,278)                   
|Campanario
    Block                                             | 50%             | 34,309                  | -                    | 34,309               | (7,086)                   | 27,223                        | 216     | (6,151)                   
|Isla
    Norte Block                                             | 60%             | 12,208                  | -                    | 12,208               | (241)                     | 11,967                        | 901     | (283)                     
|Colombia
    SAS                                                 |                 |                         |                      |                      |                           |                               |         |                           
|Llanos
    17 Block                                              | 36.84%          | 6,037                   | -                    | 6,037                | (122)                     | 5,915                         | 1,292   | (160)                     
|Yamu/Carupana
    Block                                          | 90%
    - 79.5% | 16,590                  | 2,211                | 18,801               | (2,727)                   | 16,074                        | 10,560  | (2,916)                   
|Llanos
    34 Block                                              | 45%             | 76,726                  | 1,514                | 78,240               | (3,380)                   | 74,860                        | 176,624 | 96,889                    
|Llanos
    32 Block                                              | 10%             | 8,909                   | 27                   | 8,936                | (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)                  | 78,686                        | 35,621  | 18,935                    
|                                                                 |                 |                         |                      |                      |                           |                               |         |                           



Capital commitments are disclosed in Note 31
(b).



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 31 | Commitments
| | -- | -----------



(a) Royalty commitments



In Colombia, royalties on production are
payable to the Colombian Government and are determined on a field-by-field basis using a level of production sliding scale at a
rate which ranges between 6%-8%. The Colombian National Hydrocarbons Agency (“ANH”) also has an additional economic
right equivalent to 1% of production, net of royalties.



Under Law 756 of 2002, as modified by Law
1530 of 2012, the royalties on Colombian production of light and medium oil are calculated on a field-by-field basis, using the
following sliding scale:



|Average daily production in barrels | Production Royalty rate            | 
|----------------------------------- | ---------------------------------- | 
|Up to 5,000                         | 8%                                 | 
|5,000 to 125,000                    | 8% + (production - 5,000)*0.1      | 
|125,000 to 400,000                  | 20%                                | 
|400,000 to 600,000                  | 20% + (production - 400,000)*0.025 | 
|Greater than 600,000                | 25%                                | 



When the API is lower than 15°, the
payment is reduced to the 75% of the total calculation.



In accordance with Llanos 34 Block operation
contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and
the WTI exceeds the base price settled in table A, the 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%     | 



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 31 | Commitments (continued)
| | -- | -----------------------



(a) Royalty commitments (continued)



Additionally, under the terms of the Winchester
Stock Purchase Agreement, GeoPark is obligated to make certain payments to the previous owners of Winchester based on the production
and sale of hydrocarbons discovered by exploration wells drilled after 25 October 2011.  These payments involve an overriding
royalty equal to an estimated 4% 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$ 80,000,000 and US$ 90,000,000. During 2016, the Company has accrued
and paid US$ 5,414,000 (US$ 7,100,000 in 2015 and US$ 24,600,000 in 2014) and US$ 3,772,000 (US$ 9,200,000 in 2015 and
US$ 21,000,000 in 2014), respectively.



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



In Brazil, the Brazilian National Petroleum,
Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly minimum prices for petroleum produced in concessions
for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5%
and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação)
and concession agreement. In determining the percentage of royalties applicable to a concession, the ANP takes into consideration,
among other factors, the geological risks involved and the production levels expected. In the Manatí Block, royalties are
calculated at 7.5% of gas production.



In Argentina, crude oil production accrues
royalties payable to the Provinces of 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



Colombia



The VIM 3 Block minimum investment program
consists of 200 sq km of 2D seismic and drilling one exploratory well, with a total estimated investment of US$ 22,290,800 during
the initial three year exploratory period ending 2 September 2018.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 31 | Commitments (continued)
| | -- | -----------------------



(b) Capital commitments (continued)



Colombia (continued)



The Llanos 34 Block (45% working interest)
has committed to drill two exploratory wells, one before 15 March 2017 and the other before 14 September 2019. The remaining commitment
amounts to US$ 6,255,000 at GeoPark’s working interest. As of the date of these consolidated financial statements, GeoPark
is awaiting the ANH’s approval of US$ 3,555,000 related to one well already drilled that was presented as fulfilment of the
commitment to be performed before 14 September 2019.



The Llanos 32 Block (10% working interest)
has committed to drill one exploratory well before 20 August 2018. The remaining commitment amounts to US$ 617,100 at GeoPark’s
working interest.



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.



Chile



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 6 November 2017. The remaining commitment amounts to US$ 2,100,000. On 6 January 2017, GeoPark proposed to extend
the second exploratory period for an additional period of 18 months. As of the date of these consolidated financial statements
the Chilean Ministry has not replied.



On 29 September 2016, the Campanario Block
and Isla Norte Block’s CEOP were modified so the investment commitment for the first exploratory period has already been
fulfilled. The investments to be made in the second exploratory period will be assumed 100% by GeoPark. The future investment commitments
assumed by GeoPark for the second exploratory period are up to:



F-58


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 31 | Commitments (continued)
| | -- | -----------------------



(b) Capital commitments (continued)



Chile (continued)



| | · | Campanario Block: 3 exploratory wells before
10 July 2019 (US$ 10,963,000)
| | - | --------------------------------------------------------------------------



| | · | Isla Norte Block: 2 exploratory wells before
7 May 2019 (US$ 6,595,000)
| | - | -----------------------------------------------------------------------



As of 31 December 2016, the Company has
established a guarantee for its commitments that amounts to US$ 19,300,000.



Brazil



The future investment commitments assumed
by GeoPark are up to:



| | · | SEAL-T-268 Block: before 15 May 2017 (US$
230,000)
| | - | --------------------------------------------------



| | · | REC-T-94 Block: 2 exploratory wells before
12 July 2017 (US$ 2,300,000)
| | - | -----------------------------------------------------------------------



| | · | REC-T-93 Block: 3D seismic before 20 December
2018 (US$ 50,000)
| | - | ---------------------------------------------------------------



| | · | REC-T-128 Block: 1 exploratory well before
20 December 2018 (US$ 2,690,000)
| | - | ---------------------------------------------------------------------------



| | · | POT-T-747 Block: 1 exploratory well before
20 December 2018 (US$ 1,840,000)
| | - | ---------------------------------------------------------------------------



| | · | POT-T-882 Block: 35 sq km of 2D seismic
before 20 December 2018 (US$ 480,000)
| | - | -----------------------------------------------------------------------------



| | · | POT-T-619 Block: 1 well before 16 September
2018 (US$ 700,000)
| | - | --------------------------------------------------------------



(c) Operating lease commitments –
Group company as lessee



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



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



During 2016 a total amount of US$ 47,871,000
(US$ 16,731,000 in 2015 and US$ 19,409,000 in 2014) was charged to the income statement and US$ 32,058,000 of operating leases
were capitalised as Property, plant and equipment related to rental of drilling equipment and machinery (US$ 7,102,000 in 2015
and US$ 51,341,000 in 2014).



F-59


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 31 | Commitments (continued)
| | -- | -----------------------



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



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



|Amounts in US$ ’000            | 2016   | 2015   | 2014   | 
|------------------------------ | ------ | ------ | ------ | 
|Operating lease commitments    |        |        |        | 
|Falling due within 1 year      | 67,752 | 12,878 | 37,926 | 
|Falling due within 1 – 3 years | 14,031 | 8,257  | 33,949 | 
|Falling due within 3 – 5 years | 5,066  | 2,456  | 16,109 | 
|Falling due over 5 years       | 114    | 309    | 505    | 
|Total minimum lease payments   | 86,963 | 23,900 | 88,489 | 



Note



| | 32 | Related parties
| | -- | ---------------



Controlling interest



The main shareholders of GeoPark Limited,
a company registered in Bermuda, as of 31 December 2016, are:



|Shareholder                    | Common shares | Percentage of outstanding common shares | 
|------------------------------ | ------------- | --------------------------------------- | 
|James F. Park (a)              | 7,891,269     | 13.17%                                  | 
|Gerald E. O’Shaughnessy(b)     | 7,344,741     | 12.25%                                  | 
|Manchester Financial Group, LP | 7,080,661     | 11.81%                                  | 
|IFC Equity Investments(c)      | 3,456,594     | 5.77%                                   | 
|Juan Cristóbal Pavez(d)        | 2,946,112     | 4.92%                                   | 
|Moneda A.F.I.(e)               | 1,683,571     | 2.81%                                   | 
|Other shareholders             | 29,537,933    | 49.27%                                  | 
|                               | 59,940,881    | 100.00%                                 | 



(a) Held by Energy Holdings,
LLC, which is controlled by James F. Park, a member of our Board of Directors.



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



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



(d) Held through Socoservin Overseas
Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 68,308
common shares held by him personally.



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



F-60


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 32 | 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               | 
|----------------------------------- | ----------------------- | -------------------- | ---------------- | -------------------------- | 
|2016                                |                         |                      |                  |                            | 
|To be recovered from co-venturers   | -                       | 3,311                | Joint Operations | Joint Operations           | 
|Prepayments and other receivables   | -                       | 42                   | LGI              | Partner                    | 
|Payables account                    | -                       | (27,801)             | LGI              | Partner                    | 
|To be paid to co-venturers          | -                       | (1,614)              | Joint Operations | Joint Operations           | 
|Financial costs                     | 1,587                   | -                    | LGI              | Partner                    | 
|Geological and geophysical expenses | 113                     | -                    | Carlos Gulisano  | Non-Executive Director (a) | 
|Administrative expenses             | 371                     | -                    | Pedro Aylwin     | Executive Director (b)     | 
|2015                                |                         |                      |                  |                            | 
|To be recovered from co-venturers   | -                       | 4,634                | Joint Operations | Joint Operations           | 
|Prepayments and other receivables   | -                       | 38                   | LGI              | Partner                    | 
|Payables account                    | -                       | (21,045)             | LGI              | Partner                    | 
|To be paid to co-venturers          | -                       | (113)                | Joint Operations | Joint Operations           | 
|Financial costs                     | 1,560                   | -                    | LGI              | Partner                    | 
|Geological and geophysical expenses | 101                     | -                    | Carlos Gulisano  | Non-Executive Director (a) | 
|Administrative expenses             | 66                      | -                    | Carlos Gulisano  | Non-Executive Director (a) | 
|Administrative expenses             | 377                     | -                    | Pedro Aylwin     | Executive Director (b)     | 
|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 (a) | 
|Administrative expenses             | 114                     | -                    | Carlos Gulisano  | Non-Executive Director (a) | 
|Administrative expenses             | 568                     | -                    | Pedro Aylwin     | Executive Director (b)     | 



(a) Corresponding to consultancy
services.



(b) Corresponding to wages and
salaries for US$ 246,000 (US$ 317,000 in 2015) and bonus for US$ 125,000 (US$ 60,000 in 2015).



F-61


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 32 | Related parties (continued)
| | -- | ---------------------------



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



| | 33 | Fees paid to Auditors
| | -- | ---------------------



|Amounts in US$ '000     | 2016 | 2015 | 2014 
|----------------------- | ---- | ---- | -----
|Audit fees              | 487  | 557  | 620  
|Tax services fees       | 134  | 129  | 281  
|Non-audit services fees | -    | -    | 540  
|Fees paid to auditors   | 621  | 686  | 1,441



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



Note



| | 34 | Business transactions
| | -- | ---------------------



| | a. | 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 agreement was subject to Peru regulatory
approval, which was completed on 1 December 2016 following the issuance of Supreme Decree 031-2016-MEM.



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.



F-62


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 34 | Business transactions (continued)
| | -- | ---------------------------------



| | a. | Peru (continued)
| | -- | ----------------



Entry in Peru (continued)



In accordance with the terms of the agreement,
GeoPark has committed to carry Petroperu on a work program that provides for testing and start-up production of one of the existing
wells in the field, subject to certain technical and economic conditions being met. Expected capital expenditures in 2017 for the
Morona Block are mainly related to facility maintenance and environmental and engineering studies.



| | b. | 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 had written off a receivable with Trayectoria.



Following this transaction, GeoPark continued
to be the operator and have an 89.5% interest in the Carupana Field and 100% in Yamú and Potrillo Fields. The Company recognized,
during 2015, a loss of US$ 296,000 generated by this transaction.



| | c. | 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.



GeoPark has paid a cash consideration of
US$ 140,100,000 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 consolidated financial statements either.



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).



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 34 | Business transactions (continued)
| | -- | ---------------------------------



| | c. | Brazil (continued)
| | -- | ------------------



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.



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.



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.



Note



| | 35 | Impairment test on Property, plant and equipment
| | -- | ------------------------------------------------



Oil price crisis started in the second half
of 2014 and prices fell dramatically, WTI and Brent, the main international oil price markers, fell more than 60% between October
2014 and February 2016. Because of those market conditions, during 2015, the Company undertook a decisive cost cutting program
to ensure its ability to both maximize the work program and preserve its liquidity. The main decisions included:



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



| | - | Deferment of capital projects by regulatory authority
and partner agreement.
| | - | ----------------------------------------------------------------------------



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 35 | Impairment test on Property, plant and equipment (continued)
| | -- | ------------------------------------------------------------



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



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



During February 2015, the 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 since.



As a result of the situation described,
the Company recognized an impairment loss of US$ 149,574,000 in 2015 after evaluating 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.



During 2016 the impairment tests were reviewed.
The main assumptions taken into account for the impairment tests for the blocks below mentioned were:



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



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



| | - | The table “Oil price scenarios” was based
on 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;
| | - | -----------------------------------------------------------------



| | - | 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 2017 approved budget;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------



| | - | The capital expenditures were estimated considering the
drilling campaign necessary to develop the certified reserves;
| | - | ----------------------------------------------------------------------------------------------------------------------





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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016




Note



| | 35 | Impairment test on Property, plant and equipment (continued)
| | -- | ------------------------------------------------------------



| | - | 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 (a):



|          | Amounts in US$ per Bbl.
|--------- | -----------------------
|Year      | Low price (15%)        
|2017      | 45.1                   
|2018      | 49.2                   
|2019      | 54.7                   
|2020      | 58.5                   
|2021      | 58.3                   
|Over 2022 | 57.9                   



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



As a consequence of the evaluation no additional
impairment loss was recognized but part of the impairment recorded in Colombia was reversed for an amount of US$ 5,664,000 due
to increase in estimated market prices for 2017 and 2018 and improvements in cost structure. Peru and Argentina segments have no
associated assets subject to impairment.



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 reversal
would have been lower by approximately US$ 2,100,000.



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Note



| | 36 | Commodity risk management contracts
| | -- | -----------------------------------



During 2016, the Group entered into derivative
financial instruments to manage its exposure to oil price risk. These derivatives were zero-premium collars and were placed with
major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit
Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments
and protect the Group from potential non-performance risk by its counterparties. The Group’s derivatives are accounted for
as non-hedge derivatives as of 31 December 2016 and therefore all changes in the fair values of its derivative contracts are recognized
as gains or losses in the earnings of the periods in which they occur.



|Period Hedged                      | Reference | Type                | Volume bbl/d | Price US$/bbl     
|---------------------------------- | --------- | ------------------- | ------------ | ------------------
|                                   |           |                     |              |                   
|1 November 2016 – 30 June 2017     | ICE BRENT | Zero Premium Collar | 4,000        | 50.0 Put 57.0 Call
|1 November 2016 – 30 June 2017     | ICE BRENT | Zero Premium Collar | 2,000        | 50.0 Put 57.1 Call
|1 January 2017 – 30 September 2017 | ICE BRENT | Zero Premium Collar | 3,000        | 54.0 Put 61.1 Call
|1 January 2017 – 30 September 2017 | ICE BRENT | Zero Premium Collar | 1,000        | 54.0 Put 61.0 Call
|1 January 2017 – 30 September 2017 | ICE BRENT | Zero Premium Collar | 2,000        | 53.0 Put 60.1 Call



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



|                                                       | 2016  | 2015 | 2014
|------------------------------------------------------ | ----- | ---- | ----
|Realized gain on commodity risk management contracts   | (514) | -    | -   
|Unrealized loss on commodity risk management contracts | 3,068 | -    | -   
|Total                                                  | 2,554 | -    | -   



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 37 | Supplemental information on oil and gas activities
(unaudited)
| | -- | --------------------------------------------------------------



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



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



The following table presents those costs
capitalized as well as expensed that were incurred during each of the years ended as of 31 December 2016, 2015 and 2014. The acquisition
of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological
and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development
costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and
storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.



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

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



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Note



| | 37 | 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 2016, 2015 and 2014, 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 2016                       |           |           |           |          |          
|Proved properties                         |           |           |           |          |          
|Equipment, camps and other facilities (a) | 80,611    | 46,785    | 843       | 4,174    | 132,413  
|Mineral interest and wells (a)            | 380,037   | 230,100   | 4,849     | 77,255   | 692,241  
|Other uncompleted projects (a)            | 18,274    | 12,534    | 36        | 2,082    | 32,926   
|Unproved properties                       | 48,908    | 4,503     | 1,894     | 6,468    | 61,773   
|Gross capitalised costs                   | 527,830   | 293,922   | 7,622     | 89,979   | 919,353  
|Accumulated depreciation                  | (230,917) | (190,025) | (5,692)   | (29,803) | (456,437)
|Total net capitalised costs               | 296,913   | 103,897   | 1,930     | 60,176   | 462,916  

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



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

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



|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 (a)        | 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  

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



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Note



| | 37 | 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
2016, 2015 and 2014. 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 2016                       |          |          |           |          |         
|Revenue                                           | 36,723   | 126,228  | -         | 29,719   | 192,670 
|Production costs, excluding depreciation          |          |          |           |          |         
|Operating costs                                   | (20,674) | (29,326) | -         | (5,738)  | (55,738)
|Royalties                                         | (1,495)  | (7,281)  | -         | (2,721)  | (11,497)
|Total production costs                            | (22,169) | (36,607) | -         | (8,459)  | (67,235)
|Exploration expenses (a)                          | (21,060) | (11,690) | -         | (5,636)  | (38,386)
|Accretion expense (b)                             | (897)    | (459)    | -         | (1,198)  | (2,554) 
|Impairment loss reversal for non-financial assets | -        | 5,664    | -         | -        | 5,664   
|Depreciation, depletion and amortization          | (29,890) | (29,439) | -         | (12,785) | (72,114)
|Results of operations before income tax           | (37,293) | 53,697   | -         | 1,641    | 18,045  
|Income tax benefit (expense)                      | 5,594    | (21,479) | -         | (558)    | (16,443)
|Results of oil and gas operations                 | (31,699) | 32,218   | -         | 1,083    | 1,602   



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



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Note



| | 37 | 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 2014              |          |          |           |          |          
|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 (a)                 | (36,057) | (4,567)  | 123       | (2,164)  | (42,665) 
|Accretion expense (b)                    | (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  

| | (a) | Do not include Peru costs.
| | --- | --------------------------



| | (b) | Represents accretion of ARO liability.
| | --- | --------------------------------------



Table 4 - Reserve quantity information



Estimated oil and gas reserves



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



The 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 2016, 2015 and 2014 was based on the DeGolyer and MacNaughton
Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton prepared its proved oil and natural gas reserve
estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the SEC, and in accordance with the oil and gas
reserves disclosure provisions of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities
- Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities).



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 37 | Supplemental information on oil and gas activities
(unaudited – continued)
| | -- | --------------------------------------------------------------------------



Table 4 - Reserve quantity information (continued)



Reserves engineering is a subjective process
of estimation of hydrocarbon accumulation, which cannot be 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 2016, 2015 and 2014 are summarised as follows, expressed in thousands of barrels
(Mbbl) and millions of cubic feet (MMcf):



|                           | As
    of 31 December 2016    | As
    of 31 December 2015                  | As
    of 31 December 2014   
|-------------------------- | ----------------------------- | ------------------------------------------- | -----------------------------
|                           | Oil
    and condensate (Mbbl) | Natural
        gas
        
        (MMcf) | Oil
    and condensate (Mbbl)
|Net
    proved developed   |                               |                                             |                              
|Chile
    (a)              | 547.0                         | 6,610.0                                     | 498.0                        
|Colombia
    (b)           | 9,502.0                       | -                                           | 8,177.8                      
|Brazil
    (c)             | 72.0                          | 29,525.0                                    | 120.0                        
|Peru
    (d)               | 9,316.0                       | -                                           | -                            
|Total
    consolidated     | 19,437.0                      | 36,135.0                                    | 8,795.8                      
|                           |                               |                                             |                              
|Net
    proved undeveloped |                               |                                             |                              
|Chile
    (e)              | 6,052                         | 29,690.0                                    | 5,455.8                      
|Colombia
    (f)           | 27,838.0                      | -                                           | 22,245.5                     
|Brazil
    (c)             | -                             | -                                           | -                            
|Peru
    (d)               | 9,305.0                       | -                                           | -                            
|Total
    consolidated     | 43,195.0                      | 29,690.0                                    | 27,701.3                     
|                           |                               |                                             |                              
|Total
    proved reserves  | 62,632.0                      | 65,825.0                                    | 36,497.1                     



| | (a) | Fell
                                         Block accounts for 99% of the reserves (91% in 2015 and 92% in 2014) (LGI owns a 20%
                                         interest) and Flamenco Block accounts for 1% (9% in 2015 and 8% in 2014) (LGI owns 31.2%
                                         interest).
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | Llanos
                                         34 Block and Llanos 32 Block account for 99% and 1% (Llanos 34 Block and Cuerva Block
                                         account for 94% and 3% in 2015 and 79% and 17% in 2014) of the proved developed reserves,
                                         respectively (LGI owns a 20% interest).
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



| | (e) | Fell
                                         Block accounts for 99% of the reserves (100% in 2015 and 96% in 2014) (LGI owns a 20%
                                         interest), (Flamenco Block accounts for 1% in 2016 and 3% in 2014 and Isla Norte accounts
                                         for 1% 2014) (LGI owns 31.2% interest).
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (f) | Llanos
                                         34 Block accounts for 100% (Llanos 34 Block and Cuerva Block account for 95% and 4% in
                                         2015 and 91% and 7% in 2014) of the proved undeveloped reserves, respectively (LGI owns
                                         a 20% interest).
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



37       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 | Peru     | Total    
|---------------------------------------- | --------- | --------- | ------ | -------- | ---------
|Reserves
    as of 31 December 2013      | 5,375.0   | 9,426.6   | -      | -        | 14,801.6 
|Increase
    (decrease) attributable to: |           |           |        |          |          
|Revisions
    (a)                        | 124.9     | 2,489.7   | -      | -        | 2,614.6  
|Extensions
    and discoveries (b)       | 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 (c)       | 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 
|Increase
    (decrease) attributable to: |           |           |        |          |          
|Revisions
    (d)                        | 1,148.0   | 5,779.0   | (34.0) | -        | 6,893.0  
|Extensions
    and discoveries (e)       | -         | 6,311.0   | -      | -        | 6,311.0  
|Incorporation                            | -         | -         | -      | 18,621.0 | 18,621.0 
|Production                               | (502.8)   | (5,173.3) | (14.0) | -        | (5,690.1)
|Reserves
    as of 31 December 2016      | 6,599.0   | 37,340.0  | 72.0   | 18,621.0 | 62,632.0 

| | (a) | 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.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | 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.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | (d) | In
                                         Colombia, the revisions are mainly due to the performance and development of Tigana and
                                         Jacana fields and secondly to the performance of others Fields in Llanos 34 Block.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



|Millions
    of cubic feet               | Chile     | Brazil    | Total     
|---------------------------------------- | --------- | --------- | ----------
|Reserves
    as of 31 December 2013      | 32,159.0  | -         | 32,159.0  
|Increase
    (decrease) attributable to: |           |           |           
|Revisions
    (a)                        | 3,312.0   | -         | 3,312.0   
|Extensions
    and discoveries (b)       | 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
    (c)                        | (2,680.0) | 2,907.0   | 227.0     
|Extensions
    and discoveries (d)       | 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  



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 37 | Supplemental information on oil and gas activities
(unaudited – continued)
| | -- | --------------------------------------------------------------------------



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



|Millions
    of cubic feet               | Chile     | Brazil    | Total     
|---------------------------------------- | --------- | --------- | ----------
|Reserves
    as of 31 December 2015      | 36,515.0  | 36,158.0  | 72,673.0  
|Increase
    (decrease) attributable to: |           |           |           
|Revisions
    (e)                        | 5,078.0   | (319.0)   | 4,759.0   
|Production                               | (5,293.0) | (6,314.0) | (11,607.0)
|Reserves
    as of 31 December 2016      | 36,300.0  | 29,525.0  | 65,825.0  



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



| | (b) | Mainly
                                         due to the Ache Field discovery and the associated gas from Konawentru extension well.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------



| | (c) | In
                                         Brazil, the revisions are primary due to the production performance of Manati field.
| | --- | --------------------------------------------------------------------------------------------------------------------------------



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



| | (e) | The
                                         revisions are mainly due to Ache Field and Pampa Larga development in Fell Block and
                                         gas and associated gas performance/development in others Fields of Fell Block.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



The following table discloses estimated
future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural
gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification
(ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities),
such future net cash flows were estimated using the average first day- of-the-month price during the 12-month period for 2016,
2015 and 2014 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.



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Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 37 | 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    | Peru      | Total    
|------------------------------------------------------------ | --------- | --------- | --------- | --------- | ---------
|At
    31 December 2016                                      |           |           |           |           |          
|Future
    cash inflows                                      | 394,993   | 873,771   | 200,713   | 941,463   | 2,410,940
|Future
    production costs                                  | (186,700) | (229,593) | (74,116)  | (497,187) | (987,596)
|Future
    development costs                                 | (149,785) | (69,996)  | (16,352)  | (234,328) | (470,461)
|Future
    income taxes                                      | (8,344)   | (191,096) | (21,041)  | (69,698)  | (290,179)
|Undiscounted
    future net cash flows                       | 50,164    | 383,086   | 89,204    | 140,250   | 662,704  
|10%
    annual discount                                      | (14,709)  | (113,584) | (15,688)  | (109,321) | (253,302)
|Standardized
    measure of discounted future net cash flows | 35,455    | 269,502   | 73,516    | 30,929    | 409,402  
|At
    31 December 2015                                      |           |           |           |           |          
|Future
    cash inflows                                      | 403,199   | 1,032,339 | 221,206   | -         | 1,656,744
|Future
    production costs                                  | (186,933) | (309,394) | (99,832)  | -         | (596,159)
|Future
    development costs                                 | (112,312) | (99,305)  | (16,360)  | -         | (227,977)
|Future
    income taxes                                      | (17,904)  | (195,957) | (16,837)  | -         | (230,698)
|Undiscounted
    future net cash flows                       | 86,050    | 427,683   | 88,177    | -         | 601,910  
|10%
    annual discount                                      | (17,895)  | (127,586) | (15,861)  | -         | (161,342)
|Standardized
    measure of discounted future net cash flows | 68,155    | 300,097   | 72,316    | -         | 440,568  
|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  



F-75


Table of Contents  GEOPARK LIMITED  31 DECEMBER 2016


Note



| | 37 | Supplemental information on oil and gas activities
(unaudited – continued)
| | -- | --------------------------------------------------------------------------



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



|Amounts
    in US$ '000                             | Chile     | Colombia  | Brazil   | Peru   | 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  
|Sales
    of hydrocarbon , net of production costs  | (15,127)  | (91,163)  | (20,945) | -      | (127,235)
|Net
    changes in sales price and production costs | (16,854)  | (171,131) | 16,366   | -      | (171,619)
|Changes
    in estimated future development costs   | (49,763)  | 14,941    | 542      | -      | (34,280) 
|Extensions
    and discoveries less related costs   | -         | 76,641    | -        | -      | 76,641   
|Development
    costs incurred                      | 9,417     | 17,302    | 2,214    | -      | 28,933   
|Revisions
    of previous quantity estimates        | 22,765    | 70,180    | (1,872)  | -      | 91,073   
|Incorporation                                       | -         | -         | -        | 30,929 | 30,929   
|Net
    changes in income taxes                     | 8,256     | 3,030     | (4,020)  | -      | 7,266    
|Accretion
    of discount                           | 8,606     | 49,605    | 8,915    | -      | 67,126   
|Present
    value at 31 December 2016               | 35,455    | 269,502   | 73,516   | 30,929 | 409,402  











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