ANNUAL REPORT 2023
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Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 20-F(Mark One)☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIESEXCHANGE ACT OF 1934OR☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934For the fiscal year ended December 31, 2023OR☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934For the transition period from ______________________ to ___________________________OR☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934Date of event requiring this shell company reportCommission file number: 001-36298GEOPARK LIMITED(Exact name of Registrant as specified in its charter)Bermuda(Jurisdiction of incorporation)Calle 94 N° 11-30, 8o floorBogotá, Colombia(Address of principal executive offices)Mónica Jiménez GonzálezChief Strategy, Sustainability and Legal OfficerGeoPark LimitedCalle 94 N° 11-30, 8o floorBogotá, ColombiaPhone: +57 1 743 2337(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)Copies to:Maurice Blanco, Esq.Davis Polk & Wardwell LLP450 Lexington AvenueNew York, NY 10017Phone: (212 ) 450 4000Fax: (212) 701 5800Securities registered or to be registered pursuant to Section 12(b) of the Act:Title of each classTrading SymbolsName of each exchange on which registeredCommon shares, par value US$0.001per shareGPRKNew York Stock ExchangeSecurities registered or to be registered pursuant to Section 12(g) of the Act:None Table of Contents
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
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: 55,327,520
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐ 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.
Yes ☐ 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.
Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be
submitted 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 such files).
Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an
emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in
Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐
Emerging growth company ☐
Non-accelerated filer ☐
Accelerated filer ☒
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark
if the registrant has elected not to use the extended transition period for complying with any new or revised financial
accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards
Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to
§240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this
filing:
US GAAP ☐
International Financial Reporting Standards
as issued by the International Accounting
Standards Board ☒
Other ☐
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.
☐ Item 17 ☐ 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).
Yes ☐ No ☒
Table of Contents
GEOPARK LIMITED
TABLE OF CONTENTS
Glossary of oil and natural gas terms
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and senior management
B. Advisers
C. Auditors
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A. Offer statistics
B. Method and expected timetable
ITEM 3. KEY INFORMATION
A. Reserved
B. Capitalization and indebtedness
C. Reasons for the offer and use of proceeds
D. Risk factors
ITEM 4. INFORMATION ON THE COMPANY
A. History and development of the company
B. Business Overview
C. Organizational structure
D. Property, plant and equipment
ITEM 4A. UNRESOLVED STAFF COMMENTS
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
A. Operating results
B. Liquidity and capital resources
C. Research and development, patents and licenses, etc.
D. Trend information
E. Critical accounting policies and estimates
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. Directors and executive officers
B. Compensation
C. Board practices
D. Employees
E. Share ownership
F. Disclosure of a registrant´s action to recover erroneously awarded compensation
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A. Major shareholders
B. Related party transactions
C.
Interests of Experts and Counsel
ITEM 8. FINANCIAL INFORMATION
A. Consolidated statements and other financial information
B. Significant changes
ITEM 9. THE OFFER AND LISTING
A. Offering and listing details
B. Plan of distribution
C. Markets
D. Selling shareholders
E. Dilution
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F. Expenses of the issue
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
B. Memorandum of association and bye-laws
Enforcement of Judgments
C. Material contracts
D. Exchange controls
E. Taxation
F. Dividends and paying agents
G. Statement by experts
H. Documents on display
I. Subsidiary information
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
A. Debt securities
B. Warrants and rights
C. Other securities
D. American Depositary Shares
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
A. Defaults
B. Arrears and delinquencies
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF
PROCEEDS
ITEM 15. CONTROLS AND PROCEDURES
A. Disclosure Controls and Procedures
B. Management’s Annual Report on Internal Control over Financial Reporting
C. Attestation Report of the Registered Public Accounting Firm
D. Changes in Internal Control over Financial Reporting
ITEM 16. RESERVED
ITEM 16A. Audit committee financial expert
ITEM 16B. Code of Conduct
ITEM 16C. Principal Accountant Fees and Services
ITEM 16D. Exemptions from the listing standards for audit committees
ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers.
ITEM 16F. Change in registrant’s certifying accountant
ITEM 16G. Corporate governance
ITEM 16H. Mine safety disclosure
ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
ITEM 16J. Insider trading policies
ITEM 16K. Cybersecurity
PART III
ITEM 17. Financial statements
ITEM 18. Financial statements
ITEM 19. Exhibits
Index to Consolidated Financial Statements
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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.
“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.
“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.
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“economically producible” means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the
costs of the operation.
“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.
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“mmbtu” means one million British thermal units.
“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.
“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).
“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
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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.
“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 recovery, 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.
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Certain definitions
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
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, an exempted company incorporated under the laws of Bermuda, together with its consolidated subsidiaries;
● “Amerisur” are to Amerisur Resources Limited and its subsidiaries;
● “GeoPark Brazil” are to GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.;
● “YPF” are to YPF S.A.;
● “ONGC” are to ONGC Videsh Limited, international petroleum company of India;
● “Petroamazonas” are to Petroamazonas Ecuador S.A.;
● “Petroecuador” are to Empresa Pública de hidrocarburos del Ecuador;
● “MSCI” are to Morgan Stanley Capital International;
● “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate principal amount of 6.50% senior notes
due 2024;
● “Notes due 2027” are to our 2020 issuance of US$350.0 million aggregate principal amount of 5.50% senior notes
due 2027;
● “US$” 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$” are to the official currency of Brazil;
● “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo,
Gás Natural e Biocombustíveis);
● “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos);
● “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo);
● “RODA” are to the Oil Pipeline Network of the Amazonian District (Red de Oleoductos del Distrito Amazónico);
● “SOTE” are to the Ecuadorian Oil Pipeline System (Sistema de Oleoducto Transecuatoriano);
● “IOGP” are to the International Association of Oil and Gas Producers;
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● “IPIECA” are to the International Petroleum Industry Environmental Conservation Association;
● “IADC” are to the International Association of Drilling Contractors;
● “ARPEL” are to the Regional Association of Oil and Gas Companies, a non-profit association gathering oil, gas and
biofuels sector companies and institutions in Latin America and the Caribbean;
● “UTA” are to Unidad Tributaria Anual;
● “economic interest” are to an indirect participation interest in the net revenues from a given block based on bilateral
agreements with the concessionaires;
● “ESG” are to Environmental, Social and Governance; and
● “IFC” are to International Finance Corporation.
Financial statements
Our historical financial data presented does not include any results or other financial information of any acquisitions,
prior to their incorporation into our financial statements.
Our consolidated financial statements
This annual report includes our audited consolidated financial statements as of December 31, 2023 and 2022 and for each
of the years ended December 31, 2023, 2022 and 2021 (hereinafter “Consolidated Financial Statements”).
Our Consolidated Financial Statements are presented in US$ and have been prepared in accordance with International
Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).
Our Consolidated Financial Statements for the year ended December 31, 2023, have been audited by Ernst & Young
Audit S.A.S. (member of Ernst & Young Global Limited), an independent registered public accounting firm, as stated in their
reports 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 2023,” 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, to assess the performance of our
Company and the operating segments.
We define Adjusted EBITDA as profit (loss) for the period (determined as if IFRS 16 Leases has not been adopted),
before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of
unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts,
geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. 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 (loss) for the period in arriving at Adjusted EBITDA because
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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 (loss) 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 results 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 2023, 2022 and 2021.
Oil and gas reserves and production information
DeGolyer and MacNaughton 2023 Year-end Reserves Report
The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia,
Ecuador, Brazil and Chile is derived from estimates of the proved reserves as of December 31, 2023. The reserves estimates
described herein 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 Corp. and is included as an
exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in various blocks in
the Llanos and Putumayo Basins in Colombia, the Perico Block in the Oriente Basin in Ecuador, the BCAM-40 (Manati)
Block in the Camamu-Almada Basin in Brazil and the Fell Block in the Magallanes Basin in Chile.
Market share and other information
Market data, other statistical information, information regarding recent developments in the countries in which we operate
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.
In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and
natural gas terms”.
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.
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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 Colombian, Ecuadorian, and
Brazilian 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;
● climate change related risks;
● 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;
● social and political unrest in many countries in which we operate;
● fluctuations in inflation and exchange rates in Colombia, Ecuador and Brazil 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;
● pandemics, or the future outbreak of any highly infectious or contagious disease, including the COVID-19 pandemic;
● weather and other natural phenomena;
● armed conflicts, including the current armed conflicts in Ukraine and Israel;
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● 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 pending or future acquisitions and dispositions;
● our ability to retain key members of our senior management and key technical employees;
● competition from other similar oil and natural gas companies;
● 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;
● the adverse effect which a substantial or extended decline in oil and natural gas price may have on our business;
● material weaknesses in our internal control over financial reporting;
● the difficulty in integrating significant acquisitions or unexpected contingencies or changes in reserves estimates we
discover following the completion of such acquisitions; 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.
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ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and senior management
PART I
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. Reserved
B. Capitalization and indebtedness
Not applicable.
C. Reasons for the offer and use of proceeds
Not applicable.
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. The following risk factors have been grouped
as follows:
a) Risks relating to our business;
b) Risks relating to the countries in which we operate; and
c) Risks relating to our common shares.
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Summary of Key Risks
Our business is subject to numerous risks and uncertainties, discussed in more detail below. These risks include, among
others, the following key risks:
● A substantial or extended decline in oil and natural gas prices may materially adversely affect our business, financial
condition, or results of operations.
● Low oil prices may impact our operations and corporate strategy.
● 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.
● We derive a significant portion of our revenues from sales to a few key customers.
● Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.
● There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas.
● 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 business requires significant capital investment and maintenance expenses, which we may be unable to finance
on satisfactory terms or at all.
● 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.
● The development schedule of oil and natural gas projects is subject to cost overruns and delays.
● 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.
● Our estimated oil and gas reserves are based on assumptions that may prove inaccurate.
● 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.
● We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities,
including indigenous communities, where our reserves are located.
● Under the terms of some of our various E&P contracts, production sharing agreements and concession agreements,
we are obligated to drill wells, declare any discoveries, and file periodic reports 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.
● 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 E&P contracts, production sharing agreements and concession
agreements are subject to early termination in certain circumstances.
● We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not
in the future, hold all the working interests in some 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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● 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.
● 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.
● 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.
● 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 operations are subject to operating hazards, including extreme weather events, which could expose us to
potentially significant losses.
● 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.
● We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings,
which may result in material liabilities and costs.
● Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares
and limit our access to financing and insurance.
● 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.
● 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.
● Our business could be negatively impacted by cybersecurity threats and related disruptions.
● The COVID-19 pandemic adversely impacted our business, financial condition, and results of our operations, the
global economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or
pandemic disease may have makes it impossible for us to identify all potential risks related to the pandemic or
estimate the ultimate adverse impact that the pandemic may have on our business.
● We operate in an industry with climate related risks.
● We operate in areas of significant biodiversity value.
● We operate in areas that have historical and current ties to indigenous peoples.
● Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational
risk due to overlapping claims of rightful ownership.
● We have identified a material weakness in our internal control related to ineffective information technology general
controls which could, if not remediated, result in material misstatements in our financial statements.
● 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.
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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.
● Oil and natural gas companies in Colombia, Ecuador and Brazil operate and have a working and/or economic interest
over, yet do not own any of the oil and natural gas reserves in such countries.
● Oil and gas operators are subject to extensive regulation in the countries in which we operate.
● Colombia has experienced and continues to experience internal security issues that have had or could have a negative
effect on the Colombian economy.
● Our operations are subject to security and human rights risks.
● We expect that a limited number of financial institutions in the countries in which we operate, as well as some
institutions located in the United States, will hold all or most of our cash.
● 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.
● Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of
directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements,
prospects and other factors.
● We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our
other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries;
our subsidiaries may be limited by law and by contract in making distributions to us.
● 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.
● Provisions of the Notes due 2027 could discourage an acquisition of us by a third party.
● Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key
transactions, including a change of control.
● Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and
impact our stock price.
● 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.
● 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.
● We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors
and executive officers.
● The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in
Colombia.
● Legislation enacted in Bermuda as to Economic Substance may affect our operations.
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Risks relating to our business
A substantial or extended decline in oil and natural gas 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 and natural gas have been volatile and will likely continue to be
volatile in the future. International oil and natural gas 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 and natural gas;
● the conflicts in Ukraine and Israel and other armed conflicts;
● 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;
● 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, sulphur 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;
● the price and availability of alternative fuels, and possible regulations establishing costs for carbon emissions along
the value chain; and
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● future changes to our hedging policies.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price
movements. For example, during the last four years, Brent spot prices ranged from a low of US$19.3 per barrel to a high of
US$128.0 per barrel. Furthermore, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other.
After the oil crisis that resulted from the pandemic in 2020, the crude oil market normalized during early 2021 and shifted
into an undersupply condition towards the end of that year. This condition was mainly driven by continued demand recovery
while supply grew at a slower pace. OPEC and non-OPEC producers (sometimes referred to as OPEC+) paced output increase
and capital discipline elsewhere, especially within the US Shale producers, were the key factors for moderate supply growth.
In addition, natural gas prices spiked significantly during the last quarter of 2021, especially in Europe, pushing oil prices
higher as well. These factors brought Brent prices up to US$78 per barrel at the end of 2021.
The armed conflict between Russia and Ukraine during 2022, and the imposition of comprehensive sanctions against
Russia (including in relation to the Russian energy sector), as well as the announcement of prohibitions on Russian oil and gas
imports by certain members of the European Union, the United Kingdom, the United States, and other countries, led to
volatility in the price of global oil and gas. For example, Brent spot price rose to a maximum of US$128 per barrel in March
2022.
By the second half of 2022, sharply rising inflation led central banks to shift to a more restrictive policy stance, which
historically is indicative of a potential economic recession. An economic recession could influence crude oil demand and,
therefore, lead to a drop in crude oil prices, which dropped to US$86 per barrel by the end of 2022, 30% lower from the levels
observed in June 2022.
The year 2023 and the beginning of 2024 can be described as a consolidation period after a highly volatile 2022, where
the much-anticipated Chinese economic recovery did not meet expectations, while the resilience of the U.S. economy
positively surprised the macroeconomic environment. Despite the macro trend, countries like India and China took advantage
of lower oil prices and their access to discounted barrels from Russia and Iran, and drove the world’s oil demand to an all-
time-high of 103 million barrels a day, supporting Brent prices above $70/bbl. OPEC+ intervened the oil markets by cutting
supply, especially Saudi Arabia and Russia, who pledged a combined voluntary cut of 1.3 million barrels a day until year-end.
The group’s intervention resulted in the world’s oil inventories decreasing to a multi-year low and served as a catalyst for a
sustained rally that supported a rise in Brent prices to approximately $100/bbl. Oil markets have currently shifted their focus
to the evolution of the conflict between Israel and Hamas considering the potential impact on the crude oil supply from the
region if the conflict extends beyond the region’s borders.
For the year ended December 31, 2023, 97% 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.
For the year ended December 31, 2023, natural gas comprised 3% 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.
Continuing our hedging strategy, we entered into derivative financial instruments with the intent to partially mitigate our
exposure to oil price risk. These derivatives were placed with major financial institutions and commodity traders, under ISDA
Master Agreements and Credit Support Annexes.
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To the extent that we engage in oil price risk management activities to partially protect ourselves from declines in oil
price, we may be prevented from realizing the benefits of oil price increases above the levels of the zero-premium collars used
to manage oil price risk.
As market values of these derivatives fluctuate, we may post or receive variation cash collaterals with our counterparties.
In the event of a significant decrease in the market value of the derivatives, we may have to post cash collateral, if they exceed
our available credit lines. Even though cash collateral is returned to us upon reductions in the underlying Brent oil price,
having to post cash collaterals could affect our near-term liquidity needs. As of the date of this annual report, we have no cash
collateral posted related to our commodity risk management contracts. See Note 8 to our Consolidated Financial Statements
for details regarding Commodity Risk Management Contracts.
Low oil prices may impact 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 first half of 2020 (WTI and Brent, the main international oil price
markers, fell by more than 45% between December 2019 and March 2020), we immediately took decisive measures to ensure
our ability to both maximize ongoing projects and to preserve our cash, such as reducing our work program and made
adjustments to our operating and administrative costs, with continuous monitoring to adjust further if necessary. While oil
prices have rebounded since then, they may continue to be volatile and thus, we develop multiple scenarios for our capital
expenditure plan. See “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook”.
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.
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 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 we do not operate, 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
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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.
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, 2023, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Ecuador and Brazil
was 5.3 years. According to D&M estimates, if on January 1, 2024, we ceased all drilling and development activities,
including recompletions, refracs and workovers, our proved developed producing reserves base in Colombia, Ecuador and
Brazil would decline 26% 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.
We derive a significant portion of our revenues from sales to a few key customers.
In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other
producers. During 2023, the oil and gas production was sold to three clients which concentrate 96% of the Colombian
subsidiaries’ revenue (accounting for 89% of the consolidated revenue). Delivery points include wellhead and other locations
on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients
FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the
transport through the Ecuadorian pipeline system. We manage our counterparty credit risk associated to sales contracts by
performing periodic evaluations of our counterparties’ credit profile and, in certain contracts, including early payment
conditions to minimize the exposure.
In Ecuador, oil is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of
the sales are exported on a competitive basis to industry leading participants including traders and other producers. Sales of
crude oil in Ecuador accounted for 3% of our consolidated revenue.
In Brazil, the gas production from the Manati Field is sold to Petrobras, the Brazilian State-owned company, which is the
operator of the Manati Field (accounting for 2% of our consolidated revenue). 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”.
Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.
Although most of our revenues are denominated in US$, unfavorable fluctuations in foreign currency exchange rates for
certain of our expenses in Colombia, Ecuador and Brazil could have a material adverse effect on our results of operations. An
appreciation of local currencies can increase our costs and negatively impact our results from operations.
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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.
From time to time, we enter into derivative financial instruments in order to anticipate any currency fluctuation with
respect to income taxes to be paid during the first half of the following year. No currency risk management contracts were in
place as of December 31, 2023, and onwards. In January 2023, we entered into derivative financial instruments (zero-premium
collars) with local banks in Colombia, for an amount equivalent to US$38.0 million in order to anticipate any currency
fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023.
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 due to 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 estimate 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.
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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—2024 Strategy and Outlook.” We incurred capital expenditures of US$199.0 million and
US$168.8 million during the years ended December 31, 2023 and 2022, 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. For example, as a result of the oil price decline in 2020 we adjusted the capital
expenditures program for that year to US$65-75 million, approximately a 60% reduction from prior preliminary estimates
(approximately US$180-200 million).
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.
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, including as a result of financial
institutions having lower capital availability or potentially higher interest rates. 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 uncertain and involves a high degree of risk and hazards. 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, nationwide or regional social protests or blockades, unusual or unexpected geological formations, flooding,
earthquakes and extended interruptions due to weather conditions, explosions and other accidents.
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 because certain risks, such as public order related issues or natural disasters, are
not subject to insurance coverage because they are not under our control. 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
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completion of detailed cost estimates and final engineering, contracting and procurement costs. The 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;
● compliance with governmental laws and regulations, including environmental, health and safety laws and
regulations;
● adverse weather conditions;
● unanticipated increases in costs;
● natural disasters;
● epidemics or pandemics;
● accidents;
● transportation;
● unforeseen engineering and drilling complications;
● delays during prior consultation processes;
● delays attributable to the operator of the project;
● 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, during 2023:
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● the Indico 6 and Indico 7 wells, which were drilled in the CPO-5 Block in late 2022, were shut-in from January to
September 2023, following the ANH’s request that the operator suspend production until certain required surface
facilities were completed;
● the environmental licensing processes in Putumayo (Colombia) were affected between April and November 2023, by
the suspension of the public hearings due to lack of adequate security conditions, which affected the start of
operations in the PUT-8 Block and caused delays in the planned drilling campaign; and
● the drilling and completion costs for the Tigana Norte 50 and Tigui 74 wells in our Llanos 34 Block in Colombia
included delays and overruns of US$0.4 million and US$ 0.6 million, respectively, caused by local community
blockades.
Additionally, we may not be able to follow the development schedules we believe are optimal for blocks in which we are
not the operator, such as the CPO-5 Block, which could adversely affect our financial condition and results of operations.
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 greater financial and technical 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
where 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 allow.
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 successfully compete 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 estimate in Colombia, Ecuador, Brazil and Chile as of December 31, 2023, is based on the D&M
Reserves Report. Although classified as “proved reserves,” the reserves estimate set forth in the D&M Reserves Reports is
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.
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. Post estimate drilling, testing and production results may require revisions. 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
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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 estimate, 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, 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, we would be unable to
realize revenue from those wells until arrangements were made to deliver the production to the 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 us and third parties.
In Colombia, producers of crude oil have historically suffered from trucking transportation logistics issues and limited
pipeline and storage capacity, which cause delays in delivery and transfer of title of crude oil. To reduce this exposure, we and
our partner in the Llanos 34 Block have constructed a flowline to evacuate crude oil from the Jacana field, reducing
transportation costs, blockade risks and supporting our sustainable performance by reducing carbon emissions. Throughout
2023, we were impacted by repeated strikes carried out by communities requesting attention to their needs through the
obstruction of routes we typically use for the evacuation of crude oil through tanker trucks. While we have been able to
continue to evacuate our production through evacuation alternatives such as the Oleoducto del Casanare Pipeline (“ODCA”)
pipeline, without significantly affecting the production of our fields, if both transportation alternatives are simultaneously
affected and we are unable to evacuate our production, our access to the markets may be hindered and this could cause a
material adverse effect on our business, financial condition and results of operation.
In the case of our Putumayo Basin production, we have also reduced our exposure to trucking issues by implementing the
use of flowlines alongside trucking to gather our production at the Platanillo Block and transport it via the Oleoducto
Binacional Amerisur (“OBA”) pipeline that connects us to the Ecuador pipeline system.
Trucking transportation was part of our crude delivery strategy during 2023 and will continue to be part of our strategy in
the future. Although we were able to enable alternative delivery points and transport oil by trucks, avoiding any significant
negative impact in our production during this period, we cannot assure we would be able to do so in the future.
In Ecuador, our oil production is transported through the existing pipeline infrastructure. While the Ecuadorian pipeline
system is well-developed and has operated reliably in the past, we cannot guarantee this will be the case in the future. Also, as
production in Ecuador increases, available capacity may be limited. An inability to access transport capacity could adversely
affect our production levels or the transport costs associated with getting our production to the market.
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 gas production from the Manati Field is transported on Petrobras-operated pipelines.
If those pipelines became unavailable, our overall production levels in the Manati Field would be negatively impaired.
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We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities,
including indigenous communities, where our reserves are located.
Access to the sites where we operate requires agreements (including easements, rights-of-way and access authorizations),
primarily with the owners of the lands on which we intend to develop our operational projects. If we are unable to negotiate
easements 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 Colombia, although we have agreements with many landowners and ongoing negotiations with others, the economic
expectations of landowners have generally increased concomitant with direct negotiations, which may result in delayed access
to existing or future sites. Additionally, local communities and other stakeholders in the territory, such as workers'
associations, trade unions and unions for activities related to the industry, are leading demands to the operators, beyond what
is legally established, sometimes exerting pressures under de facto means or blockades to operational activities. Although oil
and gas companies are managing these situations and stakeholder expectations in the territory, it ultimately becomes necessary
to establish agreements for the viability of the operations, which on occasions translates into higher execution costs.
Additionally, there are demands for improvements of transport infrastructure and the addressing of unsatisfied basic needs that
have been historically ignored by the authorities and the fulfillment of such demands may be redirected towards the oil and
gas companies.
In Putumayo (Colombia), where we have operating sites, there is presence of illegal groups which may pressure farmers
to oppose the control and eradication of illicit crops, and instrumentalize the oil and gas industry with blockades, seeking to
draw the attention of the national government and prevent the eradication of these crops.
As part of its international commitments, the Colombian government may seek to enhance the participatory phases of
hydrocarbon projects, which could broaden the parameters of community participation and access to information and
ultimately affect project timelines. Furthermore, local communities’ expectations may increase because of several reforms the
government has announced. If the government reforms do not meet the communities’ expectations, the pressure to reform may
shift to the oil and gas industry.
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 fixing and improving public access roads,
compensate them for any damages related to use of such roads and, more generally, invest in infrastructure which is
commonly 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 blockades and conflicts with
landowners.
In addition, community and indigenous protests and blockades may arise near our operations, which could adversely
affect our business, financial condition or results of operations.
Other legal proceedings such as land restitution, a judicial process implemented because of the peace agreement in
Colombia, focus on returning illegally held land to its rightful owners, may delay access to future sites.
There can be no assurance that disputes with landowners and local communities or legal proceedings will not delay our
operations or that any agreements we reach with such landowners and local communities or legal proceedings 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.
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Under the terms of some of our various E&P contracts, production sharing agreements and concession agreements, we
are obligated to drill wells, declare any discoveries, and file periodic reports 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.
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 periods specified in our various special operation
contracts (E&P contracts, production sharing agreements 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 them. The costs to maintain or operate
the E&P contracts, production sharing agreements 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 2023, we transferred
commitments from certain blocks to others and asked for termination of certain E&P contracts. See “Item 4. Information on
the Company—B. Business Overview—Our operations—Operations in Colombia.”
Historically, a significant amount of our reserves or production have been derived from our operations in certain blocks,
including various blocks in the Llanos and Putumayo Basins in Colombia, the Espejo and Perico Blocks in the Oriente Basin
in Ecuador, the BCAM-40 Concession in the Camamu-Almada Basin in Brazil and the Fell Block in the Magallanes Basin in
Chile.
For the year ended December 31, 2023, the different blocks in the Llanos Basin contained 85.1% of our net proved
reserves and generated 84.2% of our production, the Platanillo Block in the Putumayo Basin contained 4.8% of our net proved
reserves and generated 5.8% of our production, the Espejo and Perico Blocks in the Oriente Basin contained 3.5% of our net
proved reserves and generated 2.5% of our production, the BCAM-40 Concession in the Camamu-Almada Basin contained
2.3% of our net proved reserves and generated 2.8% of our production and the Fell Block in the Magallanes Basin contained
4.4% of our net proved reserves and generated 4.7% of our total production. While our continuing expansion with new
exploratory blocks incorporated in our portfolio and the recent divestment of our operations in Chile 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 E&P contracts, production sharing agreements and concession agreements are
subject to early termination in certain circumstances.
Under certain E&P contracts, production sharing 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 E&P contracts, production sharing contracts and concession agreements or dilution or forfeiture of interests
held by us. As of December 31, 2023, the aggregate outstanding amount of this potential liability for guarantees was US$70.7
million, mainly related to capital commitments in the Llanos 34, Platanillo, Llanos 87, PUT-8, Llanos 86, and Llanos 104
Blocks in Colombia, the Espejo and Perico Blocks in Ecuador, and the Campanario Block in Chile. See “Item 4. Information
on the Company—B. Business Overview—Our operations” and Note 33.2 to our Consolidated Financial Statements.
Additionally, certain E&P contracts, production sharing 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 of these agreements contain provisions enabling exploration extensions.
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In Colombia, our E&P contracts are 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.” To avoid the breach of an E&P contract due to unfulfillment of our exploration
commitments, regulation gives us options such as the ability to transfer or credit those commitments to other E&P contracts,
subject to meeting certain regulatory conditions.
In Ecuador, our production sharing contracts may be subject to early termination in case of breach of the obligations
under the contract, non-performance of the exploratory commitments or unjustified suspension of the operations, lack of
remediation of environmental damages or unauthorized assignment of a working interest under the production sharing
contracts, among others, as specified under the laws of the contract. The declaration of an early termination is subject to prior
due process, which would allow us to remedy any hypothetical breach claimed against us, or to present our defense
allegations. A declaration of early termination will cause forfeiture of equipment and facilities and enforcement of monetary
guarantees.
In Brazil, concession agreements in the production phase 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 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.
Early termination or nonrenewal of any E&P contract, production sharing agreements or concession agreement could
have a material adverse effect on our business, financial situation, or results of operations.
We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in
the future, hold all the working interests in some 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.
We are not the operator or sole owner of all the blocks included in our portfolio. See “Item 4. Information on the
Company—B. Business Overview—Operations in Colombia”, “—Operations in Ecuador”, “—Operations in Brazil” and “—
Operations in Argentina”. Therefore, certain decisions are not under our sole discretion and need to be agreed to with our
partners. Accordingly, our decision-making capabilities may be limited to the extent our partner operators or owners have any
limitations with respect to any proposed action or plan.
In addition, the terms of the joint operations 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, Ecuador and Brazil. Our dependence on our partners could
prevent us from achieving our target returns for those discoveries or prospects.
Moreover, as we are not the sole owner or operator of all 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
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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;
● 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.
For instance, we are not the operator of the CPO-5 Block, and do not control the execution of the development schedule.
Any delays in the execution schedule of the CPO-5 Block could have a material adverse effect in our financial condition and
results of operation. For example, the Indico 6 and Indico 7 wells, which were drilled in the CPO-5 Block in late 2022, were
shut-in from January to September 2023, following the ANH’s request that the operator suspend production until certain
required surface facilities were completed.
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;
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● 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.
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 and return value to shareholders. We may also finance future transactions through debt financing, oil
prepayment agreements, 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.
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, 2023, 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 and taxation.
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, 2023, 73% 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.
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.
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. For example, during 2023, we incurred in higher energy
costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability
of hydroelectric power.
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
key management 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.
We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings,
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
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actions. For instance, non-governmental organizations 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, 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.
The Regional Agreement on Access to Information, Public Participation and Justice in Environmental Matters in Latin
America and the Caribbean, also known as the Escazú Agreement, is an international human rights treaty that was signed by
all the countries in which we operate and has been ratified by all, except for Brazil, where pressure has been growing for the
government to ratify. We expect the countries where the agreement has been ratified will proceed to regulate the agreement
and such regulations may include additional processes on participation and information, which could directly affect our
operations as it could require additional processes that take time. Nonetheless, current Colombian processes require minor
adjustments to comply with Escazú Agreement with regards to private involvement and we have extensive experience on such
processes. The agreement also increases the protection of human rights and environmental activists, protection which we
believe is much required in the countries where we operate and is aligned with our commitment to human rights.
We are subject to national and regional environmental regulations and specific environmental requirements as part of the
licenses and permits that we must obtain for our operations. We have mechanisms to assure the fulfillment of all those legal
obligations such as a permanent external audit, a dedicated environmental team, and our environmental management system.
The evidence of the fulfillment of such obligations is consolidated in the yearly environmental reports that are issued to the
environmental authorities and correspond to public information. In addition, we are subject to yearly visits by the
environmental national authority. Although we fulfill the requirements, sometimes we have not been and may not be at all
times in complete compliance with some of them due to causes not attributable to us. This is the case of the offset obligations
we have to implement to compensate the residual impacts that cannot be avoided, minimized or restored, in which we have to
consider a concertation process with different stakeholders that could take more time than what the regulation provides.
Nevertheless, we report the progress and we define action plans to demonstrate our diligence and reduce the possibility of
sanctions, penalties or fines related to a delay in our fulfillment of the obligations, which could have a material adverse effect
on our business, financial condition or results of operations.
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. Although we screen our contractors regarding their compliance on several issues,
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. During 2023, we
approved and adopted a Supplier Code of Conduct under which we define the minimum obligations and behaviors expected
from our contractors and suppliers, aiming to address the risk.
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 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.
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We have set a target to reduce operational Scope 1 and 2 GHG emissions by 35-40 percent by year-end 2025 and by 40-
60 percent by year-end 2030 from a 2020 baseline. We also have a long-term ambition to achieve net zero Scope 1 and 2 GHG
emissions from operations by 2050. Our ability to meet these targets is subject to numerous risks and uncertainties and actions
taken in implementing such targets and ambition may also expose us to certain additional and/or heightened financial and
operational risks, which is also dependent on how we grow. Furthermore, the long-term ambition of reaching net zero
emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including
the commercial application of future technologies that may be necessary to achieve this long-term ambition. A reduction in
GHG emissions relies on, among other things, the ability to develop, access and implement commercially viable and scalable
emission reduction strategies and related technology and products, as well as our ability to participate in projects that capture
carbon and reduce our footprint. If we are unable to implement these strategies and technologies as planned without negatively
impacting expected operations or cost structures, or such strategies or technologies do not perform as expected, we may be
unable to meet the 2025 and 2030 GHG reduction targets or the 2050 net zero emissions ambition on the current timelines, or
at all.
In addition, achieving the 2025 and 2030 GHG reduction targets and the 2050 net zero ambition relies on a stable
regulatory framework and will require capital expenditures and resources, with the potential that actual costs may differ from
the original estimates and the differences may be material. Furthermore, the cost of investing in emissions-reduction
technologies, and the resultant change in the deployment of resources and focus, could have a negative impact on future
operating and financial results, or could result in a differentiator for the company and 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.”
Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and
limit our access to financing and insurance.
A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil
and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation
and indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry.
As a result of these concerns, some institutional, retail, and public investors have announced that they no longer are
willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition,
certain institutional investors are requesting that issuers develop and implement more robust social, environmental and
governance policies and practices. Although we have in place strong and robust social, environmental and governance
practices, developing and implementing even broader policies and practices can involve significant costs and require a
significant time commitment from our Board, management and employees. Failing to implement the policies and practices as
requested by institutional investors may result in such investors reducing their investment in our Company or not investing in
our Company at all.
Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, our
Company, may result in limiting our access to capital and insurance, increasing the cost of capital and insurance, and
decreasing the price and liquidity of our common shares even if our operating results, underlying asset values or prospects
have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of our assets
which may result in an impairment charge.
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
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facilitate a higher flow of hydrocarbons into the wellbore. We may eventually contemplate, after obtaining due environmental
approvals, such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs. 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.
In Colombia, during the second half of 2022, the Council of State (the highest administrative court) issued a decision by
which it denied the claims that were seeking nullity of the regulation for “non-conventional hydrocarbons”. Therefore, the
regulation for unconventional oil and gas resources in Colombia is in force and with full effects. However, the government is
seeking to prohibit fracking techniques in Colombia and, during the second half of 2022, a bill of law to forbid fracking and
exploitation of unconventional hydrocarbons was filed in Congress. The bill of law is pending two debates in one of the
chambers of Congress (house of representatives) and it is highly probable that the project is approved and sanctioned as a law.
We currently are not aware of any proposals in Ecuador, Brazil or Chile 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, 2023, we had US$501.0 million outstanding amount of indebtedness on a consolidated basis,
consisting of our Notes due 2027.
Our indebtedness could:
● limit our capacity to satisfy our obligations with respect to our indebtedness, and any failure to comply with the
obligations 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, if any, 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.
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The indenture governing our Notes due 2027 includes covenants restricting dividend payments and other shareholder
distributions. For a description, see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital
Resources—Indebtedness.”
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. We have in the past been unable
to meet incurrence tests under the indenture governing our prior notes, which limited our ability to incur indebtedness. Failure
to comply with the restrictive covenants included in our Notes due 2027 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 cybersecurity threats and related disruptions.
We rely on information technology systems, including systems which are managed or provided by third-party providers,
to conduct our business and support our exploration, development, and production activities. We increasingly depend on
digital technologies, such as applications, a cloud environment, mobile platforms, computers, and telecommunications
systems. We collect, use, transmit, store, and otherwise process data using information technology systems, including systems
owned and maintained by us or our third-party providers. These data include confidential information and intellectual property
belonging to us or our customers or other business partners.
All information technology systems are subject to disruptions, outages, failures, and security breaches or incidents. A
breach or failure of our digital infrastructure, control systems, or cyber defenses, or those of our third-party providers, as a
result of negligence, intentional misconduct, or otherwise, could seriously disrupt our operations. We and our third-party
providers have experienced, and expect to continue to experience, cybersecurity attacks. Cybersecurity attacks may range
from employee or contractor error or misuse or unauthorized use of information technology systems or confidential
information, to individual attempts to gain unauthorized access to these information systems, to sophisticated cybersecurity
attacks, known as advanced persistent threats, any of which may target us directly or indirectly through our third-party
providers. Despite employee training and other measures to mitigate vulnerabilities, our employees have been and will
continue to be targeted by parties using fraudulent “spam”, “scam”, “phishing” and “spoofing” emails to misappropriate
information or to introduce viruses or other malware programs to our technology environment. Cybersecurity attacks are
increasing in number worldwide, and the attackers are increasingly organized and well-financed, or at times supported by state
actors. Our industry is subject to fast-evolving risks from cyber-threat actors, including states, criminals, terrorists, hacktivists,
and insiders. To the extent artificial intelligence capabilities improve and are increasingly adopted, they may be used to
identify vulnerabilities and craft increasingly sophisticated cybersecurity attacks. Vulnerabilities may be introduced from the
use of artificial intelligence by us, our customers, suppliers and other business partners and third-party providers.
We continuously devote significant resources to network security, data loss prevention, and other measures to protect our
systems and data from unauthorized access or misuse, and we may be required to expend greater resources in the future,
especially in the face of evolving and increasingly sophisticated cybersecurity threats and laws, regulations, and other actual
and asserted obligations to which we are or may become subject relating to privacy, data protection, and cybersecurity.
We may be unable to anticipate, prevent, or remediate future attacks, vulnerabilities, breaches, or incidents, and in some
instances, we may be unaware of vulnerabilities or cybersecurity breaches or incidents or their magnitude and effects,
particularly as attackers are becoming increasingly able to circumvent controls and remove forensic evidence. Cybersecurity
incidents may result in business disruption; delay in the development and delivery of our products; disruption of our
production processes, internal communications, interactions with customers and suppliers and processing and reporting
financial results; the theft or misappropriation of intellectual property; corruption, loss of, or inability to access (e.g., through
ransomware or denial of service) confidential information, trade secrets, proprietary information, personal information, and
other critical data (i.e., that of our company and our third-party providers and customers); reputational damage; private claims,
demands, and litigation or regulatory investigations, enforcement actions, or other
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proceedings related to contractual or regulatory privacy, cybersecurity, data protection, or other confidentiality obligations;
diminution in the value of our investment in research, development and engineering; and increased costs associated with the
implementation of cybersecurity measures to detect, deter, protect against, and recover from such incidents. Furthermore, the
need for rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of
sophisticated and coordinated means, presents a challenge we must face and any delay or failure to detect cyber incidents
could compound potential harms. This could result in significant and compounding losses due to the cost of remediation and
reputational consequences.
Our efforts to comply with, and changes to, laws, regulations, and contractual and other actual and asserted obligations
concerning privacy, cybersecurity, and data protection, including developing restrictions on cross-border data transfer and data
localization, could result in significant expense, and any actual or alleged failure to comply could result in inquiries,
investigations, and other proceedings against us by regulatory authorities or other third parties. Customers and third-party
providers
increasingly demand rigorous contractual provisions regarding privacy, cybersecurity, data protection,
confidentiality, and intellectual property, which may increase our overall compliance burden. With respect to certain potential
incidents, such as a cyber-attack or data breach, we are covered under a cybersecurity insurance. However, no assurances can
be made as to whether the insurance policy is sufficient in coverage or amount to cover all our potential liability.
The COVID-19 pandemic adversely impacted our business, financial condition, and results of our operations, the global
economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or pandemic
disease may have makes it impossible for us to identify all potential risks related to the pandemic or estimate the ultimate
adverse impact that the pandemic may have on our business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities,
businesses, and consumers, in response to the pandemic adversely impacted the global economy and created significant
volatility in the global financial markets. The COVID-19 pandemic resulted in significant volatility in the financial and
commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. In the event of a potential
resurgence of the COVID-19 pandemic, responsive measures may be implemented and further disruptions to the global
economy, demand, supply chain and others may occur.
As of the date of this annual report, we believe we have implemented adequate operational measures (such as remote
working procedures) to avoid or minimize major disruptions to our business. However, our operations rely on our workforce
being able to access our wells, structures and facilities located upon or used in connection with our oil and gas blocks. The
uncertainty of the impact that an endemic or pandemic disease may have makes it impossible for us to identify all potential
risks related to an endemic or pandemic disease and we cannot assure if, and to what extent, our business, financial condition,
cash flows or results of operations may be adversely impacted by any potential resurgence or outbreak of the COVID-19
pandemic, or any other regional or global outbreaks related to any other endemic or pandemic disease.
The COVID-19 pandemic and its unprecedented consequences amplified, and may continue to amplify, the other risks
identified in this annual report.
We operate in an industry with climate related risks.
The oil and gas industry, where we operate, is particularly exposed to risks arising from climate change and the energy
transition, such as volatility of products prices, possible new regulations that may restrict our operations, and an increase in
extreme weather events that affect our ability to operate.
Moreover, our main assets are in countries like Colombia and Ecuador, where the risks related to the occurrence of natural
hazards such as floods, landslides and droughts are high and expected to increase in the following years. For example, during
2023, we incurred in higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia
as a result of decreased availability of hydroelectric power.
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We operate in areas of significant biodiversity value.
Some of our operations are in or adjacent to areas with significant biodiversity value, some of which are being considered
for designation as conservation or protected areas. This could require modifications to our plans in order to adapt our projects
to the environmental conditions and the allowed use of the land, which may increase viability costs and delay our timelines.
We carry out detailed due diligence processes to mitigate the potential impacts derived from this risk, but there are factors
outside of our control, such as local politics and political decisions.
We operate in areas that have historical and current ties to indigenous peoples.
We operate in highly culturally diverse areas, which brings us and our operations in close contact with different
indigenous groups. This means we may need to carry out prior consultation processes aligned with local regulations. Such
processes may cause delays in planned activities, thereby affecting our operations and may lead to claims from indigenous
peoples, including those who have not been certified by the competent authorities, claims of alleged violations of human
rights and may encourage requests for expansion of territories and precautionary measures to protect the rights of indigenous
peoples, among others.
During 2022 and 2023, as part of our exploration projects and based on certifications of the origin of prior consultation
issued by the directorate of the national authority for prior consultation of the Ministry of the Interior, we have made
advancements in the development of consultation processes in the department of Meta with the Resguardo, Turpial and La
Victoria communities for the Golondrina development area project in the Llanos 86 and Llanos 104 Blocks. The agreements
that resulted from the prior consultation process were documented and protocolized in August 2023. The prior consultation
processes for the seismic acquisition program in those blocks is currently in the follow-up stage. In 2023, we made progress
towards closing the prior consultation processes for the 2D and 3D seismic acquisition program in the Coati Block with
indigenous communities from Santa Rosa del Guamuez, Yarinal, San Marcelino, Campo Alegre del Afilador and Parcialidad
Nueva Palestina in the department of Putumayo.
Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk
due to overlapping claims of rightful ownership.
Costs related to mitigation and offset measures to protect the habitat could be greater than currently anticipated due to the
sensitivity of the biodiversity and the legal requirements imposed by the environmental authority. Nevertheless, we design our
exploration and production projects while considering the conditions of the environment and avoiding any disruption to
natural forest coverage and ecosystems connectivity.
Several of the oil and gas development and exploration blocks in the Putumayo area in Colombia overlap with indigenous
territories that are either formalized or are being considered for formal titling of tribal lands under the Colombian land
restitution law.
We have identified a material weakness in our internal control related to ineffective information technology general
controls which could, if not remediated, result in material misstatements in our financial statements.
In connection with the preparation of our financial statements as of December 31, 2023, we concluded there is a material
weakness in our internal control related to ineffective information technology general controls (ITGCs). Notwithstanding, we
have also concluded that the material weakness did not result in any identified misstatements to the consolidated financial
statements, and there were no changes to previously released financial results. To remediate our material weakness, we have
been implementing and will continue to implement measures designed to ensure that control deficiencies contributing to the
material weakness are remediated, such that these controls are designed, implemented, and operating effectively. If our
remedial measures are insufficient to address the material weakness, or if additional material weaknesses or significant
deficiencies in our internal control over financial reporting are discovered or occur in the future, our financial statements may
contain material misstatements and we could be required to restate our financial results.
For further details on controls and remedial actions, see "Item 15. Controls and Procedures."
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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.
The Economic Commission for Latin America and the Caribbean (ECLAC) has forecasted a regional growth of 1.9% in
2024, after a 2.2% growth in 2023, indicating that the region would stay on a path of low growth, which means job creation
would decelerate and informality and gender gaps would persist, among other effects. These projections reflect, in part, low
dynamism in economic growth and global trade, which translates into a limited impetus from the global economy. Although
inflation has declined, the interest rates of the main developed economies have not, which means that financing costs have
remained at high levels throughout the year, and they are expected to stay that way in coming years. Furthermore, this low
growth is also attributable to the limited domestic space for fiscal and monetary policy faced by the region’s countries. In this
regard, it is emphasized that while public debt levels have declined, they remain high, and this, coupled with the increase in
financing costs, restricts fiscal space. In the monetary arena, inflation continues to decline in the region, but monetary policy
still has a restrictive bias, due to the effects that rate cuts could have on capital flows and the exchange rate, given that high
interest rates are still in effect in developed countries.
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;
● the possibility that a deterioration in Colombia’s, Ecuador’s and Brazil’s relations with multilateral credit institutions,
such as the International Monetary Fund, 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 and other illegal armed group
activities, social unrest, local economic conditions, political disruption, civil disturbance, community protests or
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blockades, expropriation, 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 where we operate have experienced, and may continue to experience, political instability, and losses
caused by these disruptions may not be covered by insurance. During 2022, Colombia and Ecuador experienced social and
political turmoil, including riots, nationwide protests, strikes and street demonstrations against their governments which led to
acts of violence and social and political tensions. Future protests could adversely and materially affect the Colombian and
Ecuadorian economies and our businesses in those countries. 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 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 2022, the Colombian government enacted a tax reform that materially affected the
oil producing companies. See Note 16 to our Consolidated Financial Statements.
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, 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.
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, Petroecuador and Petrobras. For instance, 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 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, Ecuador and Brazil operate and have a working and/or economic interest
over, yet do not own any of the oil and natural gas reserves in such countries.
Under Colombian, Ecuadorian and Brazilian 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 Colombian, Ecuadorian and Brazilian 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,
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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
in changes to policies with respect to foreign development and ownership of oil and gas, 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, Ecuadorian and Brazilian 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, export and import restrictions, 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—Colombia” and see Note 33.1 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 from the ANP, ranging from R$5 thousand 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.”
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.
Despite the demobilization and disarmament that occurred because of the 2016 peace agreement, factors of instability
persist in the territory, such as the presence of the Revolutionary Armed Forces of Colombia (FARC), the National Liberation
Army (ELN) dissident forces and other illegal armed groups that seek to control drug trafficking and other illegal activities.
The current government’s intention to solidify peace agreements with all criminal elements may cause an escalation of violent
incidents, damage to infrastructure and social mobilizations that may have adverse effects on the country’s economy.
The ELN has targeted crude oil pipelines in Colombia, including the Caño Limón-Coveñas pipeline, and other related
infrastructure, disrupting the activities of certain oil and natural gas companies and resulting in unscheduled shutdowns 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.
The FARC has also historically attacked oil and gas infrastructure, bombing pipelines or attacking transport carrying oil
and forcing drivers to spill it in Putumayo and our area of operations. For instance, in 2015, the content of 5 trucks of
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Amerisur were spilled close to Puerto Asis, Putumayo. In 2023, the environmental licensing processes in Putumayo were
affected as a result of the suspension of public hearings due to lack of adequate security conditions.
Our operations are subject to security and human rights risks.
Our operations can be affected by security related issues that may cause a halt or delay in production and exploration. The
nature and magnitude of the risk may differ according to the area where operations are carried out. For example, our
operations in Casanare and Meta may be affected by civil disturbances, including blockades. In Putumayo, the primary risk is
the presence of illegal armed groups which control drug production and trafficking, and this situation can increase the
perception of security risks, though the exact level of security risk depends on, among other factors, the location of the blocks
and the time of crop production. Consequently, we develop security risk assessments on a yearly basis and constantly monitor
specific security related issues. Moreover, since June 2022, we have strengthened our human rights and security risk
management processes with our security contractors. As of December 2023, all our security contractors underwent training in
security, human rights, and the voluntary principles (as determined by the United Nations Voluntary Principles on Security and
Human Rights initiative).
While we remain committed to strengthening our security processes and protocols, there is no guarantee that incidents of
such nature will not occur in the future.
We have also identified potential risks to our operations, neighboring communities, employees, and contractors and
service providers, due to the presence of land mines around several of our blocks in Putumayo. The land mines around this
area were primarily used by FARC to attack public security forces, but other illegal armed groups in the area, including FARC
dissidents, have also been known to place land mines to attack public security forces or use them against their enemies in the
fight for drug trafficking and production.
In addition, our operations may be impacted by our adherence to national laws as well as all international human rights
treaties ratified by the countries where we operate. As part of our commitment to respect human rights and engage in an open,
respectful, and transparent manner with all our stakeholders, we always strive to resolve all issues with government
authorities, especially following their lead with respect to guaranteeing human rights, through discussion and communication,
which may result in delays to the advancement of our projects.
We expect that a limited number of financial institutions in the countries in which we operate, as well as some
institutions located in the United States, will hold all or most of our cash.
We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions
located in the United States, will hold all or most of our cash. Depending on our cash balance in any of our accounts at any
given point in time, our balances may not be covered by government-backed deposit insurance programs in the event of
default or failure of any bank with which we maintain a commercial relationship. The occurrence of any default or failure of
any of the banks in which we have deposits could have a material adverse effect on our business, financial condition, results of
operations and cash flows. For example, with regards to our accounts in the United States, while the U.S. Federal Deposit
Insurance Corporation provides deposit insurance of US$250,000 per depositor, per insured bank, the amounts that we have in
deposits in U.S. banks far exceed that insurance amount. Therefore, if the U.S. government does not impose measures to
protect depositors in the event a bank in which our funds are held fails, we may lose all or a substantial portion of our
deposits.
As of December 31, 2023, we maintained 95% of our cash and cash equivalents in banks ranked within investment grade
category.
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Risks relating 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 (the “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;
● 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;
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● 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; or
● the release or expiration of transfer restrictions on our outstanding 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 will depend on many factors, such as our results of operations, financial condition, cash requirements,
prospects and other factors.
We are committed to return value to our shareholders. From 2018 to 2023, we distributed US$156.4 million to
shareholders through share buybacks and US$68.5 million in cash dividends. However, our availability to continue making
distributions to shareholders in the future will depend on many factors, such as our results of operations, financial condition,
cash requirements, prospects and other factors. For example, from April to November 2020, we temporarily suspended our
quarterly cash dividends and share buybacks due to the sharp decline in oil prices as a result of the COVID-19 pandemic.
Furthermore, we are 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 (the “Companies Act”), we may
not declare or pay a dividend or make a distribution out of contributed surplus, if there are reasonable grounds for believing
that (i) we are, or would after the payment be, unable to pay our liabilities as they become due; or (ii) that the realizable value
of our assets would thereby be less than our liabilities. We are also subject to contractual restrictions under certain of our
indebtedness. “Contributed surplus” is defined for purposes of section 54 of the Companies Act to include the proceeds arising
from donated shares, credits resulting from the redemption or conversion of shares at less than the amount set up as nominal
capital and donations of cash and other assets to the company.
We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our
other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our
subsidiaries may be limited by law and by contract in making distributions to us.
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 revenue and cash flow is distributions from our subsidiaries. Thus, our ability to service
our debt, finance acquisitions and pay dividends to our stockholders in the future is dependent on the ability of our
subsidiaries to generate sufficient net income and cash flows to make upstream cash distributions to us. 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 will also be subject to, among other things, restrictions that are contained in our
subsidiaries’ financing and joint operations agreements, 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 ability to grow, pursue business opportunities or
make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially
limited.
We may not be able to fully control the operations and the assets of our joint operations and we may not be able to make
major decisions or take timely actions with respect to our joint operations unless our joint operation partners agree. We may, in
the future, enter into joint operations agreements imposing additional restrictions on our ability to pay dividends.
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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 55,327,520 common shares were
outstanding as of December 31, 2023. 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 2027 could discourage an acquisition of us by a third party.
Certain provisions of the Notes due 2027 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 change of control, holders of the
Notes due 2027 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.
Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key
transactions, including a change of control.
Certain members of our board of directors and our executive officers held 17.9% of our outstanding common shares as of
March 19, 2024, holding the shares either directly or through privately held funds. As a result, these shareholders, if acting
together, would be able to influence 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.
Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact
our stock price.
Shareholder activism has been increasing generally and in the energy industry specifically. Investors may attempt to effect
changes to our business or governance, such as with respect to climate change or otherwise, by means such as shareholder
proposals, public campaigns, proxy solicitations or other means. Such actions could adversely impact us by distracting the
Board and employees from core business operations, increasing advisory fees and related costs, interfering with our ability to
successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of the
business.
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 (the “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
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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 are 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.
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 permission of the Bermuda Monetary Authority is required, under the provisions of the Exchange Control Act 1972
and related regulations, for all issuances and transfers of shares (which includes our common shares) of Bermuda companies
to or from a non-resident of Bermuda for exchange control purposes, other than in cases where the Bermuda Monetary
Authority has granted a general permission. The Bermuda Monetary Authority, in its notice to the public dated June 1, 2005,
has granted a general permission for the issue and subsequent transfer of any securities of a Bermuda company from and/or to
a non-resident of Bermuda for exchange control purposes for so long as any “Equity Securities” of the company (which would
include our common shares) are listed on an “Appointed Stock Exchange” (which would include the New York Stock
Exchange). In granting the general permission the Bermuda Monetary Authority accepts no responsibility for our financial
soundness or the correctness of any of the statements made or opinions expressed in this annual report. Any changes in the
permission granted by the Bermuda Monetary Authority and related regulations could result in a delay or denial of any
transfer of shares an investor might seek.
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 our assets are substantially located in
Colombia, Ecuador and Brazil. In addition, several 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. However, the courts of Bermuda would recognize any final and
conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of
multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement
based thereon provided that (i) 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, (ii) such court
did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the
judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence
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relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due
compliance with the correct procedures under the laws of Bermuda.
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 Colombia.
In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax established in
article 90-3 of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad
are taxed in Colombia when such transaction represents a transfer of assets located in Colombia (“Colombian Assets”).
Although certain conditions and exemptions apply, corporate reorganizations shall monitor this new regulation. As we
indirectly own Colombian 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 realized in
connection with such sales. For a description of the indirect transfer rules and the conditions of their application see “Item 10.
Additional Information—E. Taxation—Colombian tax on transfers of shares.”
Legislation enacted in Bermuda as to Economic Substance may affect our operations.
Pursuant to the Economic Substance Act 2018 (as amended) of Bermuda (the “ES Act”) that came into force on January
1, 2019, a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda
(“non-resident entity”) that carries on as a business any one or more of the “relevant activities” referred to in the ES Act must
comply with economic substance requirements. The ES Act may require in-scope Bermuda entities which are engaged in such
“relevant activities” to be directed and managed in Bermuda, have an adequate of qualified employees in Bermuda, incur an
adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-
generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance,
fund management, financing, leasing, headquarters, shipping, distribution and service center, intellectual property and holding
entities.
The ES Act could affect how we operate our business, which could adversely affect our business, financial condition and
results of operations. Although it is presently anticipated that the ES Act will have little material impact on us or our
operations, as the legislation is new and remains subject to further clarification and interpretation, it is not currently possible to
ascertain the precise impact of the ES Act on us.
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 in February 2006. We maintain a
registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our principal executive office
is located at Street 94 N° 11-30, 8th floor, Bogotá, Colombia, telephone number +57 1 743 2337.
The SEC maintains an internet website that contains reports, proxy, information statements and other information about
issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. The Company’s website
address is www.geo-park.com. The information contained on, or that can be accessed through, the Company’s website is not
part of, and is not incorporated into, this annual report.
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Our Company
We are a leading independent oil and natural gas exploration and production (“E&P”) company with operations in Latin
America. We currently operate in Colombia, Ecuador and Brazil. We are focused on Latin America because we believe it is
one of the richest and most underexplored hydrocarbon regions globally, with less presence of independent E&P companies
compared to the United States and Canada. In this region, much of the acreage has historically been controlled or owned by
state-owned companies. We believe that these factors create an opportunity for smaller, more agile companies like us to build
a long-term business.
We produced a net average of 36.6 mboepd during the year ended December 31, 2023, of which 90.0%, 2.5%, 2.8% and
4.7% were, respectively, in Colombia, Ecuador, Brazil and Chile, and of which 92.9% was oil. As of December 31, 2023,
according to the ANH, we were ranked as the second largest oil operator in Colombia, where we made the largest new oil field
discovery in the last 20 years.
A clear set of priorities and key values have driven our Company through a two-decade track record of growth,
sustainability performance and strong value delivery. Furthermore, our internal value system called Safety, Prosperity,
Employees, Environment and Community Development (“SPEED”), which has been part of the Company’s culture since its
inception, differentiates us from our peers, guides our decision-making process and is the basis for our value-generation
approach to all our stakeholders.
Meeting the energy needs of a growing population while contributing to the energy transition requires us to conduct best-
in-class oil and gas exploration and operation, to manage our assets in the most ethical and sustainable way, and to continue
creating long-term value for our shareholders and all our stakeholders.
Our business model
Our updated business model can be summarized in four simple words and one unifying idea: “We Make Assets Better”.
This principle is underscored by our track record of adapting to change, expanding our capabilities, and continuously
enhancing our asset portfolio. The model contains three comprises three interlocking elements:
● We deliver more energy by focusing on finding and producing energy as well as in effectively taking it to the market.
This means we have a strong focus on results and to that end, our business model requires the right people, the right
assets, and the right execution.
● We invest with the goal of returning value to all our stakeholders. That means we follow a disciplined capital
allocation targeting the highest value projects, while responsibly taking on and managing risk.
● We create and share prosperity with everyone from our employees to governments and local communities. “Creating
Value and Giving Back” is a central tenet of our Company and bringing prosperity to people while looking after the
environment will always be one of our top priorities, all while maintaining the highest standards of ethics and
governance.
At the center of our company and our updated business model is our culture of agility, adaptability, and trust, and we have
a horizontal structure where all our employees have autonomy, ownership, and a key role to play. Our culture is our binding
force, and we need to protect and nurture it if we are to excel at the three interlocking elements described above.
History
We were founded in 2002. We are a leading independent oil and natural gas exploration and production (“E&P”),
company with operations in Latin America. During 2023, we had operations in Colombia, Ecuador, Brazil and Chile, and as of
January 2024, we have divested the entirety of our business in Chile as further described below.
Our History can be summarized by our growth in each country and our performance in the capital markets:
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Colombia
In the first quarter of 2012, we entered into Colombia by acquiring three privately held E&P companies, that were later
merged into GeoPark Colombia S.A.S. These acquisitions provided us with an attractive platform of reserves and resources in
Colombia, including a 45% operated working interest in the Llanos 34 Block.
During 2019, jointly with Ecopetrol/Hocol, we acquired five low-cost, low-risk and high-potential exploration blocks in
the Llanos Basin, surrounding the Llanos 34 Block, and we also executed an agreement to assume a 50% non-operated
working interest in the Llanos 94 Block.
In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development, and
exploration blocks in Colombia, distributed as follows: twelve operated blocks in the Putumayo basin (including the
producing Platanillo Block) and one non-operated block in the Llanos basin (the producing CPO-5 Block), and a cross-border
oil pipeline from Colombia to Ecuador.
In 2023, we drilled and put into production five oil exploration wells in the Llanos 87 and Llanos 123 Blocks.
Ecuador
On May 22, 2019, we signed participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico
(GeoPark non-operated, 50% working interest) Blocks in Ecuador. In 2022, we recorded our first oil sales in Ecuador due to
the successful exploration campaign in the Perico Block, which continued during 2023, and we also acquired 60 sq km of 3D
seismic and drilled our first exploration well in the Espejo Block.
Brazil
Since 2013, we have participated in several Bid Rounds promoted by the Brazilian ANP. In 2014, we acquired a 10%
non-operated working interest in the BCAM-40 Concession, which included an interest in the Manati Gas Field operated by
Petrobras.
Chile
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. Then, in 2011, ENAP awarded us operating
working interests in each of the Isla Norte, Flamenco and Campanario Blocks. In December 2023, we entered into an
agreement to sell our Chilean subsidiaries which comprised the entirety of our business in the country. The divestment
transaction closed in January 2024 and, as part of the transaction, we have retained certain rights over unconventional
activities that would be carried out in the Fell Block over the current operating contract in the future.
Other Latin American countries
During our history as operators, we have also had operations in Argentina and Peru, and we have participated in bid
rounds in Mexico. As of the date of this annual report, we do not have operations in these countries.
Funding
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.
Between 2005 and 2023, we raised approximately US$200 million in equity offerings at the holding company level and
nearly US$1.5 billion through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities,
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.
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In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due
2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The
reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. The Notes due 2027 are fully and
unconditionally guaranteed by GeoPark Colombia, S.L.U. Final maturity will be January 17, 2027.
On June 17, 2022, we received requisite consents from holders of the Notes due 2027 for certain amendments to the
indenture governing the Notes due 2027. The amendments addressed the impact of adverse market conditions and related drop
in the price of crude oil during 2020 on our results, which in turn negatively impacted the restricted payments builder basket,
and increased and reset the general restricted payments basket in the indenture to provide us additional restricted payments
capacity, giving us additional financial flexibility. Consequently, on June 27, 2022, we paid a consent fee equal to $10.00 per
$1,000 to holders of the Notes due 2027 that delivered their consents for the abovementioned amendments to the indenture
governing the Notes due 2027.
From April 2021 to September 2022, we repurchased and cancelled our US$425.0 million aggregate principal amount of
6.5% senior secured notes due 2024 (the “Notes due 2024”). In April 2021, we executed a tender to purchase US$255.0
million of the Notes due 2024, funded with a combination of cash in hand and the abovementioned reopening of the Notes due
2027. From March to September 2022, we repurchased and cancelled the remaining amount of the Notes due 2024 for a
nominal amount of US$ 170.0 million.
Following the abovementioned transactions, we reduced our total indebtedness nominal amount by US$275.0 million by
using the cash generated from our operations and improved our financial profile by extending our debt maturities.
On August 3, 2023, we signed a senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco
Latinoamericano de Comercio Exterior S.A. which provides us with access to up to US$80 million, with an availability period
until November 3, 2024, and final maturity on August 3, 2025. As of the date of this annual report, we have not withdrawn any
amount under this credit facility.
B. Business Overview
We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring
strategic assets and businesses. We continually evaluate the potential acquisition of strategic assets that will allow us to
continue growing our business in line with our recent operating and financial successes. 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, Ecuador, Brazil, Chile and Argentina.
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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, 2023. For information on our working interests in each of these blocks, see “—Our assets” below.
(1)
(2)
In process of relinquishment. See “—Our operations—Operations in Colombia” and “—Our operations—Operations in
Argentina.”
In process of transferring our working interest in the block to the partner. See “—Our operations—Operations in
Colombia” and “—Our operations—Operations in Argentina.”
(3) Divested in January 2024. See “—Our operations—Operations in Chile.”
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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, 2023.
For the year ended December 31, 2023
Country
Colombia
Ecuador
Brazil
Chile(1)
Other
Total
Oil
(mmbbl)
59.3
2.3
0.0
1.1
—
62.8
Gas
(bcf)
1.1
—
8.9
10.8
—
20.8
Oil
equivalent
(mmboe)
59.5
2.3
1.5
2.9
—
66.2
100.0 %
1.9 %
37.9 %
% Oil
99.7 % 702,401
19,097
14,019
15,644
5,464
94.8 % 756,625
Revenues
(in thousands % of total
revenues
of US$)
(1) Divested in January 2024. See “—Our operations—Operations in Chile.”
The following table sets forth our average net production during the last five years, as measured by boepd.
Average net production (mboepd)
% oil
2023
36.6
93%
For the year ended December 31,
2021
2020
2022
38.6
91%
37.6
86%
40.2
87%
92.8 %
2.5 %
1.9 %
2.1 %
0.7 %
100.0 %
2019
40.0
86%
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, 2023.
Oil production
Total crude oil production (bopd)
Natural gas production
Total natural gas production (mcf/day)
Oil and natural gas production
Colombia Ecuador
Average daily production
For the year ended December 31, 2023
Chile(1)
Brazil
Total
32,795
926
16
221
33,958
573
—
6,065
8,993
15,631
Total oil and natural gas production (mboepd)
32,890
926
1,027
1,720
36,563
(1) Divested in January 2024. See “—Our operations—Operations in Chile.”
Our assets
We have a portfolio of assets that includes working and/or economic interests in 34 hydrocarbon blocks, 33 of which are
onshore blocks, including 10 in production as of December 31, 2023, and provides the ability to quickly optimize capital
allocation as market conditions change. Our assets give us access to more than 4.7 million gross exploratory and productive
acres.
According to the D&M Reserves Report, as of December 31, 2023, the blocks in Colombia, Ecuador, Brazil and Chile in
which we have a working interest had 66.2 mmboe of net proved reserves, with 89.9%, 3.5%, 2.3% and 4.4% of such net
proved reserves located in Colombia, Ecuador, Brazil and Chile, respectively.
We produced a net average of 36.6 mboepd during the year ended December 31, 2023, of which 90.0%, 2.5%, 2.8% and
4.7%, were in Colombia, Ecuador, Brazil and Chile, respectively, and of which 92.9% was oil.
Our strengths
We believe that we benefit from the following competitive strengths:
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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 in Latin America. 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, and to allocate resources effectively based on prevailing conditions. For further information on our organic
growth and acquisitions in each country, see “—A. History and Development of the Company—History” and “—Our
operations.”
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 several 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, as demonstrated by our expansions in Colombia.
Our geoscience team continues to identify new potential accumulations and expand our inventory of prospects and
drilling opportunities.
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 low-risk 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 Amerisur in 2020 to pursue a risk-balanced approach: one block had mainly
proven production and reserves to provide us with a steady cash flow base, and the remaining blocks had highly prospective
exploration licenses.
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.”
Platform and Funding
We are focused on continued growth utilizing a disciplined capital structure and a conservative financial philosophy. Due
to the volatile nature of commodity prices, expenditure discipline and a focus on disciplined capital structure are critical to our
business. Our multi-country platform and asset portfolio is managed through our capital allocation methodology, which also
allows us to quickly adapt and grow. Under this methodology, we rank all of the projects based on economic, technical,
environmental, social and corporate governance and strategic criteria, for the purpose of comparing projects. This also creates
opportunities for improvements in the projects that can, in turn, improve their ranking. Finally, once the production and
reserve growth targets are defined, we agree on the amount of capital to be invested and allocates that capital to the highest
value-adding projects. As an example, for the 2024 capital allocation process, over 307 projects were selected which comprise
our 2024 work program, under the base capital program. Additionally, given the inherent oil price volatility, we design our
work programs to be flexible, which means that they can be increased or decreased depending on the oil price scenario.
We have historically benefited from access to debt and equity capital markets and cash flows from operations, as well as
other funding sources, which have provided us with funds to finance our organic growth and the pursuit of potential new
opportunities. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the
Company—A. History and Development of the Company—Funding.”
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We generated US$300.9 million and US$467.5 million in cash from operations in the years ended December 31, 2023 and
2022, respectively, and had US$133.0 million and US$128.8 million of cash and cash equivalents as of December 31, 2023
and 2022, respectively.
As of December 31, 2023, we had US$501.0 million of total outstanding indebtedness which is scheduled to mature in
January 2027.
Strong cash flow
We benefit from a strong cash flow from operating activities. For the year ended December 31, 2023, cash flows from
operating activities were US$300.9 million. Our cash flows from operating activities plays a significant role in funding our
capital expenditures and shareholders return.
Maintain financial strength
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.
Our cash flow generation is complemented by our financial hedging program. Since October 2016, we have entered into
derivative financial instruments to partially manage our exposure to oil price risk. The purpose of our hedging strategy is to
establish minimum oil prices to secure a stable cash flow and the execution of our work program. For more information
regarding our financial hedging program please see Note 8 to our Consolidated Financial Statements.
We believe that by maintaining a disciplined capital structure and a conservative financial philosophy, including limiting
our debt incurrence to specified projects with repayment sources and our use of financial hedges, we are positioned to
maintain sufficient liquidity and remain flexible in volatile commodity price environments. Our financial flexibility also gives
us the ability to pursue new opportunities through future potential acquisitions.
Pursue strategic acquisitions in Latin America
We have historically benefited from, and intend to continue to grow through, strategic acquisitions in Latin America.
These acquisitions have provided us with additional attractive platforms in the region. Our Colombian acquisitions, for
example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become the
second largest operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30
million and have achieved 1P reserve PV-10 of US$823 million as of December 31, 2023. Our enhanced regional portfolio,
including investment-grade countries and strong partnerships, position us as a regional consolidator. We intend to continue to
grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. 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.
In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development and
exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and one non-operated block in the Llanos
Basin) and a cross-border oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“OBA”).
Maintain a high degree of operatorship to control production costs
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 within a diversified asset portfolio. We
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believe that this strategy has allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and
our talented technical, operating and management teams.
Long-term strategic partnerships and strong strategic relationships provide us with additional funding flexibility to
pursue further acquisitions
We benefit from a number of strong partnerships and relationships. In Colombia, we believe 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
benefits from the long-term relationship with Petrobras.
Maintain our commitment to environmental, safety, human rights and social responsibility
An important component of our business strategy is our corporate approach and commitment to our safety, environmental
and social responsibilities, which is embodied in decisions that are framed by our safety, environmental and social
responsibility internal policies and aligned with international standards. We see this as a fundamental element in securing
business initiatives for long-term growth. Our commitment to sustainable development has allowed us to generate positive
impacts in the territories in which we operate, with important contributions to the protection of biodiversity and the
environment, as well as to the wellbeing and reduction of multidimensional poverty in neighboring communities. We maintain
a social license to operate, based on the construction and maintenance of mutually beneficial relationships with local
communities, the return of value as allies for their social and economic development, the respect for their human rights and
the care and preservation of the environment. Detailed information can be found in our last SPEED Report which is available
at the Company’s website.
Our internal value system is called Safety, Prosperity, Employees, Environment and Community Development
(“SPEED”). Our SPEED program was developed in accordance with several international quality standards, including ISO
14001 (for environmental management issues), ISO 45001 (for occupational health and safety management issues), ISO
26000 (for social responsibility and workers’ rights issues), IFC guidelines for social and environmental performance, and
guidelines from associations including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.”
Our Environmental Management System (“EMS”) has been certified under the ISO 14001:2015 standard since 2017. The
scope of this certification includes all our activities, processes and products related to the exploration and exploitation of
hydrocarbons in Colombia, covering 97% of our operations.
In 2023, we obtained the latest re-certification of the ISO 14001:2015, which is valid until August 2026.
Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through
the NTC-ISO 14064-1 standard of the Colombian Institute of Technical Standards and Certification (ICONTEC). GeoPark
was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions
of greenhouse gases and help the countries where we operate meet their commitments under the Paris Agreement. During
2023, we continued to incorporate clean energy sources in our operations, and implemented energy efficiency measures, while
also managing our methane emissions in accordance with our decarbonization targets.
In January 2023, GeoPark was included for a second year in a row in the Bloomberg Gender-Equality Index, including
companies with best-in-class gender-related practices and policies. Additionally, we were recognized by the Portfolio Awards
in the Corporate Social Responsibility category for our commitment and positive impact on neighboring communities.
During 2023, we carried out our first ever double materiality assessment with the help of an expert consultant and
following GRI guidelines. Our new materiality matrix includes the following topics: climate action; ethics and transparency;
responsible management of water and biodiversity; health and safety in the workplace; community engagement; human talent
management, equality, inclusion and diversity; energetic transformation; air quality management; and supply chain
management.
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In 2023, we delivered our SPEED/sustainability report and Environment, Social and Governance metrics according to the
Global Reporting Initiative (GRI) standards as well as the sustainability reporting guide of the Global Oil and Gas Association
for Advancing Environmental and Social Performance (IPIECA, 2020), selected metrics of the Sustainability Accounting
Standards Board (SASB, 2018) and in alignment with Spain’s Law 11 of 2018 on non-financial information disclosures.
Furthermore, our 2023 SPEED/ESG+ Report will include the guidelines of the Task Force on Climate Related Financial
Disclosures (TCFD) for the first time.
In 2023, we submitted the Carbon Disclosure Project’s (CDP) Climate Change questionnaire for the second time and
obtained a B rating, an improvement from the C obtained in the year prior. We also submitted the CDP water questionnaire for
the first time and obtained a C giving us a baseline against to benchmark future performance.
We were recognized with the 2023 Portfolio Award in the Corporate Social Responsibility category. The Portfolio Awards
are given annually by the “El Tiempo” editorial house to companies with outstanding sustainability performance.
In 2022, the Colombian national government, through its department for social prosperity, once again recognized our
“Sustainable Housing” program among the 24 most important public, private and international cooperation programs in terms
of overcoming poverty in Colombia. The homes of more than 2,000 families that are neighbors to our areas of operation in the
country have been benefitted by this program, which we have been carrying out since 2013 in alliance with the ‘Minuto de
Dios’ corporation.
In 2022, we participated along with the 150 largest companies in Colombia, obtaining special recognition for best
performance in the “Focusing” component associated with the implementation of social and environmental investment
initiatives in the most vulnerable areas and populations of the country.
Since 2021, we have participated in the private social investment index, an independent syndicated study conducted by
Jaime Arteaga y Asociados (JA&A), which aims to measure the effort of the private sector to improve the living conditions of
communities and/or population groups based on their voluntary decision to invest in social and environmental projects.
In 2019, we joined the Equipares gender equality certification program, an initiative of the Colombian government and
the United Nations Development Program (UNDP) focused on achieving parity in the workplace. In 2020, we created a
standing company-wide committee to implement action plans that encourage and sustain the values of equity, inclusion and
diversity. In 2020, we also reported for the first time our gender equality metrics using the Bloomberg Gender Reporting
Framework. In 2021, we achieved the Equipares Silver Seal, after the Colombian Institute of Technical Standards and
Certification (ICONTEC) gave a 91/100 rating to our SGIG (Gender Equality Management System).
In 2018, the Colombian government granted GeoPark the “Best Social Practices in the Energy Industry” award for our
good neighbor social conflict prevention program. GeoPark’s model for community engagement was chosen out of 107
different initiatives by a panel composed of representatives from the Ministry of Mines and Energy, the National
Hydrocarbons Agency and the United Nations Development Program. In 2019, we won the “Best Social Practices in the
Energy Industry” award for the second year in a row, along with the “Best Socio-Laboral Practices” award for our “Juntos
Sumamos” program. In 2021, we again won the “Best Social Practices in the Energy Industry” award for our “Sustainable
Housing” program, which improves the living conditions and well-being of our neighbors in Casanare and Putumayo. The
jury was composed of public sector members and representatives from academic and multilateral organizations. The award
was determined based on the impact of each initiative, its sustainability efforts, innovation, and relation to the 2030 agenda.
Additionally, we recently improved our performance in the MSCI ESG Ratings Assessment from A to AA, providing our
stakeholders with further evidence of our commitment to sustainability and value generation across the board.
Our approach on human rights seeks to conduct business in a way that is consistent with the UN Guiding Principles on
Business and Human Rights (the “UN Guiding Principles”), the ten UN Global Compact Principles and the Voluntary
Principles on Security and Human Rights. Our commitment to these standards is reflected in our SPEED program, as well as
in all our policies and procedures. Human Rights aspects are integrated into internal management processes, tools,
communications, contracts, and trainings.
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As part of our commitment to sustainable development and the sustainability development goals, we joined the United
Nations Global Compact in 2023.
We have a grievance mechanism in place for all our blocks and operations in Colombia, which is aligned with the UN
Guiding Principles (UNGP) on Business and Human Rights, meaning it is accessible, legitimate, aligned with judicial and
non-judicial grievance mechanisms, based on dialogue and participation, and predictable, to name a few of the eleven
principles established in the UNGP. Having open, accessible, transparent, and respectful communication with all our
stakeholders is crucial to respecting their human rights to information and participation. Our grievance mechanism,
“Cuéntame” (“Tell me” in English), is one of our most important tools to engage with communities, contractors and service
providers, and our employees on the ground, and this is especially true because it is easily accessible to all through all our
social engagement employees, email, several mobile and Whatsapp numbers, and an office in the biggest city close to our
operations. Furthermore, if any stakeholder approaches our doors, they will be informed about the mechanism and will be able
to present a grievance, complaint or question immediately. To further align and strengthen our grievance mechanism with the
highest standards on human rights, in 2022, we worked with a reputable NGO in Colombia called “Fundación Ideas para la
Paz” to assess “Cuéntame” against the UNGP, the OECD Guidance, the International Financial Corporation and the World
Bank standards. We were ranked as having best practices (meaning a complete level of implementation) in one of the UNGP,
as having high level of progress and implementation in eight of the UNGP, and as having progress with an opportunity to
improve in two of the UNGP. As part of the results, we have implemented a plan to close some of the gaps identified, for
example by increasing the number of forums and meetings to communicate and raise awareness of the existence of the
grievance mechanism, as well as providing stakeholders the opportunity to give feedback on the mechanism’s operation,
effectiveness, responses, among others. To be even closer to our neighbors in Colombia, we opened a “Cuentame” office in
Puerto Asis (Putumayo) in 2021 and one in Tauramena (Casanare) in 2023. The offices are open to the community, and
through it GeoPark seeks to continue strengthening dialogue with all its stakeholders and encourage active community
participation so that all neighbors can share proposals and ideas to promote harmonious coexistence and good neighborliness.
For further information related to health, safety and environmental matters, please see “—Health, safety and
environmental matters.”
Transparency, ethics and anti-corruption
Transparency is a cornerstone of good governance and it is embodied in our corporate values. Transparency allows
business to prosper in a predictable and competitive environment. We believe that doing business in an ethical and transparent
manner is a prerequisite for sustainable business. We have zero-tolerance policy towards all forms of corruption. This policy is
embedded across our Company through our corporate values, our Code of Conduct (Our Code), and our Compliance Program.
They prohibit all forms of corruption and bribery and reflects our values and our commitment to high ethical standards in
business activities; they apply to all our employees, board members and third parties.
Our Compliance Program aims to support and promote an ethics culture, as well as create and establish commitments and
procedures that ensure internal and external regulatory compliance and anti-corruption matters. Program execution and
implementation is the responsibility of our Compliance Department, which is directed by the Corporate Governance and
Compliance Manager, who reports directly to the Audit Committee. Additionally, the Board's Audit Committee monitors the
effectiveness of the compliance program, controls, and risk mitigation measures, and oversees plans to strengthen ethical
culture. The program is based on three pillars:
●
Prevention: ethics-based culture, including tone from the top matters, training and awareness and ethic line
management.
● Detection: risk assessment and advisory, including policies and procedures assurance, laws and regulations
compliance and risk assessment management.
● Monitoring: monitor and oversight, including on-going monitoring, due diligence third parties and regulations
oversight.
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Since 2018, we have actively participated in the Colombian Extractive Industries Transparency Initiative (EITI) and
contributed data to the country’s annual EITI report. During 2023, GeoPark continued its adherence to the Business Ethics
Leadership Alliance (BELA) as part of its efforts to continue strengthening its ethical culture. BELA is a platform of more
than 375 companies in 60 industries recognized worldwide for their ethics and compliance leadership.
Highly committed founding shareholder and technical and management teams with proven industry expertise and
technically-driven culture
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.
One of our founding shareholders and current Vice Chair of the Board, Mr. James F. 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 19, 2024, Mr. Park held 15.9% of our outstanding common shares.
Our management and operating team have an average experience in the energy industry of more than 25 years in
companies such as Chevron, Ecopetrol, ENAP, Petrobras, Pluspetrol, San Jorge, Total 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 19, 2024, our executive directors and executive officers (excluding Mr. James F. Park) owned
1.2% 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.” One of our founding shareholders is also involved in our daily operations and strategy.
Technically-driven culture and capitalization of local knowledge
We intend to continue to 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.
Innovation
We embrace innovation as a foundation for cultivating a dynamic work culture that consistently seeks improvements in
our operational processes. The objective is to streamline costs, increase production, minimize risks, and optimize information
management. At GeoPark, we firmly believe that creating an innovative culture is necessary for ensuring our enduring
success.
Through a proactive approach to innovation, our goal is to create positive impacts on productivity, enable effective
decision-making based on reliable and timely information, fortify teamwork, foster leadership skills, and establish a culture
that champions creativity and innovation.
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The innovation program continues to generate not only tangible benefits across the company and environmental
sustainability, but strengthens the development of new skills within the organization. Innovation not only contributes to
improving internal conditions but also plays a vital role in positively influencing the communities where we operate.
In 2023, we diligently monitored a range of innovation projects identified during workshops, effectively fostering a
culture of innovation across various areas. The integration of digital capabilities, including Artificial Intelligence, Machine
Learning, Internet of Things, Big Data, Automation, and Cloud Computing, marked a significant achievement. Throughout the
year, collaborative innovation initiatives with leading partners such as Microsoft, Google, Halliburton, Cisco, SAP, Indra and
many others were executed, showcasing our commitment to cutting-edge advancements.
The ongoing innovation journey is exemplified by several projects, some still in progress:
● Horizontal drilling: implementing a pilot and executing horizontal drilling campaign, improving the recovery
factor in our reserves of hydrocarbons in the Llanos 34 Block.
● Carbon Quantum Dot (CQD): simultaneous development and injection of Nanotracers based on CQD for
waterflooding in Llanos 34 Block, allowing us to not only prove the technology but also obtain tax benefits.
● Process Integration: implementing systems aimed at achieving high reliability level of production tests data
utilizing Multiphase Meter equipment while expediting their management. Additionally, optimizing production
data to minimize the time required for information gathering, analysis, and identification of opportunities to
increase production in the wells.
● Nanotechnology PoC: applying nanotechnology in fluids to induce specific chemical and physical reactions on a
nanometric scale to improve oil production. The concept is expected to be proven in 2024.
● Centrifuge for tank bottoms: implement a centrifuge decanter to reduce waste-water in +50%, reducing OPEX
and CO2 emissions in our operation in the Llanos 34 Block. It is expected to be implemented in 2024.
● Electrocoagulation: improving waste-water treatment for injection or road dampening in minor field.
● Facilities optimization: addressing energy consumers and enhancing the energy efficiency of water injection
pumps.
● Video analytics and pipeline failure detection: deploying a real-time monitoring system for facilities powered by
solar energy and artificial intelligence to detect failures and non-ethical intrusions.
● Cloud journey: approximately 100% of the infrastructure is in the cloud with intercloud redundancies and strong
cybersecurity capabilities.
Other innovation projects were executed across all organizational areas, encompassing people, processes, and technology.
We remain vigilant in our commitment to identify innovation opportunities that enhance enterprise productivity, employee
collaboration, communication, and decision-making through technology. Ongoing efforts aim to further embed this innovation
culture throughout the company with plans for new workshops geared towards capturing and developing ideas and
strengthening skills in our team while focusing on: production, geosciences, circular economy and energy transition, and
innovation management.
2024 Strategy and Outlook
Oil prices have been volatile over the past years. In preparation for continued volatility, we have developed multiple
scenarios for our 2024 capital expenditures program.
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Our preliminary base capital program for 2024 considered a reference oil price assumption of US$80-90 per barrel and
calls for approximately US$150-200 million to fund our exploration and development which we intend to fund through cash
flows from operations and cash-in-hand.
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$70 per barrel and
consists of an alternative capital expenditure program of approximately US$100-150 million consisting mainly of certain low
risk projects with shorter payback periods. The upside scenario work program considers a reference oil price assumption
above US$90 per barrel or higher and consists of an alternative capital expenditure program of approximately US$200-250
million to be selected from identified projects designed to increase reserves and production.
To secure minimum oil prices for our 2024 production, we have commodity risk management contracts in place covering
a portion of our production for the year and monitor market conditions on a continuous basis to evaluate additional new
commodity risk management contracts for the future. See Note 8 to our Consolidated Financial Statements.
As part of our strategy, we continue to monitor the impact of oil price volatility on our financial condition, cash flows and
results of operations.
Our operations
We have a portfolio of assets that includes working and/or economic interests in 34 hydrocarbon blocks, 33 of which are
onshore blocks, including 10 in production as of December 31, 2023, and provides the ability to quickly optimize capital
allocation as market conditions change. Our assets give us access to more than 4.7 million gross exploratory and productive
acres.
Operations in Colombia
Our Colombian assets currently give us access to 3,401,000 gross exploratory and productive acres across 20 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 successful exploration and development activities at our operated Llanos 34 Block, which as of
December 31, 2023, accounts for 66.8% of our production and 71.1% of our proved reserves in Colombia.
Highlights of the year ended December 31, 2023, related to our operations in Colombia included:
● Successful drilling and putting into production the Saltador 1, Toritos 1, Bisbita Centro 1 exploration wells in the
Llanos 123 Block;
● Successful drilling and putting into production the Zorzal 1 and Zorzal Este-1 exploration wells in the Llanos 87
Block;
● Successful drilling and putting into production the Halcon 1 exploration well in the CPO-5 Block;
● Drilling campaign with 16 gross development wells drilled and putting into production in the Tigana, Tigui and Tua
oil fields in the Llanos 34 Block, including successful drilling and putting into production 5 horizontal wells in the
Tigana oil field;
● Photovoltaic solar system installed in the OBA export pipeline (running from the Platanillo block) that allows us to
reduce GHG emissions and reduce energy and maintenance costs;
● Average net oil production of 32,795 boepd in 2023 (33,640 boepd in 2022), influenced by a temporary shut-in of the
Indico 6 and Indico 7 wells in the CPO-5 Block from January to September 2023, reaching an exit production in the
fourth quarter of 2023 of 34,154 boepd;
● Proved oil and gas reserves 59.5 mmboe at year-end 2023 (64.6 mmboe at year-end 2022), after producing 11.2
mmboe;
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● Capital expenditures of US$178.1 million in 2023 (US$139.2 million in 2022), representing an 89% of our total
capital expenditures; and
● Operating costs levels per barrel of US$11.5 in 2023 (US$6.6 in 2022), mainly due to higher energy costs in the
Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of
hydroelectric power.
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.
The table below summarizes information about the blocks in Colombia in which we have working interests as of and for
the year ended December 31, 2023.
Gross acres
(thousand
acres)
61.8
148.3
490.8
Working
interest(1)
100%
50%
30%
Partners(2)
—
Parex
ONGC Videsh
Operator
GeoPark
Parex
ONGC Videsh
Production
(boepd)
Basin
— Putumayo
— Llanos
5,563 Llanos
8.5
12.5%
Verano Energy
Verano Energy
360 Llanos
59.1
255.5
107.6
89.2
274.8
88.3
27.6
74.1
27.5
102.8
121.5
114.6
148.0
589.0
586.6
45%
50%
50%
50%
50%
50%
50%
50%
100%
50%
50%
100%
50%
50%
50%
Verano Energy
Hocol
Hocol
Parex
Hocol
Hocol
Hocol
Sierracol Energy
—
Sierracol Energy
Sierracol Energy
—
Sierracol Energy
Sierracol Energy
Sierracol Energy
GeoPark
GeoPark
GeoPark
Parex
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
24,425 Llanos
— Llanos
68 Llanos
— Llanos
— Llanos
352 Llanos
— Llanos
— Putumayo
Putumayo
— Putumayo
— Putumayo
— Putumayo
— Putumayo
— Putumayo
— Putumayo
2,103
Block
Coatí
CPO-4-1
CPO-5
Llanos 32
Llanos 34
Llanos 86
Llanos 87
Llanos 94(4)
Llanos 104
Llanos 123
Llanos 124
Mecaya
Platanillo
PUT-8
PUT-9
PUT-14
PUT-36
Tacacho
Terecay
Concession
expiration year
Exploration: Currently suspended
Exploration: 2025
Exploration: 2025
Exploitation: 2042-2045(3)
Exploration: 2022
Exploitation: 2040-2045(3)
Exploitation: 2039-2045(3)
Exploration: 2026
Exploration: 2023
Exploration: 2025
Exploration: 2026
Exploration: 2024
Exploration: 2024
Exploration: Currently suspended
Exploitation: 2033(3)
Exploration: 2024
Exploration: Currently suspended
In process of termination
Exploration: Currently suspended
In process of termination
In process of termination
(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) Partners with working interests.
(3) The concession expiration year is set on a field-by-field basis.
(4) In process of transferring our working interest in the block to the partner.
As of December 31, 2023, we had net proved reserves of 56.3 mmboe in various blocks in the Llanos Basin, with the
Llanos 34 Block representing 83.6% of the reserves, and 3.2 mmboe in the Platanillo Block in the Putumayo Basin.
The table below summarizes information about the blocks in Colombia in which we have economic interests as of and for
the year ended December 31, 2023.
Block
Abanico
Gross acres
(thousand
acres)
25.7
Economic
interest(1) Operator
10% Frontera
Production
(boepd)
Basin
20 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.
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Eastern Llanos Basin:
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 shale basinal facies of the Gachetá formation. The main reservoirs of the basin are represented by the Paleogene
Carbonera, Guadalupe 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 59,085 gross acres (239 sq. km.). We acquired an interest in and took operatorship of the block in the first
quarter of 2012, which at that 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 2023 we engaged in exploration
and development activities that resulted in 10 new oil fields discoveries and increased proved reserves and oil production up to
a peak oil production of 34,995 bopd. Average net production in 2023 was 24,425 bopd and net reserves of 47.1 mmboe. By
the end of 2023, we have drilled more than 230 wells, with 166 producer wells that have accumulated more than 179 million
barrels of oil. The Llanos 34 Block has three reservoirs: the Guadalupe Formation, which produces 72% of our oil production
in the Block, Mirador, which produces 26% of our oil production in the Block and Gacheta, which produces 2% of our oil
production in the Block, with an API gravity between 12.7° and 30.6°. During these 12 years of operation in Llanos 34 Block,
we have built all the required infrastructure to produce and manage the fluids of the assets, including 10 production facilities,
81 kilometers of power grid, more than 97 kilometers of flowlines for fluid transfer, 169 kilometers of roads and a 42
kilometers oil pipeline. By the end of 2023, we have transported more than 72 million barrels of oil from Tigana and Jacana
fields through the ODCA pipeline further reducing truck traffic, contributing to the reduction of operational risk, shutdowns
(due to road blockades), costs and carbon emissions. In August 2022, we connected the Llanos-34 Block to the national power
grid, reducing the risk of shutdown, cost and carbon emissions. In October 2023, we entered into an interconnection
agreement through which we expect to have an additional 20 megawatts of power energy transmission capacity available for
our operations in Llanos 34 Block by early 2025.
Our partner in the Llanos 34 Block is Verano Energy (a subsidiary of 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.”
Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block. The Llanos 32 Block covers approximately
8,556 gross acres (35 sq. km.). Verano Energy is the operator of this block and has an 87.5% 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, 2023, our average net production in the Llanos 32 Block was 360 bopd. As of the date of this annual report, we
do not aim to continue exploring on certain exploration acreage available in the Llanos 32 Block, and therefore, we will retain
interest on the existing producing fields only.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block
association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico
Block, which covers an area of approximately 25,658 gross acres (103 sq. km.). 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 Frontera, who subsequently assigned its
participation interest to Cepsa Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral
Finance Corporation and Getionar S.A.
Llanos 86 and Llanos 104 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working
interest executed an E&P contract over these blocks on July 11, 2019, as a result of the Permanent Competitive Process
launched by ANH in 2019. We are the operator of these contracts that are in their exploratory phase 1 and cover approximately
530,309 gross acres (2,146 sq. km.). Due to the presence of indigenous communities in the area, we conducted the due prior
consultation process with these communities and reached agreements, thereby concluding the process on August 29, 2023. We
requested, and the ANH approved, an extension of the first phase of the exploratory
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period in the Llanos 86 and Llanos 104 Blocks due to delays attributable to the environmental authority in approving
environmental management measures. Accordingly, as of the date of this annual report, outstanding investment commitments
consist of acquisition of 3D seismic and drilling of one exploratory well in each block for an estimated amount of US$9.8
million for Llanos 86 Block and US$8.8 million for Llanos 104 Block, before June 19, 2026.
Llanos 87 Block. We and Hocol, each with fifty percent (50%) working interest executed an E&P contract over this block
on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019, and we are the operator of this
contract. As of the date of this annual report, the total investments needed to fulfill the exploratory activities committed in the
block have already been incurred and the ANH final acquittal-approval is pending. As a result of the activity performed during
the exploratory period, we made two discoveries in the block: Tororoi and Zorzal. Therefore, we submitted to the ANH an
appraisal program for each of Tororoi and Zorzal, which includes the drilling of one exploratory well during the two-year term
ending July 27, 2025. As of the date of this annual report, the ANH approval for the appraisal program is pending.
Llanos 123 and Llanos 124 Blocks: We and Hocol, each with fifty percent (50%) working interest executed E&P contracts
over these blocks on December 20, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are
the operator of these contracts that cover approximately 115,956 gross acres (469 sq. km.). Phase 1 commitments related to
these blocks corresponded to (i) reprocessing 3D seismic and drilling of two exploratory wells for Llanos 123 Block for an
estimated amount of US$7.1 million before January 14, 2024, and; (ii) the acquisition and reprocessing of 3D seismic and
drilling of three exploratory wells for Llanos 124 Block for an estimated amount of US$10.4 million before January 14, 2024.
As of the date of this annual report, the total investments needed to fulfill the commitments in the blocks have already been
incurred or transferred to another block, and the ANH approval is pending.
Llanos 94 Block. On July 24, 2019, the E&P contract was awarded to Parex Energy as a result of the Permanent
Competitive Process launched by ANH in 2019. We acquired a 50% working interest from Parex and obtained ANH’s
approval to such transfer in May 2020. As a result of an extension in the exploratory period approved by the ANH in 2023, the
current Phase 1 commitments consist of drilling one exploratory well before October 1, 2025. However, we are not interested
in drilling such prospect and agreed to transfer our 50% working interest back to our partner and thus we are not liable for the
exploratory commitment in the block.
CPO-5 Block. On December 26, 2008, the E&P contract was executed between ONGC Videsh, as operator and the ANH
as a result of the Competitive Process “Ronda Colombia 2008”. This contract covers approximately 490,825 gross acres
(1,986 sq. km.). We hold a 30% working interest since the acquisition of Amerisur in 2020. As of the date of this annual
report, this contract is in exploratory phase 2 in which the pending commitment corresponds to the acquisition, processing and
interpretation of 73 sq. km. of 3D seismic for an amount of US$2.9 million, and drilling of one exploratory well for an amount
of US$6.4 million, to be fulfilled before May 18, 2027. As of the date of this annual report, the committed exploratory well
has already been drilled. There are two commercial fields called Mariposa and Indico, and we also had successful drilling and
putting into production exploration wells in the fields called Flamenco, Halcon and Perico. Average net production in 2023
was 5,563 bopd and net reserves were 6.3 mmboe.
CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of
the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was
executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this
annual report, this contract is in exploratory phase 1 and covers approximately 148,263 gross acres (600 sq. km.). The
outstanding investment commitment related to the block corresponds to the drilling of an exploratory well for an estimated
amount of US$2.9 million before September 19, 2025.
Magdalena Basin:
VIM-3 Block. As of the date of this annual report, the ANH has approved the termination and final liquidation of the
contract is in process.
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Putumayo Basin:
Coati Block. We are the operator of and have a 100% working interest in the Coati Block, which covers approximately
61,843 gross acres (250 sq. km.). The outstanding exploration commitment consisted of the acquisition of 57 sq. km. of 3D
seismic and 30 km. of 2D seismic, for an estimated amount of US$4.5 million. The evaluation area is currently suspended. On
November 3, 2022, we submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and
transfer the pending commitments to other E&P contracts. As of the date of this annual report, we completed the transfer of
the pending commitments in the block and the ANH approval is pending.
Mecaya Block. We are the operator of and have a 50% working interest in the Mecaya Block, which covers approximately
74,128 gross acres (300 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this
annual report, the contract is in unified phases 1 and 2 of the exploration period, which remaining exploration commitment
consists of the acquisition of 52.2 sq. km. of 3D seismic for an amount of US$0.6 million. On December 2010, the former
operator declared an evaluation area and presented an evaluation program for the Mecaya-1 well (Mecaya Evaluation
Program). Both the unified phases 1 and 2 and the evaluation program are currently suspended due to force majeure events
(relating to prior consultations).
Platanillo Block. We are the operator of and have a 100% working interest in the Platanillo Block, which covers
approximately 27,500 gross acres (111 sq. km.). On September 11, 2009, we began the commercial exploitation of the
Platanillo Block. Average net production in 2023 was 2,103 bopd and net reserves of 3.2 mmboe.
Putumayo 8 Block. We are the operator of and have a 50% working interest in the Putumayo 8 Block, which covers
approximately 102,800 gross acres (416 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. The
contract is in unified phases 1 and 2 of the exploration period. Outstanding investment commitments of US$13.1 million
related to this block correspond to the drilling of 3 exploratory wells and the acquisition of 112 sq. km. of 3D seismic before
June 14, 2024. Part of the 3D seismic committed in the block was acquired during 2020 and 2021. On October 25, 2022, we
submitted to the ANH a request to transfer the investment commitment related to the pending 3D seismic to the Platanillo
Block, and the partner reported the transfer of the outstanding committed value to one of its blocks. This transfer of
commitments is subject to authorization from the ANH. During 2023, the actions required to obtain environmental licenses
were carried out, including holding of a public environmental hearing. As a result, in August 2023, the environmental
authority granted the license for the Bienparado project, which was confirmed in January 2024. Additionally, the Nyctibius
project public environmental hearing is pending by the environmental licensing authority (Autoridad Nacional de Licencias
Ambientales or ANLA).
Putumayo 9 Block. We are the operator of and have a 50% working interest in the Putumayo 9 Block, which covers
approximately 121,453 gross acres (491 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of
the date of this annual report, the contract is in phase 1 of the exploration period and outstanding investment commitments of
US$4.4 million related to this block correspond to drilling of two exploratory wells before October 14, 2020, and the
acquisition of 126.25 sq. km. of 3D seismic. Phase 1 was suspended on June 25, 2019, due to the occurrence of a force
majeure event consisting of the issuance of the Municipal Agreement No. 007 of Puerto Guzmán, which prohibits the
hydrocarbon exploration and production activities in such municipality.
Putumayo 14 Block. We are the operator of and have a 100% working interest in the Putumayo 14 Block, which covers
approximately 114,560 gross acres (464 sq. km.). Exploration commitments in the block corresponded to the acquisition of 2D
seismic and drilling of an exploratory well for an estimated amount of US$16.1 million. On March 10, 2022, we submitted to
the ANH a request to withdraw from the PUT-14 E&P contract and transfer the pending commitments to the Platanillo and
CPO-5 Blocks. Once total investment is reached through such transfers, ANH will continue with the contract’s termination. As
of the date of this annual report, the total investment needed to fulfill the commitments has already been incurred and the
ANH approval is pending.
Putumayo 36 Block. We are the operator of and have a 50% working interest in the Putumayo 36 Block, which covers
approximately 148,021 gross acres (599 sq. km.). Sierracol is the owner of the remaining 50% working interest. As part of the
prior consultation process, the Ministry of Interior certified the presence of one indigenous community in the area. As of the
date of this annual report, the contract is in phase 0 as the applicable prior consultation process must be completed.
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Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will
enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the block over the
three-year term of phase 1 would be the acquisition of 105.6 sq. km. of 3D seismic and the drilling of two exploratory wells
for an estimated amount of US$11.7 million. Prior consultation has not been initiated with the ethnic community due to the
restrictions from the issuance of Municipal Agreement No. 007 of Puerto Guzmán, which caused the current phase 0 of the
process to be suspended.
Tacacho and Terecay Blocks. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks,
which covers approximately 589,009 gross acres (2,384 sq. km.) and 586,625 gross acres (2,374 sq. km.), respectively.
Sierracol Energy is the owner of the remaining 50% working interest. Both contracts are in phase 1, which is currently
suspended due to the occurrence of force majeure events related to social and public order conditions of the area. The
outstanding investment commitments corresponded to (i) the acquisition, processing and interpretation of 480 km. of 2D
seismic for the Tacacho Block with an estimated amount of US$1.2 million, and; (ii) the acquisition, processing and
interpretation of 476 km. of 2D seismic for the Terecay Block with an estimated amount of US$2.9 million. On September 21,
2022, we submitted to the ANH a request for termination of the E&P contract and, in January 2024, we submitted additional
third-party reports as supporting documentation to such request. As of the date of this annual report, the termination request is
under review by the ANH.
As per farm-out agreement executed on November 21, 2018, Sierracol Energy shall carry us in certain exploration
activities for the Mecaya, PUT-9, Tacacho and Terecay Contracts.
Andaquies, Putumayo 12 and Putumayo 30 Blocks. As of the date of this annual report, the ANH has approved the
termination and final liquidation of the contracts is in process.
Operations in Ecuador
Our Ecuadorian assets currently give us access to 33,300 of gross exploratory and productive acres across 2 blocks in an
attractive oil and gas geography.
Highlights of the year ended December 31, 2023, related to our operations in Ecuador include:
● Successful drilling and putting into production of the Perico Centro 1 exploration well, and the Yin 2 and Perico
Norte 4 appraisal wells in the new combined structural/stratigraphic U-sand play in the Perico Block;
● Average net oil production of 926 boepd in 2023 (848 boepd in 2022), reaching an exit production in the fourth
quarter of 2023 of 1,419 boepd;
● Proved oil reserves of 2.3 mmboe (100% in the Perico Block) at year-end 2023 (0.3 mmboe at year-end 2022), after
producing 0.3 mmboe;
● Capital expenditures of US$20.9 million in 2023 (US$18.5 million in 2022), representing an 11% of our total capital
expenditures.
The table below summarizes information about the blocks in Ecuador in which we have working interests as of
December 31, 2023.
Block
Espejo
Perico
Gross
acres
(thousand
acres)
15.6
17.7
Working
interest (1)
50%
50%
Operator
GeoPark
Frontera
Production
(boepd)
Basin
67
Oriente
859
Oriente
Expiration
concession year
Exploration: 2025
Exploitation: 2045
Exploration: 2025
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 each block.
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Espejo and Perico blocks
In May 2019, we signed participation contracts for the Espejo and Perico Blocks. We are the operator of the Espejo Block
with a 50% working interest, and Frontera is the operator of the Perico Block with 50% working interest. We assumed a
commitment of carrying out 3D seismic and drilling four exploration wells in the Espejo Block for an estimated amount of
US$20.9 million during the first exploratory period ending June 17, 2025 and drilling four exploratory wells in the Perico
Block for an estimated amount of US$18.1 million during the first exploratory period ending June 16, 2025. As of the date of
this annual report, we have drilled the four exploratory wells in the Perico Block (hence Perico Block does not have any
pending exploratory commitments) and we have completed the acquisition of 60 sq km of 3D seismic and drilled two
exploratory wells in the Espejo Block.
Operations in Brazil
Our Brazilian assets currently give us access to 61,400 of gross exploratory and productive acres across 6 blocks (5
exploratory blocks and the BCAM-40 Concession, which is in production phase) in an attractive oil and gas geography.
Highlights of the year ended December 31, 2023, related to our operations in Brazil included:
● Average net oil and gas production of 1,027 boepd (98.5% gas) in 2023 (1,516 boepd in 2022); and
● Proved oil and gas reserves in the Manati Block of 1.5 mmboe at year-end 2023 (from 1.6 mmboe at year-end 2022),
after producing 0.4 mmboe.
The following table sets forth information as of December 31, 2023, on our concessions in Brazil in which we have a
current or future working interest:
Concession
POT-T-785
REC-T 58
REC-T 67
REC-T 77
POT-T 834
Gross acres
(thousand
acres)
7.9
7.8
7.7
7.7
7.5
Working
interest(1)
70%
100%
100%
100%
100%
Partners
Petroil
—
—
—
—
Operator
GeoPark
GeoPark
GeoPark
GeoPark
GeoPark
Production
(boepd)
Basin
— Potiguar
— Recôncavo
— Recôncavo
— Recôncavo
— Potiguar
Manati
22.8
10%
Petrobras; Enauta; Gas
Bridge Storage S.A.
Petrobras
1,027
Camamu-
Almada
Concession
expiration year
Exploration: 2025
Exploitation: 2050
Exploration: 2025
Exploitation: 2052
Exploration: 2025
Exploitation: 2052
Exploration: 2025
Exploitation: 2052
Exploration: 2025
Exploitation: 2052
Exploitation: 2029
(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.
Manati Field
We have a 10% working interest in the BCAM-40 Concession, which originally included an interest in the Manati Field,
which is located in the Camamu-Almada Basin. Petrobras is the operator of, 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 Gas Bridge Storage S.A. and Enauta Energia S.A. (Enauta), 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.
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The Manati Field is located 65 km. south of Salvador, offshore at a water depth of 35 meters. 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, 2023, 11 wells had been drilled in the Manati Field, 6 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.
POT-T-785 Concession
The POT-T-785 block covers an area of 7,875 acres in the Potiguar Basin, surrounded by producing fields operated by
Petrobras. Total commitment to the ANP was R$1.2 million (US$0.2 million, at the December 31, 2023, exchange rate of
R$5.22 to US$1.00) during the first exploratory period and is equivalent to acquiring 4 sq. km. of 3D seismic and performing
geochemical analysis before April 29, 2025. In 2023, preliminary activities for the environmental licensing have started. As of
December 31, 2023, the estimated remaining commitment in the POT-T-785 block amounts to US$0.1 million.
POT-T-834, REC-T-58, REC-T-67 and REC-T-77 Concessions
During ANP’s First Open Acreage Bid Round held in September 2019, we were awarded four exploratory blocks, one in
the Potiguar Basin (Block POT-T-834) and three on the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). The
Concession Agreements were executed in February 2020. In 2023, we started preliminary activities for the environmental
licensing in Block POT-T-834. As of December 31, 2023, the estimated commitment in the blocks to be executed before
February 14, 2025, amounted to US$0.6 million.
Operations in Chile
In December 2023, we entered into an agreement to sell our Chilean subsidiaries which comprised the entirety of our
business in the country. The divestment transaction closed in January 2024 and, as part of the transaction, we have retained
certain rights over unconventional activities that would be carried out in the Fell Block over the current operating contract in
the future.
The table below summarizes information about the blocks in Chile in which we had working interests as of and for
the year ended December 31, 2023.
Block
Fell
Isla Norte
Campanario
Flamenco
Gross
acres
(thousand
acres)
367.8
97.7
144.2
47.1
Working
interest (1)
100%
60%
50%
50%
Partners (2)
—
ENAP
Operator
GeoPark
GeoPark
Production
(boepd)
Basin
1,720 Magallanes
— Magallanes
ENAP
GeoPark
— Magallanes
ENAP
GeoPark
— Magallanes
Concession
expiration year
Exploitation: 2032
Exploration: 2024
Exploitation: 2044
Exploration: 2024
Exploitation: 2045
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 each block.
(2) Partners with working interests.
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 completed more than 1,100 sq. km. of 3D
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seismic surveys and drilled 141 exploration and development wells. In the year ended December 31, 2023, we produced an
average of 1,720 boepd in the Fell Block, consisting of 87.2% gas.
Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)
In 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 were the operator of the three
blocks, with working interests of 60%, 50% and 50%, respectively. As of the date of closing of the divestment transaction,
there were outstanding investment commitments of US$0.9 million and US$5.0 million related to the Isla Norte and
Campanario Blocks, respectively, and pursuant to the terms of the divestment transaction, we remain liable for such
outstanding investment commitments.
Operations in Argentina
The table below summarizes information about the blocks in Argentina in which we had working interests as of and for
the year ended December 31, 2023.
Block
Puelen
Los Parlamentos
Gross
acres
(thousand
acres)
260.2
330.9
Working
interest (1)
18%
50%
Operator
Pluspetrol
YPF
Production
(boepd)
Basin
— Neuquén
— Neuquén
Expiration
concession year
In process of relinquishment
Exploration: 2023
(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.
Puelen Block
On August 20, 2014, the consortium of Pluspetrol and us was awarded the exploration license in the Puelen Block, 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). As of December 31, 2023, we fulfilled the total commitments and are in
process of relinquishing the block.
Los Parlamentos Block
In June 2018, we announced the acquisition of a 50% working interest in the Los Parlamentos exploratory block in
partnership with YPF, the largest oil and gas producer in Argentina. In accordance with the partnership agreement, YPF
assumed the operatorship of the block and we assumed a commitment which amounted to US$6 million at our working
interest. On October 27, 2023, we agreed to transfer our 50% working interest in the Los Parlamentos Block to YPF and thus,
once formally approved by local authorities, we will no longer be liable to remaining capital commitments or other legal
obligations resulting from our participation in the block.
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Oil and natural gas reserves and production
Our reserves
The following table sets forth our oil and natural gas net proved reserves as of December 31, 2023, which is based on the
D&M Reserves Report.
Net proved reserves
As of December 31, 2023
Total net
proved
reserves
(mmboe)(1)
Natural gas
(bcf)
Oil
(mmbbl)
Net proved developed
Colombia
Ecuador
Brazil
Chile
Total net proved developed
Net proved undeveloped
Colombia
Ecuador
Chile
Total net proved undeveloped (2)
Total net proved (Colombia, Ecuador, Brazil and Chile)
43.1
1.0
0.0
0.6
44.8
16.2
1.3
0.5
18.0
62.8
1.1
—
8.9
10.0
19.9
—
—
0.9
0.9
43.3
1.0
1.5
2.3
48.1
16.2
1.3
0.6
18.1
% Oil
99.6 %
100.0 %
1.9 %
27.2 %
93.1 %
100.0 %
100.0 %
77.1 %
99.2 %
20.8
66.2
94.8 %
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
(2) We plan to put 100% of our reported 2023 year-end proved undeveloped reserves into production through activities to be
implemented within five years of initial disclosure.
We had net proved reserves of 66.2 mmboe at December 31, 2023, compared to net proved reserves of 70.4 mmboe as of
December 31, 2022.
The 6% decrease in net proved reserves in 2023 is mainly attributable to:
● Production of 12.5 mmboe; and
● Lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl.
This was partially offset by:
● Extensions and discoveries that resulted in an increase of 4.5 mmboe in various fields in the Llanos Basin in
Colombia and the Jandaya field extension in the Perico Block in Ecuador;
● Changes in a previously adopted development plan in Colombia, resulting in 1.7 mmbbl increase;
● Higher-than-expected performance from the existing wells in Colombia and Brazil, resulting in an increase of 1.5
mmbbl and 0.3 mmboe, respectively;
● Changes in the royalties payment in certain fields in Colombia from kind to cash, resulting in a 0.4 mmboe increase;
and
● Higher average prices in Ecuador, resulting in a 0.3 mmboe increase.
During the year ended December 31, 2023, we had 4.3 mmboe of our proved undeveloped reserves from
December 31, 2022, converted to proved developed reserves due to development drilling in various blocks in the Llanos Basin
in Colombia. For further information relating to the reconciliation of our net proved reserves for the years ended
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December 31, 2023, 2022 and 2021, please see Table 5 included in Note 38 (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 estimating process and who have knowledge of the specific properties under evaluation. Our Chief
Technical Officer, Augusto Zubillaga, is primarily responsible for overseeing the preparation of our reserves estimates and for
the internal control over our reserves estimation. He has over 26 years of experience in production, engineering, well
completion, corrosion control, reservoir management and field development. See “Item 6. Directors, Senior Management and
Employees—A. Directors and executive officers.”
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.
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 Corporate Reserves team, the Executive Committee (integrated by the Chief Executive
Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy,
Sustainability and Legal Officer and Chief People Officer) and the Technical Committee (composed by four technical experts
of our board of directors). A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be
reviewed and analyzed by the Technical Committee which recommends to the Board of Directors to approve its disclosure and
publication. 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, 2023, for Colombia, Ecuador, Brazil and Chile included elsewhere in this annual
report are based on the D&M Reserves Report, dated March 1, 2024, and effective as of December 31, 2023. 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 Corp. (“DeGolyer and MacNaughton” or “D&M), a Delaware corporation with offices in
Dallas, Houston, Moscow, Algiers, Astana and Buenos Aires has been providing consulting services to the oil and gas industry
since 1936. The firm has more than 200 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
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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)(1)-(32) 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.
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
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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 materially changes.
Proved undeveloped reserves
As of December 31, 2023, we had 18.1 mmboe in proved undeveloped reserves, a decrease of 0.1 mmboe, or 1%,
compared to our December 31, 2022, proved undeveloped reserves of 18.2 mmboe. Changes for the year ended
December 31, 2023, include:
(i)
(ii)
a decrease of 4.3 mmboe in Colombia due to the conversion of proved undeveloped reserves to proved
developed reserves in various fields in the Llanos Basin;
a decrease of 0.8 mmboe due to a lower-than-expected performance in Colombia (0.6 mmboe) and Ecuador (0.2
mmboe); and
(iii)
a decrease of 0.1 mmboe due to lower average gas prices in Chile.
This was partially offset by:
(iv)
(v)
(vi)
an increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan;
an increase of 1.4 mmboe in Colombia due to the discoveries of various fields in the Llanos Basin;
an increase of 1.2 mmboe in Ecuador due to the extension in the Jandaya field in the Hollin reservoir and the
discovery of the Ui reservoir in the Perico Block;
(vii)
an increase of 0.3 mmboe due to higher-than-expected performance in Chile;
(viii)
an increase of 0.3 mmboe due to change in the royalties’ payment in certain fields in Colombia from kind to
cash; and
(ix)
an increase of 0.2 mmboe due to higher average oil prices in Ecuador.
Of our 18.1 mmboe of net proved undeveloped reserves, 16.2 mmboe (89.5%)1.3 mmboe (7.1%) and 0.6 mmboe (3.4%)
were located in Colombia, Ecuador and Chile, respectively. No net proved undeveloped reserves were located in Brazil as of
December 31, 2023.
During 2023, we incurred approximately US$52.2 million in capital expenditures in Colombia to convert such proved
undeveloped reserves to proved developed reserves.
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The following table shows the evolution of total net proved undeveloped (“PUD”) reserves in the year ended
December 31, 2023.
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2022
(All amounts shown in mmboe)
Plus: Extensions, discoveries and acquisitions:
-Colombia
-Ecuador
Less: PUD Reserves converted to proved developed reserves:
-Colombia
Plus/less: PUD Reserves revisions and movement to/from other categories:
-Colombia
-Chile
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2023
Production, revenues and price history
18.2
1.4
1.2
(4.3)
1.4
0.2
18.1
The following table sets forth certain information on our production of oil and natural gas in Colombia, Ecuador, Brazil,
Chile and Argentina for each of the years ended December 31, 2023, 2022 and 2021.
Average daily production(1)
As of December 31,
2022
Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Arg (2) Colombia Brazil Chile Arg (2)
2021
2023
Oil production
Average crude oil
production (bopd)
Average sales price
of crude oil
(US$/bbl)
Natural Gas
production
Average natural gas
production (mcfpd)
Average sales price
of natural gas
(US$/mcf)
Oil and gas
production cost
Average operating
cost (US$/boe)
Average royalties
and economic rights
in cash (US$/boe)
Average production
cost (US$/boe)(3)
32,795
926
16
221
33,640
848
21
441
80
30,920
26
313
1,215
66.8
69.9
82.1
68.0
82.7
89.9
103.1
94.7
56.7
58.3
70.2
62.8
56.4
573
— 6,065
8,993
776
— 8,967
11,387
416
1,374
11,357
12,507
5,529
3.9
—
6.5
3.4
4.5
—
6.4
3.8
2.0
4.4
5.2
3.4
2.7
11.5
37.5
10.9
13.0
6.6
27.1
7.4
16.1
24.0
6.5
4.6
12.3
20.8
7.9
19.4
—
3.1
0.9
37.5
14.0
13.9
21.0
27.6
—
3.1
1.5
5.0
27.1
10.5
17.6
29.0
9.6
16.2
2.6
7.2
0.9
6.1
13.2
26.9
(1) We present production figures net of interests due to others, but before deduction of royalties, economic rights and
government’s production share, as we believe that net production before royalties, economic rights and government’s
production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and
government’s production share regimes.
(2) “Arg” is Argentina.
(3) Calculated pursuant to FASB ASC 932.
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The following table sets forth certain information on our production of oil and natural gas by final product sold in
Colombia, Ecuador, Brazil, Chile and Argentina for each of the years ended December 31, 2023, 2022 and 2021.
Tigana oil field(1)
Jacana oil field(1)
Rest of Colombia
Ecuador
Brazil
Chile
Argentina
Total
2023
2022
2021
Oil
Mbbl
3,904
4,411
3,655
338
6
81
—
12,395
Gas
MMcf
Oil
Mbbl
— 4,057
— 4,678
3,543
209
310
—
8
2,214
161
3,283
—
29
12,786
5,705
Gas
MMcf
Oil
Mbbl
— 3,670
— 4,023
2,747
283
—
—
9
3,273
100
4,156
434
152
10,983
7,864
Gas
MMcf
—
—
502
—
3,796
4,403
1,584
10,285
(1) The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the
table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years
indicated above.
Drilling activities
The following table sets forth the exploratory wells we drilled during the years ended December 31, 2023, 2022 and 2021.
2023
Exploratory wells(1)
2022
Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Colombia Brazil
2021
Chile Argentina
7.0
3.3
6.0
2.8
3.0
1.5
—
—
— —
— —
13.0
6.0
3.0
1.5
—
—
—
—
—
—
—
—
4.0
2.6
4.0
2.3
8.0
4.9
4.0
2.0
—
—
4.0
2.0
—
—
—
—
—
—
—
—
—
—
—
—
3.0
1.9
3.0
0.8
6.0
2.7
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Productive(2)
Gross
Net
Dry(3)
Gross
Net
Total
Gross
Net
(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.
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The following table sets forth the development wells we drilled during the years ended December 31, 2023, 2022 and
2021.
Productive(1)
Gross
Net
Dry(2)
Gross
Net
Total
Gross
Net
Development wells
2022
Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Colombia Brazil Chile Argentina
2023
2021
25.0
11.8
7.0
3.7
32.0
15.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
28.0
12.0
2.0
0.9
30.0
12.9
—
—
—
—
—
—
—
—
—
—
—
—
1.0
1.0
1.0
1.0
2.0
2.0
24.0
10.8
—
—
24.0
10.8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(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.
Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in
Colombia, Ecuador, Brazil, Chile and Argentina as of December 31, 2023.
Total developed acreage
Gross
Net
Total undeveloped acreage
Gross
Net
Total developed and undeveloped acreage
Gross
Net
Colombia Ecuador
Acreage(1)
Brazil
(in thousands of acres)
Chile
Argentina
25.2
13.0
3,350.4
1,672.4
3,375.6
1,685.4
1.1
0.6
32.2
16.1
33.3
16.7
4.1
0.4
57.3
38.1
61.4
38.5
5.6
5.6
651.2
516.5
656.8
522.1
—
—
591.1
212.3
591.1
212.3
(1) Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on
which wells have not been drilled or completed to a point that would permit the production of commercial quantities of
oil or gas regardless of whether such acreage contains proved reserves. Net acreage is based on our working interest.
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Productive wells
The following table sets forth our total gross and net productive wells as of February 29, 2024. 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.
Oil wells
Gross
Net
Gas wells
Gross
Net
Productive wells(1)
Colombia Ecuador
Brazil
206.0
104.1
2.0
0.3
8.0
4.0
-
-
-
-
6.0
0.6
(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.
Present activities
From January 1, 2024, to February 29, 2024, we produced a net average of approximately 36.1 mboepd, including
production from our operations in Chile up to, and including, January 18, 2024 (the date on which the transaction for the
divestment of our operations in Chile closed).
The main highlights of the 2024 drilling campaign year-to-date are detailed as follows:
● we drilled the Perico 1 well in the CPO-5 Block in Colombia, which tested oil in the northern part of the block, next
to the Llanos 34 Block;
● we drilled the Tigana Horizontal Well 7 and two injector wells in the Llanos 34 Block in Colombia, continuing the
horizontal drilling campaign as well as expanding our water flooding project; and
● we drilled the Perico Norte 5 well in the Perico Block in Ecuador, which tested oil, representing the fourth successful
well drilled in the new U-sand play.
Marketing and delivery commitments
Colombia
Our production in Colombia consists primarily of crude oil which is sold according to price formulas based on market
reference indices (Brent price, Vasconia and Oriente differential) and discounts that consider transportation costs and quality
adjustments.
During 2023, our sales were allocated on a competitive basis to leading industry participants, including traders and other
producers. We continued to deliver at both at well-head and at various points in the Colombian pipeline system and via
Ecuador for the Putumayo production.
Our sales strategy is aimed at securing the highest available pricing for our production while securing a reliable and safe
path to market. To that end, we focus on developing synergies and strategic partnerships with both clients and the national
transport systems, in order to obtain a reduction in costs and increased revenues by making use of the best alternatives
available. Such is the case of the implementation of an unloading facility at Jaguey Station in partnership with Oleoducto de
Los Llanos Orientales S.A. (ODL) in 2015. This unloading facility is located 42 km. away from the Llanos 34 Block and
allowed for reduced trucking distance and associated costs. Additionally, during 2019 we completed a project to connect the
Llanos 34 Block to the ODL pipeline via a flowline. In the third quarter of 2019, we started sending our
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Jacana production volumes via this flowline to the ODL pipeline, eliminating trucking for that portion of our production and
allowing further cost efficiencies and increased operational reliability. In November 2020, the flowline was converted into the
Oleoducto del Casanare (“ODCA”) receiving full authorization from the Ministry of Energy and Mines to operate as such,
determining the regulated tariff and allowing the transportation of third-party crudes. In 2020, we also inaugurated an
unloading facility in Jacana, allowing for volumes of other fields to be transported via the ODCA. At the end of 2020, we
connected the Tigana field to ODCA, further reducing transport of our volumes via truck. Since 2021, ODCA has been a
central piece of our crude transportation in Colombia, including volumes of Jacana, Tigana and other fields. In 2021, we also
entered into an agreement to connect the third party owned Cabrestero Block to ODCA, which allows us to transport third
party crude. The connection was completed during the first half of 2022, and we began to transport third-party crude oil
through the ODCA. In 2023, we reached an agreement with Ecopetrol to transport the royalties and economic rights paid in
kind of the Jacana, Tigana and Tua fields through ODCA, increasing third-party crudes transported through ODCA and
therefore, optimizing the use of the available capacity. In addition, we are developing a dilution project at Tigana Station with
our partner in the Llanos 34 Block, which will allow to increase the volume transported through ODCA, reducing
transportation costs.
In the case of the Platanillo Block in the Putumayo Basin, we gather the crude via truck and flowlines to pump it towards
Ecuador via the Oloeducto Binacional Amerisur (“OBA”). This pipeline is operated by us and our affiliates and connects us to
the Ecuadorian pipeline system via RODA allowing us to sell our production FOB in Esmeraldas port in Ecuador. We hold
transport contracts with RODA and SOTE for the transport, storage and loading of our crude in Ecuador.
If we were to lose any of our 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 in a very short period.
Ecuador
Ecuador has a well-developed crude oil market with broad access to international markets and an extensive pipeline
transportation system. Our oil production, which began in 2022, is transported through the Ecuadorian pipeline system, with
Esmeraldas as the delivery point, and 100% of our sales are exported on a competitive basis to industry leading participants
including traders, refineries, and other producers. The oil price is linked to Brent and adjusted by a differential that varies
month to month and resembles Oriente crude reference price.
Brazil
Our production in Brazil consists of natural gas, condensate and crude 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 low gas prices seen in the Brazilian market during 2023
have represented a risk in the commercialization of gas from Manatí. The contractually agreed price considers inflation but is
not affected by market conditions, which reduces the appetite of the client, who has access to more favorable conditions.
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. Considering this prerogative, in February
2023, we signed an agreement with DAX Oil Refino S.A., a local private refinery, for the selling of condensate for a one-year
term, with the possibility of an extension for the same period. Through this agreement, we increased our portfolio of clients
and improved our revenues. Both agreements were valid through December 31, 2023, and can be renewed upon an
amendment signed by the purchasers and the seller.
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Chile
Our customer base in Chile was limited in numbers and primarily consists of ENAP and Methanex. For the year ended
December 31, 2023, we sold 100% of our oil production in Chile to ENAP and 100% of our gas production to Methanex, with
sales to ENAP and Methanex accounting for 2% of our total revenues.
We had a long-lasting commercial relationship with ENAP and sold our crude to them for the past years. We had a sales
agreement with ENAP whereby ENAP had committed to purchase our oil production in the Fell Block in the amounts that we
produced, subject to the limitation of available storage capacity at the Gregorio Terminal. We delivered the oil we produced in
the Fell Block to ENAP at the Gregorio Terminal, where ENAP assumed responsibility for the oil transferred.
During 2023, we were able to renegotiate and renew the sales agreement with ENAP. The negotiation process was
developed from January to May, due to prolonged discussions on the fees related to mercury content. During the negotiation
timeframe, the contract for crude oil purchasing was suspended, affecting production of oil and gas in the Fell Block.
In March 2017, we executed a gas supply agreement with Methanex effective from May 1, 2017, to December 31, 2026.
Under the agreement, Methanex committed to purchase up to 400,000 SCM/d of gas produced by us. During 2022, we
executed an amendment to increase the purchase commitment up to the total gas produced by GeoPark in Chile.
We gathered the gas we produced in several wells through our own flow lines and injected it into several gas pipelines
owned by ENAP. The transportation of the gas we sold to Methanex through these pipelines was pursuant to a private contract
between Methanex and ENAP. We did not own any natural gas pipelines for the transportation of natural gas.
Corporate
GeoPark Limited, our holding company incorporated under the laws of Bermuda, has entered into a crude purchase
agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside our
Putumayo Basin production. Sales of this crude oil purchased from third parties accounted for 1% of our consolidated revenue
in 2023.
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 twenty
three blocks in Colombia. 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 33.1 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.
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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, ANH regulation 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. 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, production sharing agreements and concession agreements are subject to
early termination in certain circumstances.”
Eastern Llanos Basin:
Llanos 34 Block E&P contract. On March 13, 2009, the E&P contract was awarded to Unión Temporal Llanos 34,
currently integrated by GeoPark Colombia S.A.S. with 45%, and Verano Limited with 55% working interest. The Llanos 34
Block E&P contract provides a 24-year exploitation period for each production area, beginning on the date of a commercial
declaration. The exploitation period may be extended for periods of up to 10 years at a time if certain conditions are met and
subject to ANH approval. As of the date of this annual report there are production areas for the Max, Túa, Tarotaro, Tigana,
Jacana, Chachalaca, Tilo, Chiricoca, Jacamar and Guaco fields.
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. Additionally, we are required to pay a subsoil use fee to the ANH. The 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 E&P 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 33.1 to our Consolidated
Financial Statements.
Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block. Verano Energy is the operator of this block
and has an 87.5% working interest. Economic rights to the ANH are similar to those under the Llanos 34 Block.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block
association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico
Block. 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 Frontera, who subsequently assigned its participation interest to Cepsa Colombia S.A., who then assigned the
interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A.
Llanos 86, Llanos 87, Llanos 104, Llanos 123 and Llanos 124 Blocks. We and Hocol (a subsidiary of Ecopetrol), each
with fifty percent (50%) working interest, executed E&P contracts over these blocks in 2019, as a result of the Permanent
Competitive Process launched by ANH. We are the operator of these contracts that are in exploratory phase 1. In these E&P
contracts, we are required to pay subsurface rights to the ANH, calculated based on the total acreage of the blocks, or the
remaining area if in case of relinquishment had taken place. There is also an additional annual 25% markup of said subsurface
rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to legal
royalties, the ANH is entitled to receive a percentage of total production net of royalties, at the delivery point (multiplied by a
factor set in the contract and based on international oil prices). That percentage is 3% in the Llanos 87 E&P contract, 2% in
the Llanos 86 and Llanos 104 E&P contracts and 1% in the Llanos 123 and Llanos 124 E&P contracts. There is an additional
5-10% share payable to the ANH applicable upon extensions to the production period and
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when the accumulated gross aggregate production of the area of the contract exceeds 5 million barrels and the WTI exceeds a
defined price. ANH becomes entitled to an additional share on production in accordance with a formula set in the contract.
Llanos 94 Block. On July 24, 2019, the E&P contract was awarded to Parex Energy as a result of the Permanent
Competitive Process launched by ANH in 2019. We acquired a 50% working interest from Parex and obtained ANH’s
approval to such transfer in May 2020. This contract is in an extended exploratory phase 1 and due to the extension of the
exploratory period approved in 2023, the current phase 1 commitments consist of drilling one exploratory well before October
1, 2025. We are not interested in drilling such prospect and have agreed to transfer our 50% working interest to our partner.
Accordingly, on December 28, 2023, Parex requested ANH approval for such transfer and, once approval is obtained, we will
no longer be liable for the capital commitment in the block.
In the Llanos 94 E&P contract, we are required to pay subsurface rights to the ANH, calculated based on the total acreage
of the blocks, or the remaining area if relinquishment had taken place. There is also an additional annual 25% markup of said
subsurface rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to
legal royalties, the ANH is entitled to receive 2% of total production net of royalties, at the delivery point (multiplied by a
factor set in the contract and based on international oil prices). There is an additional 5-10% share payable to the ANH
applicable upon extensions to the production period and when the accumulated gross aggregate production of the area of the
contract exceeds 5 million barrels and the WTI exceeds a defined price. ANH becomes entitled to an additional share on
production in accordance with a formula set in the contract.
CPO-5 Block E&P contract. On December 26, 2008, the E&P contract was executed between ONGC Videsh, as operator
and the ANH as a result of the Competitive Process “Ronda Colombia 2008”. We hold a 30% working interest since the
acquisition of Amerisur. As of the date of this annual report, the contract is in phase 2 of the exploration period. There are two
commercial fields called Mariposa and Indico, and we also had successful drilling and putting into production exploration
wells in the fields called Flamenco, Halcon and Perico.
Pursuant to the CPO-5 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on
hydrocarbons produced in the CPO-5 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The 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 CPO-
5 Block E&P contract. The ANH also has an additional economic right equivalent to 23% of production, net of royalties. In
accordance with the CPO-5 Block E&P 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.
CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of
the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was
executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this
annual report, this contract is in exploratory phase 1.
Pursuant to CPO-4-1 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on
hydrocarbons produced in the CPO-4-1 Block. Additionally, we are required to pay a surface and subsoil usage fee to the
ANH. We are required to comply with the VEE (economic value for exclusivity) equivalent to the commitments for the
exploratory period; however, if we do not perform such commitments, the VEE amount calculated as provided in the CPO-4-1
E&P contract, must be paid to the ANH. The ANH also has an additional economic right equivalent to 1% of production, net
of royalties. In accordance with the CPO-4-1 Block E&P contract, when the accumulated production of the area of the
contract, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should
deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo Basin:
Coati Block E&P contract. We are the operator of and have a 100% working interest in the Coati Block. The Coati Block
has an evaluation area, declared in September 2006, by the former operator in the southern part of the Block for the Temblon
wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coati-1 well. Pursuant to the Coati
Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons
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produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The 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 Coati Block E&P
contract. In accordance with the Coati 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, we should deliver to ANH a share of
the production net of royalties in accordance with an established formula.
Mecaya Block E&P contract. We are the operator of and have a 50% working interest in the Mecaya Block. Sierracol
Energy is the owner of the remaining 50% working interest in the contract. As of the date of this annual report, the contract is
in unified phases 1 and 2 of the exploration period, and it is suspended due to Force Majeure Events (Prior Consultations).
Pursuant to the Mecaya Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on
hydrocarbons produced in the Mecaya Block. Additionally, we are required to pay a subsoil use fee to the ANH. The 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
Mecaya Block E&P contract. In accordance with the Mecaya 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.
Platanillo Block E&P contract. We are the operator of and have a 100% working interest in the Platanillo Block. On
September 11, 2009, we began commercial exploitation. Pursuant to the Platanillo Block E&P contract and applicable law, we
are required to pay a royalty to the ANH based on hydrocarbons produced in the Platanillo Block. Additionally, we are
required to pay a subsoil use fee to the ANH. The 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 Platanillo Block E&P contract. In accordance with the Platanillo
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.
Putumayo 8 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 8 Block.
Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the
exploration period. Pursuant to the Putumayo 8 Block E&P contract and applicable law, we are required to pay a royalty to the
ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The
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 Putumayo 8 Block E&P contract. The ANH also has an additional economic right equivalent to 2% of production, net of
royalties. In accordance with the Putumayo 8 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.
Putumayo 9 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 9 Block.
Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in
phase 1 of the exploration period, which is suspended since June 25, 2019, due to the occurrence of a Force Majeure event
(issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in
Puerto Guzmán Municipality). Pursuant to the Putumayo 9 Block E&P contract and applicable law, we are required to pay a
royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the
ANH. The 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 Putumayo 9 Block E&P contract. The ANH also has an additional economic right equivalent to 18% of
production, net of royalties. In accordance with the Putumayo 9 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.
Putumayo 14 Block E&P contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block.
On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer
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the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers, ANH
will proceed with the contract’s termination. As of the date of this annual report, the total investment needed to fulfill the
commitments has already been incurred and the ANH approval is pending.
Putumayo 36 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 36 Block.
Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, which is suspended since
April 1, 2020 due to the occurrence of a Force Majeure Event (issuance of the Municipal Agreement which prohibits the
execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). Pursuant to the Putumayo
36 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in
the block. Additionally, we are required to pay a subsoil use fee to the ANH. The 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 Putumayo 36 Block E&P
contract, and the payment of 25% of the Economic Right for the use of the subsoil for institutional strengthening and
Technology Transfer. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In
accordance with the Putumayo 36 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.
Tacacho and Terecay Blocks E&P contracts. We are the operator of and have a 50% working interest in the Tacacho and
Terecay Blocks. Sierracol Energy is the owner of the remaining 50% working interest in each E&P contract. The contracts are
in phase 1 of the exploration period, which are currently suspended due to the occurrence of force majeure events related with
social and public order conditions of the area. Pursuant to the Tacacho and Terecay Blocks E&P contracts and applicable law,
we are required to pay a royalty to the ANH based on hydrocarbons produced in the blocks. Additionally, we are required to
pay a subsoil use fee to the ANH. The 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 Tacacho and Terecay Blocks E&P contracts. In accordance with the Tacacho
and Terecay Blocks operation contracts, when the accumulated production of each field, including the royalties’ volume,
exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of
royalties in accordance with an established formula. On September 21, 2022, we submitted to the ANH requests for
termination of the E&P contracts and, in January 2024, we submitted additional third-party reports as supporting
documentation to such request. As of the date of this annual report, the requests are under review by the ANH.
Overriding Royalty Agreements
We are obligated to pay an overriding royalty of 4% and 2.5%, respectively, to the previous owners of the Llanos 34 and
CPO-5 Blocks, based on the production and sale of hydrocarbons discovered in the blocks. During 2023, the Group has
accrued US$27.5 million in relation to these overriding royalty agreements. Furthermore, there are overriding royalty
agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay
Blocks. Since they were exploratory blocks with no production during 2023, these agreements had no impact on our results.
Ecuador
Production sharing contracts
We entered into two production sharing contracts with the Ministry of Energy and Mines. While we are the operators in
the Espejo Block, Frontera operates the Perico Block. The production sharing contracts in Ecuador are generally divided into
two stages: (i) an exploration period of 4 years, which may be extended to 6 years; and (ii) a production period of 20 years.
The exploitation or production period commences upon Governmental approval of the exploitation and development plan of a
commercial field (although early production during the exploration period is allowed). The extension of the production period
requires entering into an amendment to the contract with the Government of Ecuador, which may imply revision of
contractual conditions.
In the Espejo and Perico production sharing contracts, production is measured and distributed among the contractor and
the Government at the delivery point where a production sharing formula is applied based on international oil prices of the
Oriente marker in the previous month and the offer made as base point in each tender. No further royalties apply. In
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addition, we are obliged to make a yearly payment of US$24,000 as compensation for the use of water and natural
construction materials, which increases to US$60,000 during the production stage. Furthermore, there is an institutional
development fee of US$100,000 payable every year.
Brazil
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 consists of one exploratory
period that begins on the date of execution of the concession agreement, which 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.
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
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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.
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’ 10% participation interest in the BCAM-40 Concession on
March 31, 2014.
Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements.
Under the Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements, the ANP is entitled to
a monthly royalty corresponding to up 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, Queiroz Galvão Perfurações (now Enauta) 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. Enauta, Gas Bridge Storage S.A.
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and GeoPark Brazil 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
Enauta, GeoPark Brazil, Gas Bridge Storage S.A. and Petrobras are party to a natural gas purchase agreement providing
for the sale of natural gas by Enauta, GeoPark Brazil and Gas Bridge Storage S.A. 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.
Chile
CEOPs
As of December 31, 2023, we had four CEOPs in effect with Chile, one for each of the blocks in which we operated,
which granted us the right to explore and exploit hydrocarbons in these blocks, determined our working interests in the blocks
and appointed the operator of the blocks. These CEOPs were divided into two phases: (1) an exploration phase, which was
divided into two or more exploration periods, and which began on the effectiveness date of the relevant CEOP, and (2) an
exploitation phase, which was determined on a per-field basis, commencing on the date we declared 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 had to declare a discovery of hydrocarbons to the Ministry of Energy. This was a unilateral declaration,
which granted us the right to test a field for a limited period of time for commercial viability. If the field proved commercially
viable, we would have to make a further unilateral declaration to the Ministry of Energy. In the exploration phase, we were
obligated to fulfill a minimum work commitment, which generally included 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
had relinquishment obligations at the end of each period in the exploration phase in respect of those areas in which we had not
made a declaration of discovery. We were also able to voluntarily relinquish areas in which we had not declared discoveries of
hydrocarbons at any time, at no cost to us. In the exploitation phase, we generally did not face formal work commitments,
other than the development plans we filed with the Chilean Ministry of Energy for each field declared to be commercially
viable.
Our CEOPs provided 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 considered 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 could not be modified without consent of the parties.
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. The Fell Block CEOP provided 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 production sold in the field, for production sold of
up to 5,000 bopd, ring fenced by field, and 97% of gas production sold in the field, for production sold
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of up to 882.9 mmcfpd. If we exceeded these levels of production sold, our monthly retribution from Chile would 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 sold
per field.
TDF Blocks CEOPs. In 2012, we signed 3 CEOPs, together with ENAP, for the Isla Norte, Campanario and Flamenco
Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region. Our working interest was 60% in Isla Norte and
50% in Campanario and Flamenco Blocks. The CEOPs had a term of 32 years, with an initial exploration phase which last for
up to 10 years, including a first exploration period of 3 years. The hydrocarbon discoveries opened up an exploitation phase
that lasts up to 25 years. We discovered hydrocarbon fields in the 3 blocks, starting in 2013 in the Flamenco Block, and in
2014 in both Campanario and Isla Norte Blocks. The CEOPs provided us with a right to receive a remuneration payable by
means of a fraction of the production sold, which in the TDF Blocks was 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 was less than 1.0, the remuneration was 95% of the hydrocarbons sold, either oil or gas.
If the recovery factor surpassed 1.0, a formula would apply reducing gradually the remuneration fraction to a minimum of
75% when the recovery factor was 2.5 times the total accumulated expenses.
Argentina
Overview of exploration permits
Our exploration permits granted 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 were made up of three subperiods, each
lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years.
We were bound to pursue specific minimum work or investment commitments during each of the subperiods of each
exploration permit. Such exploration works were valued in work units assigned to each particular type of work under the
applicable bidding conditions.
Work and investment programs for the permits were 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 were entitled to our proportionate share of the
hydrocarbons production lifted from each block. We paid 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 had no change of control provisions, though any assignment of these concessions was
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. Each of these permits or future concessions could be terminated for default in payment obligations
and/or breach of material statutory or regulatory obligations. We were subject to the obligation to relinquish at least 50% of
the acreage of each exploration permit at the end of each exploration subperiod. We might also voluntarily relinquish acreage
to the provincial authorities.
Our Argentine exploration permits were governed by the laws of Argentina and the resolution of any disputes must be
sought in the Mendoza Provincial Courts.
If and when we made a commercial discovery in one or more of our exploration permits, we would 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 would 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.
Additionally, oil and gas producers in Argentina must grant a privilege to the domestic market over the export market,
including hydrocarbon export restrictions, domestic price controls, export duties and domestic market supplier obligations.
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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 Colombia, Ecuador, Brazil, Chile and Argentina, local governments
grant such rights through E&P contracts or contracts of association, production sharing contracts, concession agreements,
CEOPs and exploitation concessions, respectively. See “Item 3. Key Information—D. Risk factors—Risks relating to the
countries in which we operate— Oil and natural gas companies in Colombia, Ecuador and Brazil operate and have a working
and/or economic interest over, yet 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 E&P contracts, contracts of association, production sharing contracts, concession agreements, CEOPs
and exploitation concessions 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, we allocate our sales on a competitive basis to industry leading participants including traders and other
producers. During 2023, the oil and gas production was sold to three clients that concentrated 96% of the Colombian
subsidiaries’ revenue. In Ecuador, 100% of our sales were exported on a competitive basis to industry leading participants
including traders and other producers. In Brazil, all our gas produced in Manati was sold to Petrobras. In Chile, our customers
were ENAP and Methanex. As of December 31, 2023, ENAP purchased all our Chilean oil and condensate production and
Methanex purchased all our natural gas production in Chile. We managed the counterparty credit risk associated to sales
contracts by limiting payment terms offered to minimize the exposure. For further information, please see Note 3 to our
Consolidated Financial Statements.
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.
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.
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.”
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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 corporate HSE commitment governs our actions, in accordance with the legal framework, industry best practices and
international standards in terms of socio-environmental, health and safety performance. We work closely with our suppliers
and contractors to transfer the best HSE practices throughout our value chain and extend our responsibility towards safety and
the environment, with binding contractual agreements, monthly safety and environmental performance evaluations, annual
compliance evaluations and the construction of capacities and competencies necessary to be in line with our health, safety, and
environmental commitment.
We have a health and safety management plan focused on hazard identification and evaluation, including systematic tools
implemented in all the operations involving both employees’ and contractors’ activities.
We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and
actions that ensure respect and protection of the environment in the territories where we operate.
In each of the countries where we operate, we ensure compliance with applicable health, safety and environmental
requirements. All our operations have the environmental licenses and permits required under the applicable legislation, which
are derived from the development of environmental studies with citizen participation for the definition of management
measures and impact mitigation.
In 2023, our Health and Safety Management System (HSMS) was certified under the ISO standard: 45001:2018,
including all Colombian operations. We also implemented our HSMS in our operations in other countries, such as Ecuador
and Chile, based on corporate commitment.
Our Environmental Management System (EMS), certified under the ISO standard: 14001:2015 for our operations in
Colombia, defines programs for the integral management of water resources; solid and liquid waste management; atmospheric
emissions and energy; biodiversity and ecosystem services and training and awareness regarding the protection of the
environment for employees and suppliers. In addition, it defines the roles and responsibilities of management regarding to the
performance of our environmental issues.
Although we do not have a certified EMS in countries such as Ecuador and Chile, we have implemented the main
programs contemplated by our corporate environmental commitment.
Our corporate environmental commitment is mainly based on the management of the following issues:
Integral water management
We recognize water as a strategic resource and axis of sustainable development in the territories. For this reason, we
implement initiatives and strategies for saving and efficiently using the resource, and we focus our efforts on seeking
efficiencies in the operation, on reusing water and on reducing environmental impacts and conflicts associated with water
management.
We have an integral water management program that allows us to monitor the information needed to control its use and
consumption, ensure compliance with our environmental permits and take the necessary measures to control the different
activities where we use water.
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All the waste waters generated in our operations is treated and disposed of in accordance with the environmental licenses.
In 2023, we did not use natural surface water sources in our permanent operations in the Llanos 34, Platanillo and Fell
Blocks and we did not carry out any type of wastewater discharge into surface waterbodies, to avoid any potential conflict
with the other users of this resource due to its quality or quantity. We are committed to eliminate any natural surface
waterbody withdrawal in all our permanent operations (fields under development) by 2025, as well as continuing to maintain
zero (0) direct discharges into surface water sources. We are making advancements to define the corporate water footprint
under a recognized standard.
Biodiversity
Through our management, we articulate our efforts to avoid, mitigate and eliminate any impact that may represent a
material risk to the biodiversity of the environment where we operate, applying the mitigation hierarchy to protect nature and
use it sustainably. We recognize the importance of biodiversity in the areas of our interest since the planning stage of our
projects. We are committed to avoiding operations in legally protected areas and taking into account biodiversity value and
ecosystem services as a driver to design, planning and execute our projects. Ecosystem services are the services that nature
provides to the people, such as fresh water, food, medicines, regulation of floods and soil erosion and carbon dioxide capture.
In addition, we compensate for our residual impact on biodiversity and, we participate and promote programs related to
the rehabilitation, restoration, and conservation of high value ecosystems through strategic alliances for the conservation of
biodiversity, strengthening social and cultural connections with nature, and promoting knowledge of the natural wealth of the
countries we operate in.
Some of the projects related to biodiversity that contribute to the reduction of biodiversity loss, the promotion of
conservation of the environment and the stability of ecosystems during 2023, included:
●
The donation of 1,600 hectares of land to the Manacacias National Park to be declared by the Colombian
government as part of the biodiversity offset measurements of our activities in Llanos 34 block.
● We continue being part of the Putumayo Regional Agreement for Biodiversity and Development, which
integrates efforts by the private sector and national and regional entities to preserve the biodiversity and
connectivity of this region of the Amazon. As part of this agreement, in 2023, we made an alliance with the
Sinch Amazon Institute of Scientific Research, Wildlife Conservation Society - WCS and other Colombian
O&G Company, to implement the project call “Ríos diversos” in order to characterize the water’s biological
quality in the Putumayo watershed and study its relationship with the local communities.
●
In Ecuador, in the canton of Shushufindi, province of Sucumbios, we developed, in coordination with the local
and provincial government, a project for the recovery of plant cover in areas of watercourses and estuaries with
an ecosystem, landscape and watershed protection approach, in order to improve the natural balance and the
biodiversity of the territory.
● We actively participated in initiatives led by national and local governments in the countries where we operate
focused on reducing deforestation and promote the restauration of disturbed areas. In 2023, we contributed by
planting or donating more than 40,000 trees, as part of our environmental obligations and voluntary initiatives.
Climate change
Our response to climate change and our contribution to achieve the sustainable development goal number 13 of the
United Nations is part of our plan to minimize Greenhouse Gas (GHG) emissions announced by us in November 2021,
following approval of our board of directors:
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● 35-40% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2025;
● 40-60% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2030; and
● net zero Scope 1 and 2 emissions by or before 2050.
All our abovementioned goals are defined against a 2020 baseline.
These goals take into account the execution of some operational and environmental projects. The following projects are
the most relevant achieved during 2023 in Colombia:
● Both the interconnection of the core Llanos 34 Block to Colombia’s national grid and the dedicated 10MW solar
photovoltaic plant, although completed during 2022, showed their full impact during 2023; and
● the construction of permanent flare systems in our main fields in Colombia in compliance with current
regulations.
Medium-term actions include energy efficiency, small-scale renewable projects, management of methane emissions, and
potential participation in carbon markets, among others.
Longer-term actions may include carbon capture, use and storage projects, reforestation and afforestation initiatives.
As of the date of this annual report, we have other ongoing environmental initiatives related to climate adaptation, such
as, in Colombia, we continue the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental
Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía,
in the hydrographic zone of the Meta River, which will contribute to improve water management, comprehensive risk
management and climate change adaptation.
Integral waste management and circular economy
Regarding the proper management of solid waste generated by our activities, we focus our management on the principles
of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with
applicable regulations. In 2023, we continue strengthening our circular economy strategic plan and the roadmap for its
implementation. As part of this plan, we are carrying out more than 8 circular initiatives as part of the three (3) circularity
models that we have prioritized: 1. Water management. 2. Waste management. 3. Use of GHG.
Spill Management
In 2023, we had zero recordable hydrocarbon spills (>=1Bbl uncontained) in our operations.
Our HSE Plan
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 SPEED philosophy and our HSE Plan have been developed with reference to ISO
14001 for environmental management issues, ISO 45000 for occupational health and safety management issues, SA 8000 for
social accountability and workers’ rights issues and general guidelines from international entities such as IOGP, IPIECA,
IADC and ARPEL.
Our HSE Policy
Our policy seeks to meet or exceed safety and 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
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management, while safeguarding the well-being of all people. Within our SPEED philosophy we have a team that is
exclusively focused on securing the environmental authorizations and permits for the projects we undertake and promoting the
best health and safety practices. This professional and trained team, specialized in environmental issues, is also responsible for
the achievement of the health, safety and 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
health, safety and environmental management.
Our health and safety practices and outcomes
We continue to improve and update management tools to strengthen our health and safety policy. We have implemented
world-class programs focused on analyzing, assessing, and controlling hazards that may cause injury or illness to our
employees, contractors, and visitors. Our main occupational health and safety programs are: the proactive observation
program (POP), the authority to stop an activity (ADA), the safety operational standard (SOS), the incident reporting and
investigation (IRIS), the road transportation safety (RTS), and the business continuity master plan (PMCN).
In 2023, we reached several significant milestones, among which the following stand out:
● Our assets in Putumayo (Colombia) and Ecuador, which maintained a constant operation throughout 2023, had no
recordable people incidents.
● Record of hours worked, and kilometers travelled, 20% and 35% higher than 2022, respectively.
● Total recordable injury rate (TRIR) and recordable vehicular incidents rate (MVC) goals achieved.
● ISO 45001 certification.
As of December 31, 2023, and for the last twelve months, our HS indicators were the following:
● People injury. Indicators calculated per 1,000,000 hours worked (for both employees and contractors):
● Lost time injury rate (LTIR) of 0.48.
● Total recordable incident rate (TRIR) of 0.67.
● One fatal incident resulting from a vehicular accident involving one of our contractors.
● Vehicle incidents, calculated per 1,000,000 kilometers travelled:
● Recordable vehicular incidents rate (MVC) of 0.12.
The fatal incident reported above was the result of a vehicular accident in the Llanos 34 Block. Both the contractor and
the Company conducted internal investigations and determined the incident was accidental in nature. Furthermore, with the
intent of reinforcing safety in our operations, we carried out a third-party peer review of our risk management system to
enhance our action plans in response to potential occurrence of similar events.
In 2023, we performed a third-party health and safety management system peer review, including more than 1,300 survey
participants, 25 interviews / focus groups and documents review. As a result, we plan to implement a workplan focused on
leadership, operative discipline, and contractor management.
Certain Bermuda law considerations
We have been designated by the Bermuda Monetary Authority 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
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no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to
pay dividends to United States residents who are holders of our common shares.
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,
cyber security, 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.”
Industry and regulatory framework
Colombia
Regulation of the oil and gas industry
The ANH is responsible for managing all exploration acreage not subject to previously existing association contracts with
Ecopetrol. Two decades ago, the ANH began offering all undeveloped and unlicensed exploration areas in the country under
concession-fashion Exploration and Production Contracts (“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 regime for ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. The Agreement 004 of
2012 regulates E&P contracts entered into from May 4, 2012, and onwards. E&P contracts signed before that date are still
regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the ANH implemented transitory measures through
Agreements 002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which replaced Agreement
004 of 2012 and transitory measures adopted in 2014 and 2015. Agreement 002 of 2017 established rules for granting
hydrocarbon areas and adopted criteria for the exploration and exploitation of hydrocarbons owned by Colombia, including
the selection of contractors, and management, execution, termination, liquidation, monitoring, control, and supervision of
corresponding contracts. Agreement 002 of 2017 (compiled by Acuerdo 009 of 2021) regulates contracts entered into from
May 18, 2017, and onwards. E&P contracts entered into before that date are still regulated by the agreements under which
they were executed. Since 2004, the ANH has promoted several bidding processes resulting in various E&P contracts.
In 2020, and due to COVID-19 pandemic and the then-current oil low price scenario, the ANH issued Agreement 002 of
2020 with transitory relief measures such as term extensions for the exploratory phases, reduction of the amounts of the
guarantees, among other measures. All these measures are subject to the accomplishment of certain conditions, some of which
are related to the average oil price for the previous months. In 2021, ANH issued Agreement 010 of 2021 to enable the
execution of pending investments in any free area on the map of available areas published by ANH. This agreement has
enabled companies with E&P contracts with pending obligations (investments) to execute them in other areas promoting
exploration activities in Colombia whilst helping companies comply with contractual commitments. In 2022, ANH issued
Agreement 01, 2022 to regulate termination requests of E&P contracts under specific conditions such as being suspended for
at least 24 consecutive months. This agreement enables companies to request termination of E&P contracts which appear to be
inexecutable due to external factors out of a company’s control.
In September 2023, the ANH issued Agreement 06, 2023, with the purpose of promoting exploration by granting
extensions of exploratory and evaluation periods and the possibility for contractors to maintain areas for a longer period of
time in exchange for additional exploratory commitments in the areas.
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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 creating national energy policy
and 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 should be met 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 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, which restructured the
hydrocarbons sector, but all agreements entered into by Ecopetrol prior to 2003 with other oil companies are still regulated by
Decree 2310 of 1974. By Decree Law 1760 of 2003, Ecopetrol was spun off and the ANH was created. One of the main
purposes of this decree was to treat Ecopetrol as another oil and gas company in the market and to transfer regulatory
functions to the ANH as administrator of the nation’s hydrocarbons. This enabled Ecopetrol to differentiate its role and avoid
it being a party and judge to contractual matters.
Resolution 18-1495 of 2009, modified by Resolution 40048 of 2015, establishes a series of regulations regarding
hydrocarbon exploration and exploitation. In the E&P contracts, operators are afforded access to blocks by committing to
perform an exploratory 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 to be granted with a block, applicable royalties and revenue taxes. 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 by executing seismic and /or drilling stratigraphic wells and to propose
work commitments on those areas, and have a preemptive right to enter into an E&P contract (Right to convert the TEA
contract 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. Under a TEA, the contractor commits to exclusively perform the
committed exploration activities.
Pursuant to Colombian law, oil companies are obliged to pay royalties (a percentage of their production) to the ANH in
kind or in money as per ANH’s instruction and pursuant to the E&P contracts. Companies must also pay the ANH an
economic right called participating interest in the production, commonly known as “X factor” among other economic rights
established in the E&P contracts (i.e. high price provision, technology transfer, use of the subsurface). Producing fields pay
royalties in accordance with the applicable law at the time of the discovery. Under the E&P contracts, ANH contractors also
undertake obligations in favor of the communities located in the area of influence of the oil & gas projects, called “Proyectos
en Beneficio de las Comunidades” or (PBC).
In 2022, ANH launched Ronda Colombia 2021 with an addition to the terms of reference to include the Exclusivity
Economic Value (EEV). The EEV includes both the minimum amount required by the ANH and the additional amount
eventually included in the proposal, and which should be offered by the initial offers and counteroffers to surpass the initial
proposal and equalize or exceed the most favorable counteroffer presented in each round. EEV is represented in the number of
exploratory wells offered by a company to be drilled during the E&P contract’s exploratory phase of six years. The companies
should offer at least 1 EEV (minimum accepted by ANH) and grant a stand-by letter of credit for 100% of the estimated value
of the well as per ANH’s reference values. In the event the company does not comply with the offered EEV, the letter of credit
will be enforced by ANH. ANH granted 30 areas in Ronda Colombia 2021 in which we did not participate. However, Parex
transferred to us a 50% non-operated working interest in the CPO4-1 Exploration and Production Contract, which was granted
to it under Ronda Colombia 2021.
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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 foreign exchange
system in Colombia. Generally, national taxes under the general tax statute apply to all taxpayers, regardless of industry.
The latest tax reform was enacted in December 2022, including modifications to the corporate income tax rate and the tax
treatment of royalties, in-kind and in cash. However, in November 2023, the Constitutional Court ruled that the modification
that prohibited the deduction of royalties is unconstitutional, and such deductions are allowed as was the case until 2022. See
Note 16 to our Consolidated Financial Statements.
The main taxes currently in effect are the income tax (35%, plus a surtax for companies developing crude oil extractive
activities from 2023 onwards, ranging between 0% and 15%, depending on the Brent oil price level), capital gains tax (15%),
sales or value added tax (19%), and the tax on financial transactions (0.4%).
Additional regional taxes also apply with some special rules for the companies belonging to the oil and gas industry.
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 1/2018 of the board of the Colombian Central Bank, or the Exchange Statute, and its
amendments contain provisions governing exchange operations. Articles 94 to 97 of Resolution 1 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 and Ministry of
Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 1 and may not be able to
access the special exchange regime for a period of 10 years.
Ecuador
Regulatory framework
Petroleum Ownership and Regulation
Oil, gas, minerals and natural resources underground belong to the Republic of Ecuador, in accordance with the
Ecuadorian Constitution. This is a primary concept in both the Constitu tion and the law. However, the State can allow private
invest ment to explore and produce hydrocarbons under different types of contracts as provided under the law.
The Ministry of Energy and Non-Renewable Natural Resources (“Ministry of Energy”) regulates and oversees all
hydrocarbon-re lated activities in the country, including exploration, produc tion, transportation, refining and marketing. The
Ministry of Energy has absorbed the functions and duties of the Secretariat of Hydrocarbons and, through the Vice-Ministry of
Hydrocarbons, oversees awarding, executing and monitoring contracts with private companies for the explo ration and
production of hydrocarbons. On the other hand, the Agency for Regulation and Control of Energy and Non-Renewable
Natural Resources (“ARCERNNR” for its Spanish acronym) has the legal duty to oversee, audit, collect levies and duties on
operations, and conduct accounting control of all upstream and downstream hydrocarbon operations.
The Ministry of the Environment, Water and Ecological Transition of Ecuador (“MAATE” for its Spanish acronym) has
the legal competence for granting environmental licenses for all oil and gas ac tivities and to ensure such operations are
conducted in compliance with environmental laws and regulations. The MAATE is independent from the Ministry of Energy.
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Petroleum Laws and Regulations
The Ecuadorian Constitution contains the main provisions, which stipulate that all hydrocarbons belong to the State of
Ecuador, that the national oil company is EP PETROECUADOR has preferential rights for oil ex ploration, production,
transportation and sale, and that, in case a contract is executed with a private oil company, the State’s benefit must be more
than that of the private company. The State’s benefit is understood as all taxes, production shar ing and other economic benefits
the State receives from oil production, while the company’s benefit is understood as all proceeds received from payment for
the service of producing oil, or from the sales of its share of oil, less all amortization of investments, costs and taxes paid by
the company.
The Hydrocarbons Law is the main body of law below the Ecuadorian Constitution and regulates the different types of
contracts the government can enter into with international oil com panies, as well as the rights, obligations and penalties for
private companies. The main contracts that have been imple mented in Ecuador from time to time are service contracts and
fairly recently the production-sharing contracts (“PSC”). Under a service contract, the State of Ecuador pays a contractually
agreed tariff per barrel. Under a PSC, the investing company receives a share of the oil produced which it can freely trade.
There are several regulations ranking below the Hydrocar bons Law that set further rules for all activities, including the
regulation of hydrocarbon operations and special local rules on the accounting principles for each type of contract.
In addition to all the other generally applicable laws of the country, the Environmental Law, Labor Law (including local
content in hiring of personnel) and Tax Law should be carefully considered.
Background for Contract types for Private Investment in Petroleum
During almost 50 years, Ecuador has been producing oil, through two types of contracts: production-sharing contracts and
service con tracts. Traditionally, the government has imposed service contracts when the price of oil was high and production-
sharing contracts when the price of oil was low. In 2010, a legal reform required all oil companies that were operating under
the umbrella of production-sharing contracts to transform their con tracts into service contracts.
Service contracts can be executed by the Ministry of Hydrocarbons for exploration blocks or for fields already in
production (followed a 2021 reform to the Law of Hydrocarbons). In both cases, the con tracting company receives a pre-
agreed tariff that is usually negotiated considering the amount of the investment, exist ing reserves, production cost and an
estimated reasonable profit for the company.
In July 2018, Executive Decree No. 449 reinstated the production-sharing type of contracts locally referred to as
Participation Contracts. In 2019, the Ministry of Energy executed several Participation Contracts for exploration and
exploitation of hydrocarbons.
The contract term for a production-sharing contract is usually four years for exploration, ex tendable for two additional
years, and 20 years for produc tion, subject to an extension if reserves have been added and new investments are committed.
As of the date of this annual report, we hold two production-sharing contracts with a 50% working interest in consortium with
Frontera Energy (Espejo Block, operated, and non-operated Perico Block), which were awarded by the Ministry of Energy
during the First Intracampos Bidding Round in April 2019.
Taxation
The guiding principle is that the government’s share will always be higher than the contracting company’s share. If the
contracting company’s share is higher than 51%, it triggers a sovereignty margin adjustment in favor of the government.
Under a production-sharing contract, the government’s share is composed of the sales price or the reference price of the
share of oil assigned to the government as per the contract, plus all taxes and contributions paid by the company. In this type
of contract, the contracting company’s share is the higher of the sales price and the reference price of the
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company’s oil, less all amortization of investments, operating costs, trans portation costs up to the port of Balao on the Pacific
Coast and all taxes and contributions paid pursuant to the law and the contract.
Basically, the taxes are:
● employee profit-sharing (15 per cent of net profits before income tax);
● 25 per cent income tax rate;
● 12 per cent value-added tax;
● money outflow tax, applied to remittances abroad, except when it comes to distribution of profits, with the following
rates: 4% until January 31, 2023, 3.75% from February 1, 2023, to June 30, 2023, 3.5% from July 1, 2023, to
December 30, 2023 and 2% from December 31, 2023 onwards;
● municipal taxes; and
● other fees and contributions charged by petroleum oversight authorities.
Production Risk
For any type of contract to be entered into in Ecuador, the investing company has to take on all exploration and pro ‐
duction risks and investments, as well as environmental responsibilities in accordance with its corresponding envi ronmental
obligations.
Furthermore, the investing company must strictly abide by all employment laws, in terms of legal requirements
concerning the maximum number of foreign employees. Some contracts have allowed for arbitration as a dispute resolution
mechanism; however, certain matters, such as taxes, cannot be submitted to arbitration. This is also true for certain termination
provisions in the event of the investing company breaching the law (such as transfer of rights without consent). The reform to
the Law of Hydrocarbons enacted in 2021 allows the entry into investment treaties with the Government of Ecuador, allowing
to freeze tax incentives in consideration for investment commitments and expanding local employment.
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.
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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 17 bidding rounds for
exploration concessions from 1999 through 2021, four open acreage bid rounds, 6th Production Sharing Bidding Round and
two Transfer of Right Surplus Bidding Round.
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.
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.
State VAT (ICMS)
ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based on the sale price, including the ICMS
itself.
For intrastate transactions (carried out by a seller and a buyer located in the same Brazilian state) or imports, the ICMS
rate is determined by the legislation of the state where the sale is made and generally varies from 17% to 20%. Interstate
transactions (carried out between a seller and buyer located in different Brazilian states), in turn, are subject to reduced rates of
4% (if the products are imported and not submitted to a manufacturing process or, in case of further manufacturing, if the
resulting product has a minimum imported content of 40%), 7% or 12%, depending on the states involved. One exception is
that, due to the immunity established by the Brazilian Federal Constitution, ICMS is not due on interstate crude oil
transactions when destined to industrialization and commercialization. On the other hand, in case of consumables
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or fixed assets, the buyer must pay to the state where the buyer is located, the ICMS DIFAL, which is calculated based on the
difference between the interstate rate and the buyer’s own internal ICMS rate.
ICMS is calculated under the noncumulative regime, and therefore some input transactions could result in tax credits (for
example the acquisition of inputs and fixed assets directly used in the company’s activity).
Social contribution taxes on gross revenue (PIS and COFINS)
PIS and COFINS are social contribution taxes charged on gross revenues earned by a Brazilian Federal Revenue
noncumulative regime of calculation.
Under the noncumulative regime, PIS and COFINS are generally charged at a combined nominal rate of 9.25% (1.65%
PIS and 7.6% COFINS) on national revenues earned by a legal entity. In that case, certain business costs result in tax credits to
offset PIS and COFINS liabilities (e.g., input and services acquisitions, expenses of depreciation and amortization of
machinery, equipment and other fixed assets acquired to be directly used in the company’s activities). PIS and COFINS paid
upon the importation of certain inputs, assets and services contracted that are destined to the company’s activity are also
creditable. Although upstream industries are generally subject to this regime, it is not clear yet when this benefit is applied
according to the stage of the field, (exploration or production).
Since July 1, 2015, taxpayers subject to the noncumulative regime must calculate PIS and COFINS over certain financial
revenues, applying rates of 0.65% and 4%, respectively.
Federal Industrialization VAT (IPI) and Municipality VAT (ISS)
IPI is a non-cumulative tax and may be due on goods acquisitions by importation or national transactions. The IPI rate
will be applied depending on the NCM classification of the product according to TIPI (Table of IPI). On the acquisition of
local goods subject to IPI, such tax is included in the price of the good. Considering that O&G activity (upstream) is not
subject to IPI taxation, the amount of the tax cannot be considered as a credit (even though IPI is under the non-cumulative
regime applicable for IPI’s taxpayers), which means that this will be a cost for the legal entity acquirer. In relation to the
importation, the importer of record will be considered as the taxpayer and will be obliged to pay the IPI due on the transaction.
For the same aforementioned reasons for the O&G companies (upstream), this will be considered as cost when the importation
is subject to IPI.
ISS is a cumulative tax which is due on provided services and imported services. Usually, regarding local transactions,
such tax is included in the price of the service charged by the service provider. In relation to the import of service, the
Brazilian entity contractor is responsible for the payment of the ISS, which means that, depending on contractual arrangement,
the tax burden may be supported by the Brazilian contractor or the foreign service provider.
ISS tax rate may vary from 2% to 5% and will depend on the nature of service, as well as where the service provider is
located (in general, some exceptions may apply).
Additionally, in 2018, GeoPark Brazil was granted a tax benefit issued by SUDENE (Northeastern Development
Superintendence), by means of the Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by 75% the
Income Tax and Additions, calculated over the company exploration profits, based on Article 1 of the Provisory Measure
2,199-14 of August 24, 2001, in accordance with the requirements established by the Decree 6,539 of August 18, 2008.
The benefit will be valid for 10 years, starting from January 1, 2018, under the condition of modernizing the entire project
on the SUDENE operating area, observing all provided legal conditions and requirements that includes compliance with labor
and social law and with all environmental protection and control regulations, annual submission of a declaration of income
and a restriction to the distribution to partners or shareholders of the tax amount which is not paid due to the tax exemption.
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The noncompliance with the requirements provided constitutes a default of the beneficiary company in respect to
SUDENE and shall be subject to the applicable penalties.
Chile
Regulation of the oil and gas industry
Under article 24 of 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 (administrative contract for the provision of
oilfield services) 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 are 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 landowners 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.
Taxation
Under the Chilean tax regime, hydrocarbon exploitation benefits from the general income tax legislation are established at
the time of the execution of each CEOP for the exploitation of each block. Thus, new tax reforms do not affect the current
taxation for our subsidiaries in Chile.
Further, transactions between foreign related parties and our local subsidiaries are compliant with several tax reporting
provisions set forth by the Chilean legislation for transfer pricing and indirect transfer tax purposes, at the same time that
benefits derived from double taxation agreements entered into by Chile and the relevant countries are applied as well.
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Argentina
Regulatory framework
The Hydrocarbon Law No. 17,319 enacted in 1967 continues in force until today, subject to amendments introduced by
the Laws No. 24,145, 26,197 and 27,007. A bill to amend the Hydrocarbons Law 17,319 was presented by the National
Executive Branch to the National Congress in December 2023 and continues under study as of March 2024.
The Hydrocarbon Law No. 17,319 provided for the existence of a state-owned oil & gas company (originally, YPF) for
whom private companies initially served as service contractors or joint venture partners. But it also provided for a concession
& royalty system which became the prevailing contractual granting instrument after the deregulation of petroleum activities
introduced by Decrees No. 1055/89, 1212/89 and 1589/89 (the “Petroleum Deregulation Decrees”) and the YPF Privatization
Law 24,145 enacted in 1992.
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty Law 26,741 which (i) impaired the
Deregulation Decrees; (ii) declared that achieving self-sufficiency in the supply of hydrocarbons, shall be a national public
interest and a priority for Argentina; and (iii) expropriated 51% of the share capital of YPF then owned by the Spanish
company Repsol.
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.
Hydrocarbon Exports and Self-Sufficiency
Achieving self-sufficiency has been an energy policy goal from the early days of the industry. Supply privileges favoring
the domestic market over the export market, including hydrocarbon export restrictions, domestic price controls, price
subsidies, export duties and domestic market supply obligations have been implemented several times throughout Argentina´s
history.
Hydrocarbon Exploitation Concessions Terms
With regards to concessions, three types of exploitation concessions are provided: (i) 25-years conventional concessions;
(ii) 35-years unconventional hydrocarbon concessions and (iii) 30-years offshore concessions.
With regards to royalties, the standard royalty rate is 12%, but incremental 3% rates are provided to apply when a
concession holder elects to renew an ongoing concession at the end of its term, subject to a cap of 18%. The payment of an
extension bonus to the government is also provided for a maximum amount equal to 2% of the remaining proven reserves at
the end of effective term of the concession valued at the average basin price applicable to the respective hydrocarbons during
the immediate past 2 years.
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. Effective February 8, 2019, to promote
transportation capacity expansions, Decree 115/2019 allowed interested shippers to reserve transportation capacity in new or
expanded pipelines through freely negotiated capacity reservation agreements.
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Taxation
Exploitation concessionaires are subject to the general federal and provincial tax regime. The most relevant federal taxes
are the income tax (35%) and the value-added tax (21%). The most relevant provincial taxes are the turnover tax (3% on
average) and stamp tax. Corporate income tax rate may range from 25% to 35% on bands of income that can be adjusted
annually.
Foreign Exchange Restrictions
Since September 1, 2019, wide foreign exchange restrictions were re-established in Argentina. Different promotional
investment regimes (such as National Decree 929/2013 and National Decree 277/2022) were with a view to lessening such
restrictions on new hydrocarbon investments projects. But foreign exchange restrictions continue to limit remittances of
dividends, financial and commercial obligations with foreign creditors.
Environmental
Hydrocarbon operations are subject to concurrent national and provincial environmental statutes and regulations, and to
the concurrent jurisdiction of national and provincial environmental and hydrocarbon enforcement authorities. The different
hydrocarbon producing provincial states have enacted and enforce comprehensive environmental decommissioning,
restoration and remediation frameworks.
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 21 (“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.
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.
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:
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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, 2023, we made total capital expenditures of US$199.0 million (US$178.1 million and
US$20.9 million in Colombia and Ecuador, respectively), consisting of US$73.2 million related to exploration.
Oil prices have been volatile, particularly since the start of the COVID-19 pandemic and the armed conflict in Ukraine. In
preparation for continued volatility, we have developed multiple scenarios for our 2024 capital expenditure program. See
“Item 4. Information on the Company—B. Business Overview—2024 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. 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 our 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. The price realized for the oil we produce is generally linked to Brent. The price realized for the
natural gas we produced in Chile was 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. For example, during the four-year period from March 1, 2020, to
February 29, 2024, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel.
We seek to partially mitigate our exposure to crude oil price volatility using derivatives by hedging a portion of our
production for a limited period going forward. We use a combination of options to manage our production’s exposure to
commodity price risk, which considers forecasted production and budget price levels, among other factors. For further
information related to Commodity Risk Management Contracts, please see Note 8 to our Consolidated Financial Statements.
Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price
is linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude
reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin
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that is transported through Ecuador. In both basins, the reference price is then adjusted for certain marketing and quality
discounts based on, among other things, API, viscosity, sulphur content, delivery point and transport costs.
In Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles the
Oriente crude reference price.
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) (the “IGPM”).
In Chile, the price of oil we sold to ENAP was based on Dated Brent minus certain marketing and quality discounts such
as, API, sulphur content and others. We had a long-term gas supply contract with Methanex. The price of the gas sold under
this contract was determined by a formula that considered a basket of international methanol prices, including US and
European price indices.
If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant,
considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$42.4
million (US$47.3 million in 2022).
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 facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees,
chemical analysis, royalties, economic rights, and consumables, among others. Our production costs may vary as a
consequence of the increase or decrease of commodity prices and other factors, such as the increase in energy costs occurred
in 2023 due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric
power. We have historically not hedged our costs to protect against fluctuations.
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.”
Production levels
Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and 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 licensed 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 licensed areas may fluctuate or increase significantly, and we may not be able to meet our
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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 E&P contracts, production sharing agreements 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.”
Acquisitions
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. We generally incorporate our acquired business
into our results of operations at or around the date of closing.
On January 16, 2020, we acquired the 100% share capital of Amerisur. Considering that Amerisur issued financial
information monthly, we considered the identified assets and liabilities as of December 31, 2019. If the purchase price
allocation exercise had been carried out as of January 16, 2020, it would not have deferred significantly.
Functional and presentational currency
Our Consolidated Financial Statements are presented in US$, which is our presentation 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-
Ecuadorian, non-Brazilian, non-Chilean and non-Argentine operations, primarily consisting of our corporate head office
operations.
As of December 31, 2023, we divided our business into five geographical segments—Colombia, Ecuador, Brazil, Chile
and Argentina—that corresponded to our principal jurisdictions of operation. Activities not falling into these five 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 consolidated 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 from the sale of crude oil and
gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically
transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s
performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent
considered to be a separate performance obligation under the contractual arrangements in place.
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Commodity risk management contracts
Includes realized and unrealized gains and losses arising from commodity risk management contracts.
The derivatives that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were accounted
for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were recognized
immediately as gains or losses in the results of the periods in which they occur as part of the Commodity risk management
contracts line item in the Consolidated Statement of Income.
The derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, and onwards are
designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are
recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion, if any, is recognized
immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in Other Reserves is
reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows
affect profit or loss as part of the Revenue line item in the Consolidated Statement of Income.
Production and operating costs
Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries
incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, royalties and
economic rights in cash are also included within this account. For a description of our production and operating costs, see “—
Factors affecting our results of operations.”
Depreciation
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 (the “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.
Geological and geophysical expenses
Geological and geophysical expenses are recognized on the accrual basis of accounting and 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.
Administrative expenses
Administrative expenses are recognized on the accrual basis of accounting and 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.
Our administrative expenses for the year ended December 31, 2023, decreased by US$6.1 million, or 12%, compared to
the year ended December 31, 2022, mainly due to higher overhead related to joint operations, and a one-time share-based
payment made to the Group´s former CEO in 2022, as part of his transition agreement described in “Item 6. Directors, Senior
Management and Employees – B. Compensation – CEO Transition Agreement.”
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Selling expenses
Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs
and selling taxes.
Our selling expenses for the year ended December 31, 2023, increased by US$5.1 million, or 64%, compared to the year
ended December 31, 2022, mainly due to deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the
wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points
are recognized as selling expenses.
Write-off of unsuccessful exploration efforts
Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or
charged to expense in the period in which the determination is made, depending on whether they have discovered reserves or
not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated
that the carrying value of the investment is recoverable.
During 2023, we recognized write-off of unsuccessful exploration efforts of US$29.6 million (US$25.8 million in 2022).
See Note 20 to our Consolidated Financial Statements.
Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject
to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that
the carrying amount may not be recoverable.
An impairment loss is recognized for the 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 2023, we recognized a net impairment loss of US$13.3 million in the Fell Block due to the known selling price of
the related net assets in the context of the divestment transaction of the Chilean business. See Note 36.1 in our Consolidated
Financial Statements. During 2022, no impairment losses were recognized or reversed.
Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and
liabilities, and foreign exchange gains and losses.
Recent accounting pronouncements
See Note 2.1.1 to our Consolidated Financial Statements.
Results of operations
The following discussion is of certain financial and operating data for the periods indicated. You should read this
discussion in conjunction with our Consolidated Financial Statements and the accompanying notes.
In preparation for continued volatility, we have developed multiple scenarios for our 2024 capital expenditure program.
See “Item 4. Information on the Company –B. Business Overview—2024 Strategy and Outlook.”
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Year ended December 31, 2023, compared to year ended December 31, 2022
The following table summarizes certain of our financial and operating data for the years ended December 31, 2023 and
2022.
For the year ended December 31,
% Change from
prior year
(in thousands of US$, except for percentages)
2023
2022
Revenue
Sale of crude oil
Sale of purchased crude oil
Sale of gas
Commodity risk management contracts designated as cash flow hedges
Revenue
Commodity risk management contracts
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful exploration efforts
Impairment loss recognized for non-financial assets
Other (expenses) income
Operating profit
Financial expenses
Financial income
Foreign exchange (loss) gain
Profit before income tax
Income tax expense
Profit for the year
Net production volumes
Oil (mbbl)(2)
Gas (mcf)(3)
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$)
Operating cost
Royalties and economic rights in cash
Production costs(1)
Geological and geophysical expenses
Administrative expenses
Selling expenses
726,947
5,464
25,024
(810)
756,625
—
(232,325)
(11,192)
(43,969)
(13,084)
(120,934)
(29,563)
(13,332)
(21,319)
270,907
(45,815)
6,237
(16,820)
214,509
(103,441)
111,068
12,395
5,705
13,345
36,563
67.0
4.6
12.5
7.2
19.6
0.9
3.7
1.1
1,004,775
9,454
35,350
—
1,049,579
(70,221)
(359,779)
(10,529)
(50,024)
(7,995)
(96,692)
(25,789)
—
527
429,077
(57,073)
3,180
19,725
394,909
(170,474)
224,435
12,786
7,864
14,096
38,620
82.2
4.8
8.0
18.8
26.8
0.8
3.7
0.6
(28)%
(42)%
(29)%
100 %
(28)%
(100)%
(35)%
6 %
(12)%
64 %
25 %
15 %
100 %
(4,145)%
(37)%
(20)%
96 %
(185)%
(46)%
(39)%
(51)%
(3)%
(27)%
(5)%
(5)%
(18)%
(4)%
57 %
(62)%
(27)%
21 %
(0)%
86 %
(1) Calculated pursuant to FASB ASC 932.
(2) We present production figures before deduction of royalties, economic rights and government’s production share, as we
believe that net production before royalties, economic rights and government’s production share is more appropriate in
light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. Oil
production figures presented on page F-70 are net of royalties, economic rights and government’s production share.
(3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor
business performance. Gas production presented on page F-71 is gas measured at the point of delivery.
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The following table summarizes certain financial data.
Colombia Ecuador Brazil Chile Argentina Other Total
Colombia Ecuador Brazil Chile Argentina Other Total
(in thousands of US$)
2023
2022
For the year ended December 31,
702,401
(101,666)
19,097
(7,096)
14,019
(2,332)
15,644
(9,815)
— 5,464
(3)
(22)
756,625
(120,934)
978,423
(78,775)
10,671
(788)
19,873
(2,796)
29,196
(14,076)
1,962
(254)
9,454
(3)
1,049,579
(96,692)
(29,563)
—
— (13,332)
—
—
(42,895)
(21,318)
(4,471)
—
—
—
—
(25,789)
Revenue
Depreciation
Impairment and
write-off
Revenue
For the year ended December 31, 2023, crude oil sales were our principal source of revenue, with 96%, 1% and 3% of our
total revenue from crude oil, purchased crude oil and gas sales, respectively. The following chart shows the change in oil and
natural gas sales from the year ended December 31, 2022, to the year ended December 31, 2023.
Consolidated
Sale of crude oil
Sale of purchased crude oil
Sale of gas
Commodity risk management contracts designated as cash flow hedges
Total
By country
Colombia
Ecuador
Brazil
Chile
Argentina
Other
Total
For the year ended
December 31,
2023
2022
(in thousands of US$)
726,947
5,464
25,024
(810)
756,625
1,004,775
9,454
35,350
—
1,049,579
Year ended December 31,
2023
2022
Change from prior year
%
(in thousands of US$, except for percentages)
702,401
19,097
14,019
15,644
—
5,464
756,625
978,423
10,671
19,873
29,196
1,962
9,454
1,049,579
(276,022)
8,426
(5,854)
(13,552)
(1,962)
(3,990)
(292,954)
(28)%
79 %
(29)%
(46)%
(100)%
(42)%
(28)%
Revenue decreased 28%, from US$1,049.6 million for the year ended December 31, 2022, to US$756.6 million for
the year ended December 31, 2023, as a result of lower realized prices and lower deliveries. Sales of crude oil decreased due
to lower realized prices and lower sold volumes of 10.9 mmbbl in the year ended December 31, 2023, compared to 12.2
mmbbl in the year ended December 31, 2022, and resulted in net revenue of US$726.9 million for the year ended
December 31, 2023, compared to US$1,004.8 million for the year ended December 31, 2022. In addition, sales of gas
decreased from US$35.4 million for the year ended December 31, 2022, to US$25.0 million for the year ended
December 31, 2023, due to lower natural gas deliveries and lower realized prices.
The decrease in 2023 net revenue of US$293.0 million is mainly explained by:
● a decrease of US$276.0 million in Colombia, due to lower realized prices and lower deliveries;
● an increase of US$8.4 million in Ecuador, mainly due to higher deliveries partially offset by lower realized oil prices;
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● a decrease of US$5.9 million in Brazil, mainly due to lower gas deliveries, partially offset by higher realized gas
prices;
● a decrease of US$13.6 million in Chile, due to lower realized prices and lower deliveries;
● a decrease of US$2.0 million in Argentina due to the divestment of the Aguada Baguales, Puesto Touquet and El
Porvenir Blocks on January 31, 2022; and
● a decrease of US$4.0 million due to lower trading operation performed by the holding company, GeoPark Limited.
Revenue attributable to our operations in Colombia for the year ended December 31, 2023, was US$702.4 million,
compared to US$978.4 million for the year ended December 31, 2022, representing 92.8% and 93.2% of our total
consolidated sales, respectively. The decrease is related to a decrease in the average realized price per barrel of crude oil from
US$82.7 per barrel to US$66.9 per barrel, primarily due to lower reference international prices, in addition to a decrease in oil
deliveries from 11.8 mmbbl to 10.5 mmbbl.
Revenue attributable to our operations in Ecuador for the year ended December 31, 2023, was US$19.1 million, a 79%
increase from US$10.7 for the year ended December 31, 2022. This increase was mainly due to higher oil deliveries from 0.12
mmboe for the year ended December 31, 2022, to 0.27 mmboe for the year ended December 31, 2023, principally as a result
of the successful drilling campaign in the Perico Block during the year, partially offset by lower realized oil prices from
US$89.9 per boe for the year ended December 31, 2022, to US$69.9 per boe for the year ended December 31, 2023. The
contribution to our revenue from our operations in Ecuador during the year ended December 31, 2023, and 2022, was 2.5%
and 1.0%, respectively.
Revenue attributable to our operations in Brazil for the year ended December 31, 2023, was US$14.0 million, a 29%
decrease from US$19.9 million for the year ended December 31, 2022, principally due to lower gas deliveries from 0.5
mmboe for the year ended December 31, 2022, to 0.3 mmboe for the year ended December 31, 2023, to respond to the lower
gas demand in Brazil, partially offset by higher realized gas prices from US$38.3 per boe for the year ended
December 31, 2022, to US$39.0 per boe for the year ended December 31, 2023. The contribution to our revenue from our
operations in Brazil during the years ended December 31, 2023, and 2022, was 1.9%, in both years.
Revenue attributable to our operations in Chile for the year ended December 31, 2023, was US$15.6 million, compared to
US$29.2 million for the year ended December 31, 2022, principally due to (1) a decrease in oil sales by US$9.4 million
reflecting lower average realized prices per barrel of crude oil from US$94.7 per barrel for the year ended December 31, 2022,
to US$68.0 per barrel for the year ended December 31, 2023, and a decrease in oil deliveries from 0.15 mmbbl to 0.07 mmbbl,
and, (2) a decrease in gas sales by US$4.1 million reflecting lower deliveries and lower average realized prices from US$22.7
per boe for the year ended December 31, 2022, to US$20.5 per boe for the year ended December 31, 2023. The contribution to
our revenue during the years ended December 31, 2023, and 2022, from our operations in Chile was 2.1% and 2.8%,
respectively.
For the year ended December 31, 2023, no revenue was generated from our operations in Argentina due to the divestment
of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks on January 31, 2022. For the year ended December 31, 2022,
revenue was US$2.0 million which contributed in a 0.2% to our revenue.
Revenue attributable to our trading operation performed by the holding company, GeoPark Limited, for the year ended
December 31, 2023, was US$5.5 million, compared to US$9.5 million for the year ended December 31, 2022. The
contribution to our revenue from our trading operation during the year ended December 31, 2023, and 2022, was 0.7% and
0.9%, respectively.
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Production and operating costs
The following table summarizes our production and operating costs for the years ended December 31, 2023 and 2022.
For the year ended December 31,
% Change
2023
2022
from prior year
(in thousands of US$, except for percentages)
Consolidated (including Colombia, Ecuador, Brazil, Chile and Other)
Royalties in cash
Economic rights in cash
Staff costs and share-based payments
Well and facilities maintenance
Operation and maintenance
Consumables
Equipment rental
Transportation costs
Field camp
Safety and insurance costs
Personnel transportation
Consultant fees
Gas plant costs
Non-operated blocks costs
Crude oil stock variation
Purchased crude oil
Other costs
Total
(12,845)
(72,032)
(14,639)
(26,089)
(8,143)
(37,556)
(4,314)
(5,850)
(6,546)
(5,487)
(3,363)
(2,291)
(1,865)
(20,421)
(2,004)
(4,666)
(4,214)
(232,325)
2023
Year ended December 31,
(80)%
(62)%
4 %
26 %
24 %
72 %
(43)%
45 %
61 %
47 %
36 %
7 %
11 %
61 %
(131)%
(41)%
(6)%
(35)%
(63,298)
(188,989)
(14,069)
(20,779)
(6,545)
(21,789)
(7,580)
(4,021)
(4,070)
(3,745)
(2,480)
(2,133)
(1,680)
(12,650)
6,449
(7,929)
(4,471)
(359,779)
2022
Colombia Ecuador Brazil Chile Other Colombia Ecuador Brazil Chile Argentina Other
(in thousands of US$)
By country
Royalties in cash
Economic rights in cash
Staff costs and share-based
payments
Well and facilities maintenance
Operation and maintenance
Consumables
Equipment rental
Transportation costs
Field camp
Safety and insurance costs
Personnel transportation
Consultant fees
Gas plant costs
Non-operated blocks costs
Crude oil stock variation
Purchased crude oil
Other costs
Total
(11,201)
(72,032)
(12,006)
(23,280)
(8,143)
(36,078)
(3,461)
(5,145)
(5,761)
(5,075)
(3,211)
(2,241)
(131)
(12,168)
(1,012)
—
(3,301)
(204,246)
— (1,096)
—
—
(548)
—
— (60,314)
— (188,989)
— (1,546)
—
—
(1,165)
—
(273)
—
—
—
(2,601)
(2)
(30)
(1,368)
(1,439)
(2)
—
—
—
— (1,357)
(121)
(15)
—
(838)
(632)
—
(73)
(776)
—
(9)
(184)
(183)
(45)
(107)
—
(45)
—
(42)
(8)
—
— (1,734)
—
(108)
(101)
—
—
(376)
(4,946)
— (10,647)
— (13,670)
—
(6,240)
— (19,727)
(7,372)
—
(3,163)
—
(3,239)
—
(3,321)
—
(2,334)
—
(2,067)
—
—
—
(6,618)
—
3,652
—
— (4,666)
—
(3,577)
—
(327,626)
(4,666)
(537)
(8,226)
(8,145)
(891)
—
—
(10,241)
(3,180)
(5)
(38)
(5,029)
(1,732)
(191)
—
—
—
— (1,917)
(16)
—
—
(148)
(848)
—
(3)
(795)
—
—
(195)
(217)
—
(83)
—
(9)
(51)
—
(3)
(241)
— (1,375)
(215)
—
(235)
—
—
—
(438)
(206)
(14,126)
(5,299)
(5,817)
3,053
—
—
(3,220)
(199)
—
(157)
—
(305)
—
(129)
—
(60)
—
(7)
—
(36)
—
(12)
—
(54)
—
(12)
—
(64)
—
—
—
—
(21)
— (7,929)
—
(7,929)
(250)
(1,579)
Consolidated production and operating costs decreased 35%, from US$359.8 million for
the year ended
December 31, 2022, to US$232.3 million for the year ended December 31, 2023, primarily due to a decrease in royalties and
economic rights paid in-cash, partially offset by an increase in consumables due to higher energy costs in Colombia and an
increase in non-operated block costs due to higher activities in the CPO-5 and Perico Blocks in Colombia and Ecuador.
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Production and operating costs in Colombia decreased by 38%, to US$204.2 million for the year ended
December 31, 2023, as compared to US$327.6 million for the year ended December 31, 2022, primarily due to lower royalties
and economic rights which decreased by US$249.3 million, mainly due to a decrease in the mix of royalties and economic
rights paid “in-cash” as compared to royalties and economic rights paid “in-kind”, and lower international prices, partially
offset by an increase in consumables due to higher energy costs in the Llanos 34 Block due to a drought that affected the
energy matrix in Colombia as a result of decreased availability of hydroelectric power and an increase in non-operated block
costs due to higher activities in the CPO-5 Block.
Production and operating costs in Ecuador were US$10.2 million for the year ended December 31, 2023, compared to
US$3.2 million the year ended December 31, 2022. The increase was mainly the result of higher deliveries that increased
130% during 2023, compared to 2022, and higher activity in the Perico block.
Production and operating costs in Brazil decreased by 7%, to US$4.9 million for the year ended December 31, 2023, as
compared to the year ended December 31, 2022, mainly resulting from lower royalties due to a decrease in gas deliveries and
maintenance activities in the Manati Block. Operating costs per boe increased to US$10.9 per boe for the year ended
December 31, 2023, from US$7.4 per boe for the year ended December 31, 2022, due to lower gas deliveries during 2023.
Production and operating costs in Chile decreased by 42% to US$8.2 million due to lower well intervention and
maintenance activities in the Fell Block. Operating costs per boe decreased to US$13.0 per boe in 2023 from US$16.1 per boe
in 2022.
Purchases of crude oil for the trading operation performed by the holding company, GeoPark Limited, amounted to
US$4.7 million and US$7.9 million for the years ended December 31, 2023, and 2022, respectively.
No production and operating costs were recorded in Argentina for the year ended December 31, 2023, due to the
divestment of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks on January 31, 2022.
Geological and geophysical expenses
Geological and geophysical expenses increased by 6%, from US$10.5 million for the year ended December 31, 2022, to
US$11.2 million for the year ended December 31, 2023, as the result of higher exploratory activities.
Administrative costs
Administrative costs decreased by 12%, from US$50.0 million for the year ended December 31, 2022, to US$44.0 million
for the year ended December 31, 2023, primarily as the result of higher overhead related to joint operations, and a one-time
share-based payment made to the Group´s former CEO in 2022 as part of his transition agreement described in “Item 6.
Directors, Senior Management and Employees – B. Compensation – CEO Transition Agreement.”
Selling expenses
Colombia
Ecuador
Chile
Argentina
Total
Year ended December 31,
Change from prior year
2023
%
(in thousands of US$, except for percentages)
2022
(10,976)
(1,850)
(258)
—
(13,084)
(5,887)
(1,676)
(328)
(104)
(7,995)
(5,089)
(174)
70
104
(5,089)
86 %
10 %
(21)%
(100)%
64 %
Selling expenses increased by 64%, from US$8.0 million for year ended December 31, 2022, to US$13.1 million for
the year ended December 31, 2023, primarily due to deliveries at different sales points in the CPO-5 Block in Colombia. Sales
at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery
points are recognized as selling expenses.
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Commodity risk management contracts
As from January 1, 2023, commodity risk management contracts are designated and qualify as cash flow hedges, so that
realized gains or losses are recorded within Revenue while unrealized gain and losses are recorded in the Reserves line item
within Equity.
We recorded a net loss of US$70.2 million for the year ended December 31, 2022, composed by a realized and an
unrealized portion. The realized loss of US$83.2 million reflected Brent oil prices above ceiling prices of the commodity risk
management contracts settled during the period and the unrealized gain of US$13.0 million reflected the reclassification to
realized loss of the previously mentioned settled contracts.
Depreciation
Colombia
Ecuador
Brazil
Chile
Argentina
Other
Total
Year ended December 31,
2023
2022
Change from prior year
%
(in thousands of US$, except for percentages)
(101,666)
(7,096)
(2,332)
(9,815)
(22)
(3)
(120,934)
(78,775)
(788)
(2,796)
(14,076)
(254)
(3)
(96,692)
(22,891)
(6,308)
464
4,261
232
—
(24,242)
29 %
801 %
(17)%
(30)%
(91)%
— %
25 %
Depreciation charges increased by 25% from US$96.7 million for the year ended December 31, 2022, to US$120.9
million for the year ended December 31, 2023, primarily due to an increase in the depreciation cost per boe in Colombia as a
consequence of lower proved and probable reserves at the end of 2022 in the CPO-5 and Llanos 34 Blocks, and higher
production sold in Ecuador, partially offset by lower production sold in Chile.
Operating profit
Colombia
Ecuador
Brazil
Chile
Argentina
Other
Total
Year ended December 31,
2023
2022
Change from prior year
%
(in thousands of US$, except for percentages)
321,512
(1,912)
4,514
(21,878)
(11,189)
(20,140)
270,907
443,584
(1,033)
10,521
(728)
923
(24,190)
429,077
(122,072)
(879)
(6,007)
(21,150)
(12,112)
4,050
(158,170)
(28)%
85 %
(57)%
2,905 %
(1,312)%
(17)%
(37)%
We recorded an operating profit of US$270.9 million for the year ended December 31, 2023, compared to US$429.1
million for the year ended December 31, 2022, as a result of the reasons described above.
In 2023, we recorded a write-off of unsuccessful exploration efforts of US$29.6 million that corresponded to three
unsuccessful exploratory wells drilled in the Llanos 87 Block (Colombia), an unsuccessful exploratory well drilled in the
Llanos 124 Block (Colombia) and other exploration costs incurred in the Llanos 94, Coati and Llanos 124 Blocks (Colombia).
During 2023, we also recognized an impairment loss of US$13.3 million in the Fell Block due to the known selling price
of the related net assets in the context of the divestment transaction of the Chilean business. In addition, we recorded
termination and other costs incurred from the divestment process in Chile, including a provision for investment commitments
maintained by GeoPark after the transaction, for a total amount of US$9.7 million, together with the amount
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paid for transferring the working interest in the Los Parlamentos Block in Argentina to the joint operation partner of US$7.0
million.
In 2022, we recorded a write-off of unsuccessful exploration efforts of US$25.8 million that corresponded to exploration
costs incurred in previous years in the Tacacho and Terecay Blocks (Colombia), four exploratory wells drilled in the CPO-5,
Platanillo, Llanos 34 and Llanos 94 Blocks (Colombia), and certain exploration costs incurred in the Espejo Block (Ecuador).
No impairment losses were recognized during 2022.
Financial results
Net financial results decreased 27% to US$39.6 million for the year ended December 31, 2023, as compared to US$53.9
million for the year ended December 31, 2022, mainly resulting from the deleveraging process executed during 2021 and 2022
that resulted in significant debt reduction with extended maturities and lower costs of debt.
Foreign exchange (loss) gain
Foreign exchange difference was a loss of US$16.8 million for the year ended December 31, 2023, compared to a gain of
US$19.7 million for the year ended December 31, 2022. The results in both years mainly correspond to the effect of the
fluctuation of the local currency in Colombia on the liabilities held in that currency, such as the income tax payable, the
provision for asset retirement obligation and other environmental liabilities, and the lease liabilities. The Colombian Peso
revalued by 21% in 2023 and devalued by 21% in 2022.
Profit before income tax
Colombia
Ecuador
Brazil
Chile
Argentina
Other
Total
Year ended December 31,
Change from prior year
2023
2022
%
(in thousands of US$, except for percentages)
287,243
(3,188)
5,504
(23,462)
(6,933)
(44,655)
214,509
460,561
(1,469)
11,119
(2,491)
(4,337)
(68,474)
394,909
(173,318)
(1,719)
(5,615)
(20,971)
(2,596)
23,819
(180,400)
(38)%
117 %
(50)%
842 %
60 %
(35)%
(46)%
For the year ended December 31, 2023, we recorded a profit before income tax of US$214.5 million, compared to a profit
of US$394.9 million for the year ended December 31, 2022, primarily due to the reasons mentioned above.
Income tax expense
Colombia
Ecuador
Brazil
Chile
Other
Total
Year ended December 31,
Change from prior year
2023
2022
%
(in thousands of US$, except for percentages)
(96,770)
198
(396)
(3,878)
(2,595)
(103,441)
(162,565)
(780)
(3,566)
(525)
(3,038)
(170,474)
65,795
978
3,170
(3,353)
443
67,033
(40)%
(125)%
(89)%
639 %
(15)%
(39)%
Our effective tax rate was 48% for the year ended December 31, 2023, compared to 43% in 2022. The increase in the
effective tax rate was primarily due to higher statutory income tax rate applicable to companies engaged in the extraction of
crude oil in Colombia, partially offset by the effect of the revaluation of the local currency in Colombia on the tax bases of
property, plant and equipment.
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In 2023 and 2022, the statutory income tax rate in Colombia was 35%, though a tax surcharge is also applicable in 2023,
as a result of a tax reform approved in November 2022, impacting companies engaged in the extraction of crude oil like
GeoPark. The tax surcharge varies from zero to 15%, depending on different Brent oil prices. The applicable surcharge for
2023 was 10%.
Profit for the year
Colombia
Ecuador
Brazil
Chile
Argentina
Other
Total
Year ended December 31,
2023
2022
Change from prior year
%
(in thousands of US$, except for percentages)
190,473
(2,990)
5,108
(27,341)
(6,933)
(47,249)
111,068
297,996
(2,249)
7,553
(3,016)
(4,337)
(71,512)
224,435
(107,523)
(741)
(2,445)
(24,325)
(2,596)
24,263
(113,367)
(36)%
33 %
(32)%
807 %
60 %
(34)%
(51)%
For the year ended December 31, 2023, we recorded a net profit of US$111.1 million as a result of the reasons described
above, compared to a net profit of US$224.4 million for the year ended December 31, 2022.
Year ended December 31, 2022, compared to year ended December 31, 2021
For a discussion of the results of our operations for the year ended December 31, 2022, compared to the year ended
December 31, 2021, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended
December 31, 2022, compared to the year ended December 31, 2021” in our Annual Report on Form 20-F for the year ended
December 31, 2022.
B. Liquidity and capital resources
Overview
Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including:
● changes in oil and natural gas prices and our ability to generate cash flows from our operations;
● our capital expenditure requirements;
● the level of our outstanding indebtedness and the interest we have to pay on this indebtedness; and
● changes in exchange rates which will impact our generation of cash flows from operations when measured in US$.
We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances
and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and
potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing
equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our
assets or to obtain additional financing on terms acceptable to us, or at all.
Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash
generated by our operations. We have also in the past entered into offtake and prepayment agreements. For further information
on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and
Development of the Company—Funding.”
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We believe that our current operations and 2024 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 capital expenditure program reductions,
oil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital
resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry
conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and
any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the
Company—B. Business Overview—2024 Strategy and Outlook.”
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—2024 Strategy and Outlook”.
In the year ended December 31, 2023, we had total capital expenditures related to the purchase of property, plant and
equipment of US$199.0 million (US$178.1 million and US$20.9 million in Colombia and Ecuador, respectively).
In the year ended December 31, 2022, we had total capital expenditures related to the purchase of property, plant and
equipment of US$168.8 million (US$139.2 million, US$18.5 million, US$11.1 million and US$0.1 million in Colombia,
Ecuador, Chile and Argentina, respectively).
Cash flows
The following table sets forth our cash flows for the periods indicated:
Cash flows from (used in)
Operating activities
Investing activities
Financing activities
Net increase (decrease) in cash and cash equivalents
Cash flows from operating activities
2023
Year ended December 31,
2022
(in thousands of US$)
2021
300,938
(198,590)
(98,721)
3,627
467,471
(153,673)
(286,552)
27,246
216,777
(126,558)
(190,442)
(100,223)
For the year ended December 31, 2023, cash flows from operating activities were US$300.9 million, a 36% decrease from
US$467.5 million for the year ended December 31, 2022, mainly resulting from the decrease in revenues reflecting lower oil
and gas prices in 2023.
For the year ended December 31, 2022, cash flows from operating activities were US$467.5 million, a 116% increase
from US$216.8 million for the year ended December 31, 2021, mainly resulting from the increase in oil revenues reflecting
higher prices in 2022, partially offset by the loss on commodity risk management contracts.
Cash flows used in investing activities
For the year ended December 31, 2023, cash flows used in investing activities were US$198.6 million, a 29% increase
from US$153.7 million for the year ended December 31, 2022. This variation is primarily explained by an increase of
US$30.2 million in capital expenditures related to the purchase of property, plant and equipment.
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For the year ended December 31, 2022, cash flows used in investing activities were US$153.7 million, a 21% increase
from US$126.6 million for the year ended December 31, 2021. This variation is primarily explained by an increase of
US$39.6 million in capital expenditures related to the purchase of property, plant and equipment.
Cash flows used in financing activities
Cash flows used in financing activities were US$98.7 million for the year ended December 31, 2023, compared to
US$286.6 million used in financing activities for the year ended December 31, 2022. This variation was principally related to
the full redemption during 2022 of the Notes due 2024.
Cash flows used in financing activities were US$286.6 million for the year ended December 31, 2022, compared to
US$190.4 million used in financing activities for the year ended December 31, 2021. This variation was principally related to
the full redemption of the Notes due 2024 plus an increase in the programs of repurchase of shares and quarterly cash
distributions.
Indebtedness
As of December 31, 2023, and 2022, we had total outstanding indebtedness of US$501.0 million and US$497.6 million,
respectively, as set forth in the table below.
Notes due 2027
Total
Our material outstanding indebtedness is described below.
Notes due 2027
General
As of December 31,
2023
2022
(in thousands of US$)
500,981
500,981
497,642
497,642
In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due
2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The
reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. Final maturity will be January 17,
2027.
On June 17, 2022, we received requisite consents from holders of the Notes due 2027 for certain amendments to the
indenture governing the Notes due 2027. The amendments addressed the impact of adverse market conditions and related drop
in the price of crude oil during 2020 on our results, which in turn negatively impacted the restricted payments builder basket,
and increased and reset the general restricted payments basket in the indenture to provide us additional restricted payments
capacity, giving us additional financial flexibility. Consequently, on June 27, 2022, we paid a consent fee equal to $10.00 per
$1,000 to holders of the Notes due 2027 that delivered their consents for the abovementioned amendments to the indenture
governing the Notes due 2027.
Ranking
The Notes due 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark
Colombia, S.L.U. (the “Guarantor”). The Notes due 2027 rank equally in right of payment with all existing and future senior
obligations of GeoPark Limited and the Guarantor (except those obligations preferred by operation of law, including without
limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of
GeoPark Limited and the Guarantor; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantor
and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
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Optional redemption
We may, at our option, redeem all or part of the Notes due 2027, 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 January 17 of the years indicated below:
Year
2024
2025
2026 and after
Change of control
Percentage
102.750 %
101.375 %
100.000 %
Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all
outstanding Notes due 2027, 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. If holders of not less
than 90% in aggregate principal amount of the outstanding Notes due 2027 validly tender and do not withdraw such notes and
we repurchase all such notes, we may redeem the Notes due 2027 that remain outstanding following such purchase at a price
in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such
redemption.
Covenants
The Notes due 2027 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,
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 2027 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 indentures governing the
Notes due 2027, 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 includes certain tests that must be satisfied before incurring additional debt, as well as
other matters, and which provide among other things, that the net debt to EBITDA ratio should not exceed 3.25 and the
EBITDA to interest ratio should exceed 2.5. 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).
Events of default
Events of default under the indentures governing the Notes due 2027 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 indentures
governing the Notes due 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more,
and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and
invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require
the principal of and accrued interest on the Notes due 2027 to become or to be declared due and payable.
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Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31, 2023, or as of December 31, 2022.
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—2024 Strategy and Outlook.”
E. 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 issued 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.
Reserves estimates
The process of estimating reserves is complex. It requires significant judgements and decisions based on available
geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas
reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2023, prepared by
DeGolyer and MacNaughton Corp., an independent international oil and gas consulting firm based in Dallas, Texas, in line
with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management
Reporting System (PRMS) framework. It incorporates 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 gas prices and quality differentials;
● assumed effects of regulation by governmental agencies;
● tax rates by jurisdiction, and
● future development and operating costs.
Our management believes these factors and assumptions are reasonable based on the information available to them 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 gas
prices and costs change.
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Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of
exploration and evaluation assets; oil and gas properties and other property, plant and equipment; which may be affected due
to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income,
which may change where such charges are determined using the unit of production method, or where the useful life of the
related assets change, (c) provisions for abandonment that may require revision where changes to reserves estimates affect
expectations about when such activities will occur and the associated cost of these activities and, (d) the recognition and
carrying value of deferred income tax assets that may change due to changes in the judgements regarding the existence of such
assets and in estimates of the likely recovery of such assets.
Cash flow estimates for impairment assessments
Cash flow estimates for impairment assessments of non-financial assets require assumptions about three primary
elements: future prices, reserves and discount rate. Estimates of future prices require significant judgments about highly
uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s forecasts for oil and
gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments.
Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs.
Given the significant assumptions required and the possibility that actual conditions may differ, management considers the
assessment of impairment to be a critical accounting estimate.
For further information related to impairment of property, plant and equipment, please see Note 37 to our Consolidated
Financial Statements.
Exploration and evaluation expenditures
The Group adopts the successful efforts method of accounting. Our management makes assessments and estimates
regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient
information exists. This assessment is made on a quarterly basis considering the advice from qualified experts.
The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to
determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not
reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and
resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are
classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy
requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether
an economically viable extraction operation can be established. Any such estimates and assumptions may change as new
information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery
of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the
period when the new information becomes available.
Depreciation of oil and gas assets
Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) 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. This results in a depreciation charge proportional
to the depletion of the anticipated remaining production from the block.
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present
assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use
of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The
calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from
current forecast production based on total proved and probable reserves, or future capital expenditure estimates change.
Changes to proved and probable reserves could arise due to changes in the factors or assumptions used
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in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity
prices and commodity price assumptions and (b) unforeseen operational issues.
Asset retirement obligations
Obligations related to the 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 estimates and judgments because most of the obligations will be settled after many years. Technologies
and costs are constantly changing, as well as political, environmental, health, safety and public relations considerations.
Consequently, the timing and future cost of 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. The
present value of future costs necessary for well 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.
The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and
gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are
made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions
established which would affect future financial results.
The provision at reporting date represents management’s best estimate of the present value of the future abandonment
costs required.
Contingencies
(1) 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, tax, 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 Consolidated Financial
Statements.
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ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A.
Directors and executive officers
Board of directors
Our board of directors is currently composed of nine members. Our directors are elected by shareholders annually at the
Company’s annual general meeting and 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 term for the current directors expires on the date of our next annual general meeting of shareholders to
be held in 2024.
The current members of the board of directors were appointed at our annual general meeting held on July 19, 2023. The
table below sets forth certain information concerning our current board of directors. All ages are current as of March 27, 2024.
Name
Sylvia Escovar Gómez (1)(2)
James F. Park
Robert Bedingfield (1)(2)
Constantin Papadimitriou (1)(2)
Somit Varma (1)
Brian F. Maxted (1)
Carlos E. Macellari (1)
Marcela Vaca
Andrés Ocampo
Position
Chair and Director
Deputy Chair, Director and Co-founder
Director
Director
Director
Director
Director
Director
Chief Executive Officer and Director
(1) Independent director under SEC Audit Committee rules.
(2) Member of the Audit Committee.
At the Company
Age
62
68
75
63
63
66
70
55
45
since
2020
2002
2015
2018
2020
2022
2022
2012
2010
Biographical information of the current members of our board of directors is set forth below. Unless otherwise indicated,
the current business address for our directors is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Sylvia Escovar Gómez has been a member of our board of directors since August 2020 and was appointed as Chair on
June 6, 2021. An economist by training, she received her undergraduate degree from the Universidad de Los Andes in
Colombia. She has had a long and prestigious career in both the public and private sectors, having worked for the World Bank,
the Central Bank of Colombia and the Colombian National Department of Planning. Previously, she served as Deputy
Secretary of Education and Deputy Secretary of Finance for Bogota’s government as well as Vice President of Finance of
Fiduciaria Bancolombia. Ms. Escovar was the CEO of Terpel S.A., a fuel distribution company that operates in Colombia,
Ecuador, Panama, Peru and the Dominican Republic from 2012 until December 2020. In 2014, Ms. Escovar was named the
top businessperson of the year by Portafolio, Colombia’s leading financial daily. In 2018, she received the National Order of
Merit for spearheading private sector support for peacebuilding and reconciliation in Colombia. In 2020, she was the only
woman on the Corporate Reputation Business Monitor’s list of Colombian leaders with the best reputation to rank in the top
10. In 2023, Forbes named Sylvia Escovar as one of the 100 most powerful women in Colombia. Ms. Escovar’s other Board
memberships include Grupo Bancolombia, Empresa de Telecomunicaciones de Bogotá, Organización Corona S.A.,
Organización Terpel, Compañía de Medicina EPS Sanitas and Grupo Energía Bogotá.
James F. Park since co-founding the Company in 2002, has served for 20 years as our Chief Executive Officer until his
retirement effective June 30, 2022. He initially funded, built the team, and led the strategy and growth of GeoPark from its
small footprint at the southern tip of South America into becoming one of the leading oil and gas companies operating across
Latin America today. He continues to serve as Vice Chair of our board of directors and advisor to the team. Beginning as a
drilling rig roughneck in his teenage years, Mr. Park has more than 50 years of experience in all phases of the upstream oil and
gas business, with a record of achievement in the acquisition, technical operation, and management
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of international projects and teams across the globe - including projects in North America, Central America, South America,
Asia, Europe, Africa, and the Middle East - and with a successful emphasis on people, communities, and the environment. He
earned a Bachelor of Science in Geophysics from the University of California at Berkeley and previously worked as a research
scientist focused on earthquakes and tectonics at the University of Texas. Mr. Park is a member of the board of directors of
GoodRock LLC, Spark Resources LLC and Rocabuena S.A.S., and is a former Board member of the humanitarian non-profit
SEE (Surgical Eye Expeditions) International, and the service and advocacy non-profit Girls, Inc. He is a member of the
AAPG and SPE, has a degree in environmental management, and has lived in Latin America since 2002.
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. From 2013 to 2023, Mr. Bedingfield served
as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). Mr.
Bedingfield became age ineligible to serve on SAIC’s board on June 7, 2023.
Constantin Papadimitriou has been a member of our board of directors since May 2018. He is a respected and successful
international investor and businessman, with more than 30 years of investment experience in global capital markets and in
resource and industrial projects and was an early investor in GeoPark. Mr. Papadimitriou was for 18 years the Head of General
Oriental Investments S.A., the Investment Manager of the Cavenham Funds, as part of the Cavamont Group founded by the
Late Sir James Goldsmith. During his tenure at the Cavamont group, Mr. Papadimitriou was initially responsible for Treasury
Management, then the Private Equity Portfolio as well as representing the group on the Boards of associated companies
including investments in the oil and gas, mining, real estate, and gaming sectors (including Basic Petroleum, a Nasdaq-listed
Guatemalan oil and gas company). He is a founding partner of Diorasis International, a company mainly focusing on
investments in Greece and the broader Balkans in Aquaculture, and he also chairs the Greek Language School of Geneva and
Lausanne. Mr. Papadimitriou holds an Economics and Finance degree and a post-graduate Diploma in European Studies from
Geneva University. Mr. Papadimitriou is currently a member of the board of directors of Cavamont Holdings Limited, General
Oriental Advisory (formerly known as General Oriental Investments S.A.), Diorasis International S.A. and Tellco AG.
Somit Varma has been a member of our board of directors since August 2020. He has been a proven and respected
investor in oil, gas, mining, and infrastructure projects across the globe for more than three decades. During his time at the
International Finance Corporation (IFC), he was the Global Head of Oil, Gas, Mining and Chemicals, Chairman of the IFC
Oil, Gas, Mining and Chemicals Investment Committee and Chairman of the Global Gas Flaring Reduction Partnership. From
2011 until July 2020, Mr. Varma was a Managing Director of the Energy Group at Warburg Pincus LLC, one of the world’s
premier private equity firms. Throughout his tenure at Warburg Pincus, Mr. Varma served on the boards of several
international energy companies where he worked with management teams on a diverse set of issues including new
acquisitions, strategic partnerships, capital allocation, risk management, succession planning, and growing and mentoring
teams. Mr. Varma was Chairman of the Energy and Infrastructure Council of EMPEA, the global industry association for
private capital in emerging markets. He is also currently an advisor to a global private equity firm and a family office. Mr.
Varma earned his MBA at Boston University before attending the Executive Development Program at Harvard Business
School. During the last 5 years, Mr. Varma has served as board member of several companies including Delonex Energy,
Zenith International, Apex Energy and Zenith US.
Brian F. Maxted has been a member of our board of directors since July 2022. He holds a bachelor’s degree in geology
from the University of Sheffield and a master’s degree in organic geochemistry and petrology from the University of
Newcastle-upon-Tyne. Mr. Maxted is a proven oil and gas explorer, private equity entrepreneur and public company leader in
the upstream E&P business, with a global track record of significant basin and play discoveries over 30 years. He spent the
first part of his professional life from the late 1970s working for BP in locations including Europe, Africa,
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North America and South America, where he was involved in the discovery of Colombia’s giant Cusiana and Cupiagua oil
fields in the early 1990s. During the second half of his career from the mid-1990s through the 2010s Mr. Maxted held various
exploration leadership roles for US-based independents, including Triton Energy and Hess Corporation. In 2003, Mr. Maxted
became a founding partner and later the CEO/CXO and Board Director of Kosmos Energy. Mr. Maxted retired from Kosmos
in 2019 and established Limatus Energy Advisory Limited to provide strategic counsel to upstream E&P companies. In
addition, he led the formation of Lapis Energy, a company focused on carbon solutions in the US Lower 48, where he
currently serves as Chair of the Board. Mr. Maxted is also a member of the board of directors of JHI Energy – now Triple 7
Energy Inc.
Carlos E. Macellari has been a member of our board of directors since July 2022. He holds a bachelor’s degree in
geology from the Universidad Nacional de La Plata in Argentina, and a master´s degree and a PhD in geology from Ohio State
University. He has over 30 years of successful exploration, development and management experience in the oil and gas
industry across several continents, at Tecpetrol, Repsol YPF, Hocol, Benton Oil & Gas, Enron Oil & Gas International and
Pecten International (Shell Oil). As Director of Exploration and Development for Tecpetrol, he led the subsurface team
responsible for making Fortín de Piedra the largest gas producing block in Argentina, and the discovery and development of
the Pendare Field in Colombia. As Worldwide Director of Geology, he also led the technical group behind Repsol’s
exploration success in locations such as Libya, Algeria, Pre-Salt Brazil, the Gulf of Mexico, Venezuela and Peru. He has
published over 50 technical papers and has been guest lecturer in numerous international forums. He is the founder of the
Journal of South American Earth Sciences, has lectured several courses in the USA, Colombia, Spain and Argentina and is
currently a professor for postgraduate students at Universidad Nacional de La Plata. At present he is an independent consultant
on oil and gas exploration and production after founding and managing Andes Energy Consulting, since 2020 he has been a
Board member at Inverban Investments, Tecpetrol Investments, Tecpetrol International and Suizum, and since 2024
independent board member at Olympic Peru.
Marcela Vaca joined GeoPark in August 2012 and served as General Director until August 2022. She has been a member
of our board of directors since July 2022. She has more than 20 years of experience in planning, legal, environmental and
social articulation and management of hydrocarbon exploration and production projects in Colombia and elsewhere in Latin
America. Under her leadership as Director for Colombia and General Director, GeoPark became one of the leading oil and gas
companies in the country. She plays a crucial role in advancing GeoPark’s diversity, equality and inclusion efforts, and
promotes female empowerment as a key to the economic development of Latin America. Prior to joining our company, for
nine years Ms. Vaca was the CEO of the Hupecol Group, where her achievements included leading the development of the
Caracara field and the construction of the Jaguar–Santiago Pipeline. From November 2000 to June 2003, she worked as Legal,
Administrative and External Affairs Manager at GHK Company Colombia. Bloomberg Linea includes Ms. Vaca in its 500
most influential people in Latin America, and in 2020, 2021 and 2022 Forbes named her as one of the 50 most powerful
women in Colombia. Ms. Vaca was a member of the board of directors of the Colombian Oil Association (ACP, Asociación
Colombiana de Petróleo) from 2010 to 2021 and served as Chair of the Board until March 2022. Marcela graduated in Law
with a specialization in Commercial Law from the Pontificia Universidad Javeriana in Colombia and is a Fulbright Scholar
with a Summa Cum Laude Master (LLM) from Georgetown University in the USA. Currently, Ms. Vaca serves as board
member at Corficolombiana and Fundación Juanfe.
Andrés Ocampo has served as our Chief Executive Officer and as a member of our board of directors since July 2022. He
previously served as our Chief Financial Officer (from November 2013 through June 2022) and Director of Growth and
Capital Markets (from January 2011 through October 2013), and has been with our company since July 2010. Mr. Ocampo
holds a Bachelor’s degree in Economics from Universidad Católica Argentina, has more than 17 years of experience in
business and finance. Andrés has been instrumental in helping GeoPark reach some of its greatest milestones, including its
entry into Colombia and Brazil, the IPO on the New York Stock Exchange, the acquisition of Amerisur Resources and
significant acreage expansion in Colombia. Our board of directors appointed Mr. Ocampo to serve as Chief Executive Officer
of the Company effective July 1, 2022, by virtue of his wide experience in business management and finance together with his
character, vision, knowledge of the Company and his proven ability to lead successful teams. Before joining our Company,
Mr. Ocampo worked at Crédit Agricole Corporate & Investment Bank and Citigroup, focusing on the oil and gas and
commodities industries.
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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 current as of March 27, 2024.
Name
Andrés Ocampo
Jaime Caballero Uribe
Augusto Zubillaga
James Deckelman
Rodolfo Martín Terrado
Mónica Jiménez
Agustina Wisky
Position
Chief Executive Officer and Director
Chief Financial Officer
Chief Technical Officer
Chief Exploration Officer
Chief Operating Officer
Chief Strategy, Sustainability and Legal Officer
Chief People Officer
At the Company
Age
45
49
54
67
49
48
47
since
2010
2024
2006
2023
2018
2022
2002
Biographical information of our executive officers is set forth below. Unless otherwise indicated, the current business
address of our executive officers is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Jaime Caballero Uribe has served as our Chief Financial Officer since January 2024. He has more than 25 years of
industry and finance experience, including senior positions in large corporations as well as in start-ups and entrepreneurial
businesses. Until August 2023, Mr. Caballero was Group CFO at Ecopetrol, the largest corporation in Colombia and one of the
400 largest companies in the world where he helped the management team achieve various performance records, including the
delivery of more than US$20 billion in growth financing and debt refinance. During his tenure, he was recognized by the
Institutional Investor publication as one of the top three sector CFOs in Latin America. Previously, he held multiple positions
at BP plc over 17 years, where his most recent appointment was CFO for the Brazil Region, which includes Colombia,
Uruguay and Venezuela. Mr. Caballero holds a degree in Law from Universidad de Los Andes, an MBA in Energy Business
from Fundação Getulio Vargas, and certificates in CFO Excellence from Wharton and Energy Innovation and Emerging
Technologies from Stanford. Mr. Caballero currently serves as a board member of Agricola Cerro Prieto S.A.
Augusto Zubillaga has served as our Chief Technical Officer since July 2022. He previously served in other management
positions throughout the Company including as Chief Operating Officer, Operations Director, Argentina Director and
Production Director. He is a petroleum engineer with more than 26 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.
James Deckelman has served as our Chief Exploration Officer since October 2023. He is a highly successful explorer
with over 25 years of experience in Latin America, the Middle East, Africa, Southeast Asia and North America, leading
projects ranging from ultra-deepwater to unconventional. Mr. Deckelman added over a billion barrels of recoverable resources
for companies including ConocoPhillips, BP and Talisman Energy. In Latin America, he has led projects and transactions in
Colombia, Venezuela, Peru, Ecuador, Mexico, Brazil and Argentina. Mr. Deckelman is highly experienced in investment
evaluation, new asset capture, and delivering production and reserve growth. He has a Master´s degree in geology from Utah
State University and has authored over 15 industry publications focused on Latin America. Among other awards, in 2021, he
was recognized as one of “Industry’s 100 Who Made a Difference” by the American Association of Petroleum Geologists.
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Rodolfo Martín Terrado has served as our Chief Operating Officer since July 2022. He previously served as our Director
of Operations since he joined GeoPark in August 2018. Mr. Terrado has more than 25 years of experience in the oil industry,
working in field development and operations. Martín has a degree in Petroleum Engineering from the Instituto Tecnológico de
Buenos Aires (ITBA) and an MBA from the IAE Business School at the Universidad Austral in Buenos Aires. He is a member
of the Society of Petroleum Engineers (SPE). Prior to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San Jorge
and Chevron San Jorge S.A. in different international operations, including in Argentina, the United States and Venezuela.
Mr. Terrado previously led heavy oil operations in Venezuela assets and his prior responsibilities include waterflooding, CO2
flooding and unconventionals.
Mónica Jiménez has served as our Chief Strategy, Sustainability and Legal Officer and Company Secretary since August
2022. She leads the strategy and sustainability (ESG) within the Company and leads the governance and legal team. Mrs.
Jiménez is an experienced attorney in corporate and international law in Canada and Colombia with extensive experience in
international commercial and investment arbitration. After living in Canada for more than 16 years, Mrs. Jiménez was Vice
President of Corporate Affairs and Secretary General of Ecopetrol (NYSE), Colombia´s largest company, before joining
GeoPark. Mrs. Jiménez studied Law at Universidad the Los Andes, has a postgraduate degree in Civil Liability and Damages
from the Universidad Externado de Colombia, and a Master of Science in Development Studies from the London School of
Economics (LSE). Recognized as one of the leading in-house lawyers in Colombia by The Legal 500 GC Powerlist: Colombia
2022 and 2023, Mrs. Jiménez is a current member of the International Court of Arbitration of the International Chamber of
Commerce (ICC). She has served as board member of several companies and is currently a member of the Board of Grupo
Bolivar S.A.
Agustina Wisky is GeoPark’s Chief People Officer, responsible for enriching and promoting an organizational culture
based on trust, teamwork, continuous improvement, mutual respect, and diversity. Agustina has been with the Company since
it was founded in 2002, and she created and has led the People department for over 15 years, guided by the principles of
attracting, motivating and developing the best professionals, and ensuring the comprehensive wellbeing of staff and their
families. She previously held the position of Performance Director at GeoPark. Before joining GeoPark, Agustina worked at
PricewaterhouseCoopers and AES Gener in Argentina. Agustina is a Public Accountant and has a Master’s degree in Human
Resources from the IAE Business School of the Universidad Austral in Buenos Aires, Argentina. Thanks to Agustina’s
leadership in the implementation of inclusion and diversity best practices, GeoPark won the Equipares Silver Award in 2020,
which is given by the Government of Colombia with technical support from the United Nations Development Program.
GeoPark was furthermore included in the Bloomberg Gender-Equality Index (GEI) in 2022, which evaluates the performance
of listed companies that are committed to transparency in gender reporting.
B. Compensation
Executive officers and director compensation
For the year ended December 31, 2023, we paid an aggregate of US$2.0 million to the members of our board of directors
for their services in all capacities. This amount includes payments made to Mr. Carlos Macellari for his services as a
consultant for the period from May to August 2023. It does not include payments made to executive director Andrés Ocampo
as he only received compensation in his capacity as an executive officer (as described below). Disclosure of compensation on
an individual basis is included in Note 11 to our Consolidated Financial Statement.
During this same period, we paid an aggregate of US$8.9 million for salaries and other benefits (including with respect to
grants of awards under the LTIP Executives and contingent amounts or deferred compensation accrued for the year, even if
payable at a later date) to the executive officers of the Company for their services in all capacities.
Annual Bonus Program
Our Corporate Governance Guidelines set forth that the Compensation Committee will evaluate annually the performance
of the Chief Executive Officer and other executive officers of the Company based on objective and relevant corporate goals
and that the board of directors, in consultation with and at the recommendation of the Compensation Committee will review
executive officers’ annual performance evaluations. In addition, the Charter of the Compensation Committee establishes that
the Committee shall review and approve written annual and longer-term corporate goals and
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objectives relevant to the compensation of the Chief Executive Officer and other executive officers, making sure that they are
appropriately linked to the Company´s strategy.
In this regard, the Compensation Committee reviews and recommends that the board of directors approve the annual
performance scorecard that contains the performance metrics and objective criteria against which the Chief Executive Officer
and other executive officers are evaluated. Depending on the performance evaluation, the amounts to be paid to the Chief
Executive Officer and other executive officers as annual bonuses are recommended by the Committee and submitted to be
approved by our board of directors. The 2023 performance bonus approved by our board of directors on March 6, 2024,
corresponds to 65% score payout applied to target annual bonus of each executive officer, including the Chief Executive
Officer.
CEO Transition Agreement
Mr. James F. Park (former CEO of the Company and current non-executive member of the board of directors and
consultant of the Company, advising on M&A and strategic matters) has a consulting agreement with the Company, approved
by the board of directors on March 2022, as part of the transition of the CEO position. Such agreement governs his consulting
services and does not provide for payments upon a termination of service (other than previously earned or accrued amounts).
Pursuant to the terms of his transition agreement, James F. Park was provided certain severance benefits, including (i) cash
severance payments, payable in a combination of cash and stock, (ii) accelerated vesting of unvested equity awards, and (iii)
administrative support for 1-2 years, reimbursement for reasonable relocation costs and 12 months of health and life insurance
premiums.
Senior Management Severance
Our board of directors determined that it is in the best interests of the Company and its shareholders to provide certain
members of the Company’s senior management with payments and benefits in connection with certain qualified terminations
and/or in connection with certain change in control scenarios. Therefore, the board of directors approved the adoption of an
Executive Termination and Change in Control Benefits Plan (the “Severance Plan”). In addition, the board of directors
approved an employment agreement with our current CEO, Andrés Ocampo, which provides for severance benefits consistent
with those provided under the Severance Plan.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due
to the executive’s death or disability within 24 months following a change in control, the executive will be entitled to receive
the following, subject to the execution of a release of claims: (i) cash severance in an amount equal to 2 times the sum of (x)
the executive’s annual base salary, (y) the average of any cash bonuses paid in the two years preceding the termination date
and (z) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000; and (ii) to the extent
permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of
employment. In addition, the Severance Plan provides that, in the event an executive has relocated at the Company’s request
and is terminated during the 12 months following the change in control, the executive will be provided the costs for relocation
back to their home country.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due
to the executive’s death or disability, other than in the 24 months following a change in control, then, subject to the execution
of a release of claims, the executive sill be entitled to the following benefits: (i) cash severance in an amount equal to 1.5
times (or, in the case of the CEO, 2 times) the sum of (x) the executive’s annual base salary, (y) the average of any cash
bonuses paid in the two years preceding the termination and (z) an amount equal to the lesser of 15% of the executive’s annual
base salary or US$50,000, and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost,
for 12 months following their termination of employment. In addition, the executive’s unvested equity awards will accelerate
pro-rata (in the case of performance equity awards, subject to achievement of the applicable performance metrics).
Pursuant to the Severance Plan, in the event of a change in control, outstanding performance equity awards will convert
into a number of time-based equity awards based on actual performance through the date of the change in control and, except
as set forth below, will vest in accordance with the awards’ original schedule, subject to the executive’s
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continued service through such date. In the event of a termination of the executive’s employment without cause, resignation
for good reason or termination due to the executive’s death or disability within 24 months following a change in control: (i) all
outstanding time-vesting equity awards will fully accelerate and vest; and (ii) performance equity awards, as converted in
accordance with clause (i) above, will fully accelerate and vest. In the event that the acquiror cashes out outstanding equity
awards at closing of the change in control, then, at closing, (i) performance awards will accelerate, and vest based on actual
performance through the date of the change in control and (ii) all outstanding time-vesting equity awards will fully accelerate
and vest.
GeoPark Limited 2018 Equity Incentive Plan
Given the expiration of our Stock Awards Plan on November 3, 2018, on November 5, 2018, we adopted the 2018 Equity
Incentive Plan (the “Plan”) to motivate and reward those participating employees and executives to perform at the highest
level and to further the best interests of the Company and our shareholders. The Plan is designed as an omnibus plan, pursuant
to which we may grant awards in the form of options, share appreciation rights, restricted shares, restricted stock units,
performance awards, other share-based awards or other cash-based awards throughout the ten (10)-year term of the Plan.
Subject to adjustments as set forth in the Plan, the maximum number of shares available for issuance under the Plan is
5,000,000 shares. The applicable award documentation will set forth the terms and conditions of the awards granted under the
Plan, including, but not limited to, the vesting conditions and the effect on a termination of service or a Change in Control on
awards.
The following table sets forth the common share awards granted to our employees and executive officers under the Plan
which are outstanding as of the date of this annual report:
Number of underlying common shares outstanding
800,000 (1)
215,000 (2)
25,000 (4)
571,984 (5)
197,197 (6)
1,000,000 (7)
5,968 (8)
20,000 (9)
25,000 (10)
351,971 (11)
Grant date
01/01/2020
03/31/2022
03/31/2022
10/01/2022
02/14/2023
01/02/2023
10/01/2023
10/01/2023
01/15/2024
02/14/2024
Vesting date
01/02/2023
03/31/2025 (3)
03/31/2025
01/02/2025
01/02/2026
01/02/2026
01/02/2026
10/01/2026
01/15/2027
01/02/2027
(1) On November 6, 2019, our board of directors approved a share-based compensation program for approximately 800,000
shares to be granted in 2020. Considering the performance conditions, the Compensation Committee determined that
only a total of 152,030 shares have vested. As of December 31, 2023, 61,980 shares have been exercised, with a
remaining amount of 90,050 shares to be exercised.
(2) Awards corresponding to the Retention and Hiring Bonus scheme.
(3) The vesting date is March 31, 2025, or 3 years from grant date.
(4) Service agreement. The awards granted under this agreement vest in three annual installments (March 31, 2023, March
31, 2024, and March 31, 2025). As of December 31, 2023, 8,333 shares have been exercised, with a remaining amount of
16,666 shares to be exercised.
(5) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and
the vesting date of the PSUs will be on January 2, 2025.
(6) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and
the vesting date of the PSUs will be on January 2, 2026.
(7) Awards corresponding to LTIP Employees approved in December 2022. The vesting date of the RSUs is annually during
a three-year period and the vesting date of the PSUs will be on January 2, 2026.
(8) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and
the vesting date of the PSUs will be on January 2, 2026.
(9) Awards corresponding to the Hiring Bonus scheme.
(10) Awards corresponding to the Hiring Bonus scheme.
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(11) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and
the vesting date of the PSUs will be on January 2, 2027.
Currently, we have the following incentive equity programs in place under the Plan: the Stock Awards Program (“Stock
Awards Program”), the Retention and Hiring Bonus Scheme, the Long-Term Incentive Program for Executives (“LTIP
Executives”) and the Long-Term Incentive Program for Employees (“LTIP Employees”).
Employees
Long-Term Incentive Program to Employees (“LTIP Employees”)
In December 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a
new Long-Term Incentive program for employees and new hirings. Main characteristics of the program are:
● All employees (non-top management) and new hirings are eligible.
● 3-year program, with a grant date of January 2, 2023, or the date on which the employees are hired.
● The components of the program are the following:
-
-
-
30% Time-based RSUs: vesting annually ratably in three equal installments;
30% Company Performance: measured over three-year performance period (December 2022-December 2025);
and
40% Absolute Performance Shares: share price at the date of vesting must be higher than the share price at the
date of grant or date of hiring.
● The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026.
Executive officers
Long-Term Incentive Program to Executive Officers (“LTIP Executives”)
In March 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new
Long-Term Incentive program for the executive officers. Main characteristics of the program are:
● All executive officers are eligible.
● Grants are awarded annually to executive officers.
● The components of the program are the following:
-
-
-
20% Time-based Restricted Share Units (RSUs) vesting ratably in three equal installments on each of the first
three anniversaries of the grant date;
35% Relative Performance Share Units based on relative total shareholder return (TSR) and measured over
three-year performance period relative to peer group; and
45% Absolute Performance Share Units (PSUs) based on absolute total shareholder return (TSR) and measured
over three-year performance period.
In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated 571,984 total
shares, to vest during a three-year period. On February 17, 2023, the Compensation Committee approved a new grant,
effective as of February 14, 2023, of 197,197 shares to vest during a three-year period. On February 26, 2024, the
Compensation Committee approved a new grant, effective as of February 14, 2024, of 351,971 shares to vest during a three-
year period.
On January 25, 2023, and February 26, 2024, the Compensation Committee determined that 246,110 and 86,602 shares,
respectively, should be delivered to the participants according to the first and second vesting periods of the abovementioned
grants.
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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 (the “Non-Executive Director Plan”). The Non-
Executive Director Plan was amended and restated in October 2016, when additional 1,000,000 shares were registered as the
maximum number of shares available to be issued under this plan. 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.
Potential dilution resulting from Equity Incentive Compensation Plans
In accordance with the equity awards granted by the Company under its Stock Awards Program and the Plan, as of March
19, 2024, there were 1,850,149 outstanding shares that had been awarded but which had not yet vested, representing
approximately 3.3% of the total issued share capital as of that date.
Stock Ownership Guidelines
In December 2022, to further align the interests of our executive officers with those of the Company’s shareholders, our
board of directors approved minimum stock ownership guidelines applicable to the Company’s executive officers, as
determined by the board of directors. Each such executive officer is required to hold, within five years after the adoption of
the guidelines or, if later, within five years after becoming subject to the policy, a number of shares with an aggregate value of
at least three times his or her annual base salary. Shares beneficially owned by the applicable officer or held in a family trust
established by the applicable executive officer and shares underlying vested equity awards (which, in the case of stock
options, are at- or in-the-money) are taken into account for purposes of determining compliance with these guidelines. Until
an officer has met his or her ownership requirement, he or she is required to retain at least 50% of shares received from the
vesting, settlement or exercise of equity awards (and which remain outstanding after tax withholding and payment of any
applicable exercise price).
C. Board practices
Overview
Directors are expected to provide stewardship to promote the long-term success of the Company. They are expected to
fulfill their fiduciary duties and duty of care in the best interests of the Company, considering the various needs of its
stakeholders (shareholders, employees, communities, suppliers and clients), providing advice to and oversight of
management’s activities. Within its responsibilities, the board of directors oversees the company’s strategic goals; financial
statements, control and risk management; core values, integrity and ethical standards; management and board remuneration
and succession planning, among others. On December 23, 2020, and as amended from time to time, the board of directors
adopted our Corporate Governance Guidelines (available at the Company’s website) to further regulate and enhance the
board’s corporate governance structures and processes.
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 July 19, 2023. Their term expires
on the date of our next annual shareholders’ meeting, to be held in 2024. The board of directors meets regularly throughout the
year, 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 and Corporate
Governance Committee, a Strategy & Risk Committee, a Technical Committee and a SPEED/Sustainability Committee.
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The composition and responsibilities of each board committee are described below. The Nomination and Corporate
Governance Committee annually considers and recommends to the board of directors the membership and the chair of each
board committee. Our board of directors may establish other committees to assist with its responsibilities.
Audit Committee
The Audit Committee is currently composed of three independent directors. The current members of the Audit Committee
are Mr. Robert Bedingfield (who serves as Chairman of the committee), Mr. Constantin Papadimitriou and Ms. Sylvia
Escovar. Mr. Robert Bedingfield is regarded as audit committee financial expert. The Nomination and Corporate Governance
Committee determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou and Ms. Sylvia Escovar are independent, as
such term is defined under SEC rules applicable to foreign private issuers.
The main purposes of the Audit Committee, without prejudice of any additional objectives or functions foreseen in its
charter, are to assist the board of directors in its oversight of: (i) the integrity of the Company’s financial statements and the
company’s accounting and financial reporting processes and financial statement audits; (ii) the independent auditor’s
performance, qualifications and independence; (iii) the Company’s compliance with legal and regulatory requirements and the
company´s ethical standards; and (iv) the performance of the company´s internal audit function.
Compensation Committee
The Compensation Committee is currently composed of four independent directors. The current members of the
compensation committee are Mr. Constantin Papadimitriou (who serves as Chairman of the committee), Mr. Robert
Bedingfield, Mr. Brian F. Maxted and Mr. Somit Varma.
The main purposes of the Compensation Committee, without prejudice of any additional objectives or functions foreseen
in its charter, are to (i) evaluate and recommend for approval by the independent members of the Board the remuneration,
benefits and incentive compensation arrangements for the executive officers of the Company; (ii) establish performance
indicators against which the executive officers of the Company will be evaluated; (iii) evaluate and review the identification,
recruitment and succession planning for the executive officers of the Company; and (iv) review and recommend to the board
of directors any changes to the remuneration of the non-executive directors of the Company.
Nomination and Corporate Governance Committee
The Nomination and Corporate Governance Committee is currently composed of three independent directors. The current
members of the Nomination and Corporate Governance Committee are Mr. Somit Varma (who serves as Chairman of the
committee since November 11, 2021), Ms. Sylvia Escovar and Mr. Robert Bedingfield.
The main purposes of the Nomination and Corporate Governance Committee, without prejudice of any additional
objectives or functions foreseen in its charter, are to (i) review board succession planning, including identifying and selecting
suitable board candidates in accordance with the criteria set forth in its charter and approved by the board of directors; (ii)
review and recommend to the board of directors the membership and Chair of each board Committee; (iii) develop, review
and monitor the Company’s corporate governance guidelines, processes and structures; and (iv) conduct and oversee the board
of directors’ annual evaluation process.
Strategy & Risk Committee
The Strategy & Risk Committee was created in December 2020, and is currently composed of six directors. The current
members of the Strategy & Risk Committee are Mr. James F. Park (who serves as Chairman of the committee), Mr. Constantin
Papadimitriou. Mr. Somit Varma, Mr. Brian F. Maxted, Mr. Andrés Ocampo and Mr. Carlos E. Macellari.
The main purposes of the Strategy and Risk Committee, without prejudice of any additional objectives or functions
foreseen in its Charter, are to assist the Board in (i) its oversight function of understanding the various key risks to which the
Company is exposed, and the interlink between the Company’s strategy and such risks; and (ii) its review of new strategic
opportunities and transactions (including mergers, acquisitions, divestments and similar transactions).
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Technical Committee
The Technical Committee is currently composed of four directors. The current members of the technical committee are
Mr. Brian F. Maxted (who serves as Chairman of the committee), Mr. Carlos E. Macellari, Mr. James F. Park and Mr. Somit
Varma.
The main purposes of the Technical Committee, without prejudice of any additional objectives or functions foreseen in its
Charter, are to assist the Board in fulfilling its responsibilities by providing strategic oversight on specific technical matters
which are beyond the scope or expertise of non-technical Board members to: (i) optimize and assure technical decision
making in existing assets to ensure business performance targets, as defined by the annual corporate scorecard, and long-range
plan goals are achieved, including with respect to the design, execution and delivery of the exploration and appraisal strategy
and plan, as well as the field development programs and drilling/production operations; (ii) review and advise the Board on
the technical analysis of prospective new ventures and/or in conjunction with the Strategy and Risk Committee, potential
corporate merger and acquisition opportunities, as and when required; (iii) provide regular, timely feedback, guidance and
support to the management team and technical staff on all sub-surface matters to facilitate the Board processes related to work
programs and budget planning, execution and reporting, as well as people and business performance review; and (iv) review
and analyze the annual report presented by the management team in relation to the Company’s oil reserves and recommend to
the board of directors to approve its disclosure and publication.
SPEED/Sustainability Committee
The SPEED/Sustainability Committee is currently composed of four directors. The current members of the
SPEED/Sustainability committee are Ms. Marcela Vaca (who serves as Chairman of the committee), Ms. Sylvia Escovar, Mr.
James F. Park and Mr. Andrés Ocampo.
The main purposes of the SPEED/Sustainability Committee, without prejudice of any additional objectives or functions
foreseen in its Charter, are to assist the Board in (i) its guidance and oversight function of the Company’s strategy concerning
the SPEED/Sustainability matters, including the safety of its operations, the initiatives to give back value to stakeholders, the
wellbeing of employees, preservation of the environment, community development, and any other matters related to
sustainability; and (ii) its review of the performance on the topics above.
Liability insurance
We maintain liability insurance coverage for all of our directors and officers, the level of which is reviewed annually.
D. Employees
As of December 31, 2023, we had 470 employees, representing a decrease of 2.5% from December 31, 2022.
The following table sets forth a breakdown of our employees by geographic segment for the periods indicated.
Colombia
Ecuador
Brazil
Chile
Argentina
Corporate
Total
Year ended December 31,
2022
2021
2023
412
5
4
27
15
7
470
388
8
4
49
24
9
482
321
3
4
52
74
9
463
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, 2023, 13 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 19, 2024, members of our board of directors and our executive officers held as a group 9,906,640 of our
common shares and 17.9% of our outstanding share capital.
The following table shows the share ownership of each member of our board of directors and executive officers as of
March 19, 2024.
Shareholder
James F. Park (1)
Sylvia Escovar
Robert Bedingfield
Constantin Papadimitriou
Somit Varma
Brian Maxted
Carlos Macellari
Marcela Vaca
Andrés Ocampo
Jaime Caballero Uribe
Augusto Zubillaga
James Deckelman
Rodolfo Martín Terrado
Mónica Jiménez
Agustina Wisky
Sub-total executive officers' ownership
Total
Common shares
8,817,251
61,610
172,296
73,664
72,876
13,816
13,816
12,656
*
*
*
*
*
*
*
668,655
9,906,640
Percentage of
outstanding
common shares
15.9 %
*
*
*
*
*
*
*
*
*
*
*
*
*
*
1.2 %
17.9 %
Indicates ownership of less than 1% of outstanding common shares.
*
(1) Held by Mr. Park directly and indirectly through GoodRock, LLC. The information set forth above and listed in the table
is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14,
2024. 352,400 of Mr. Park’s shares have been pledged pursuant to lending arrangements.
Certain members of our board of directors have, since the time of our initial public offering in the U.S., entered into
certain pledges of Company securities in order to access some liquidity with respect to those shares and/or to diversify their
holdings. On June 29, 2021, the board of directors, based on the recommendation of the Nomination and Corporate
Governance Committee, revised its Insider Trading Policy with respect to securities pledging and prohibited employees and
directors from pledging Company securities in any circumstance, including by purchasing Company securities on margin or
holding Company securities in a margin account. In the event that an employee or director pledged any Company securities
prior to June 29, 2021, and provided that any such pledges were made in compliance with the Insider Trading Policy of the
Company effective at the time such securities were pledged, the employee or director must terminate any such arrangements
by June 29, 2024.
F. Disclosure of a registrant’s action to recover erroneously awarded compensation
Not applicable.
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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 19, 2024, except for certain
shareholders whose last available data is as of December 31, 2023, or as noted below. The percentages reported herein are
based on the shares outstanding as of March 19, 2024.
Shareholder
James F. Park (1)
Compass Group LLC (2)
Renaissance Technologies LLC (3)
Socoservin Overseas SPF S.à.r.l. (4)
Cobas Asset Management, SGIIC, SA (5)
Gerald E. O’Shaughnessy (6)
Other shareholders
Total
Common shares
8,817,251
3,312,589
3,091,863
2,889,315
2,801,544
2,793,392
31,764,896
55,470,850
Percentage of
outstanding
common shares
15.9 %
6.0 %
5.6 %
5.2 %
5.1 %
5.0 %
57.2 %
100.0 %
(1) 7,305,133 shares are held by GoodRock, LLC, which is controlled by James F. Park. The information set forth above and
listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on
February 14, 2024. 352,400 of Mr. Park´s shares have been pledged pursuant to lending arrangements.
(2) The information listed in the table is based solely on the disclosure set forth in Compass Group LLC´s most recent
Schedule 13G filed with the SEC on February 14, 2024.
(3) The information listed in the table is based solely on the disclosure set forth in Renaissance´s most recent Schedule 13G
filed with the SEC on February 13, 2024.
(4) The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’
most recent Schedule 13G filed with the SEC on July 25, 2023.
(5) The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset
Management’s most recent Schedule 13G filed with the SEC on March 20, 2024.
(6) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP; GPK Holdings, LLC; The Globe
Resources Group, Inc.; and other investment vehicles. The information listed in the table is based solely on the disclosure
set forth in Mr. O´Shaughnessy’s most recent Schedule 13D filed with the SEC on March 15, 2024. 2,700,000 of Mr. O
´Shaughnessy´s shares have been pledged pursuant to lending arrangements.
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 19, 2024, we had 12 registered shareholders, out of which 6 are registered as
U.S. shareholders. 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:
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 officers and director compensation—.”
For further information relating to our related party transactions and balances outstanding as of December 31, 2023, 2022
and 2021, please see Note 34 to our Consolidated Financial Statements.
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C. Interests of Experts and Counsel
Not applicable.
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.
On January 8, 2020, Amerisur received a copy of a claim form issued in the High Court of England and Wales (the
“Court”) by Leigh Day solicitors on behalf of a group of claimants (the “Claimants”) described as members of a farming
community in the department of Putumayo in Colombia, seeking compensation for economic and non-economic damages said
to be caused by alleged environmental contamination and pollution caused by Amerisur’s operations in the region. Following
initial court hearings, an interim freezing order was imposed on Amerisur for a certain amount of its assets located in the
United Kingdom. On November 10, 2020, the freezing order was discharged by agreement between the parties as Amerisur
provided alternative security in the form of a letter of credit. On August 11, 2023, a settlement (the “Settlement”) was signed
between Leigh Day and Amerisur, made on a no-admission of liability basis and included a payment made by Amerisur. All
Claimants represented by Leigh Day agreed to the Settlement. On October 2, 2023, the Court approved the Settlement, the
litigation was discontinued, and the letter of credit was cancelled. For further information on the contingent liability related to
the above, please see Note 29 to our Consolidated Financial Statements.
Dividends and dividend policy
Holders of common shares will be entitled to receive dividends, if any, paid on the common shares.
On March 31, 2023, and May 31, 2023, we paid dividends of US$0.13 per share, on September 7, 2023, we paid
dividends of US$0.132 per share and, on December 11, 2023, we paid dividends of US$0.134 per share.
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.
Under the Companies Act 1981, as amended of Bermuda (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. Under our bye-laws,
each common share is entitled to dividends if, as and when dividends are declared by our board of directors, subject to any
preferred dividend right of the holders of any preference shares, if any.
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—Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of
our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash
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requirements, prospects and other factors” and “—We are a holding company and our only material assets are our equity
interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is
distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us,” as
well as “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
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
Our common shares have been listed on the NYSE under the symbol “GPRK” since February 7, 2014.
D. Selling shareholders
Not applicable.
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 limited by shares incorporated under the laws of Bermuda. We are registered with the
Registrar of Companies in Bermuda under registration number 33273. 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
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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 March 19, 2024, there are 55,470,850 common shares outstanding. All of our issued
and outstanding common shares are fully paid and non-assessable. We also have an employee incentive program (LTIP
Employees and LTIP Executives), pursuant to which we have granted share awards to our executive officers and 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. Under our bye-laws, each common share is entitled to dividends, if, as and when dividends are declared by our board
of directors, subject to any preferred dividend right of the holders of any preference shares, if any. Holders of common shares
have no pre-emptive, redemption, conversion or sinking fund rights. In the event of our liquidation, dissolution or winding up
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.
Board composition
Our bye-laws provide that the minimum number of directors shall be three or such other number as shall be determined
from time to time by our board of directors. In addition, our bye-laws provide that our board of directors shall determine the
maximum size of the board. As per the meeting of the board of directors of GeoPark Limited, which took place on May 10,
2022, the modification of the members of the board of directors was approved and it was determined that the maximum
number of members will be nine. Therefore, the current number of members of the Board is nine.
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.
A director may be removed by the shareholders at any special general meeting by a resolution adopted by 65% or more of
the votes cast at the meeting, provided that notice of the shareholders meeting convened to remove the director is given to the
director. The notice must contain a statement of the intention to remove the director and must be served on
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the director not less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the
motion for his removal.
In addition, our bye-laws provide that our board of directors may remove a director only for cause by the affirmative vote
of at least three-quarters of the board of directors, provided that notice of any such meeting convened for the purpose of
removing a director shall contain a statement of the intention to remove the director and must be served on the director not
less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the motion for his
removal.
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 due to an increase in the maximum number of directors on our board, may be
filled by our board of directors.
Proceedings of board of directors
Our bye-laws provide that our business is to be managed and conducted by 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
The Companies Act authorizes the directors of a company, subject to its bye-laws, to exercise all powers of the company
except those that are required by the Companies Act or the company’s bye-laws to be exercised by the shareholders of the
company. Our bye-laws provide that our business is to be managed and conducted by our board 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 (and officers) 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 Companies Act imposes various duties on directors (and officers) of a company with respect to
certain matters of management and administration of the company. Under Bermuda law, directors (and officers) generally owe
fiduciary duties to the company itself, not to the company’s individual shareholders, creditors or any class thereof.
The 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.
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
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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 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 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
Section 98 of the 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 favour or in which they are acquitted or granted
relief by the Supreme Court of Bermuda pursuant to section 281 of the Companies Act.
We have adopted provisions in our bye-laws that 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. Our bye-laws provide that 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 for any act or failure to
act in the performance of such director’s duties, except in respect of any fraud or dishonesty of such director. Section 98A of
the Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any
loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may
otherwise indemnify such officer or director. We have purchased and maintain a directors’ and officers’ liability policy for
such a purpose.
Meetings of shareholders
Under Bermuda law, the company is required to convene at least one general meeting of shareholders each calendar year
(the “annual general meeting”). However, the members may by resolution waive this requirement, either for a specific year or
period of time, or indefinitely. When the requirement has been so waived, any member may, on notice to the company,
terminate the waiver, in which case an annual general meeting must be called.
Bermuda law provides that a special general meeting of shareholders may be called by the board of directors of a
company and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company
carrying the right to vote at general meetings. Bermuda law also requires that shareholders be given at least five days' advance
notice of a general meeting, but the accidental omission to give notice to any person does not invalidate the proceedings at a
meeting.
Our bye-laws provide that our board of directors may convene an annual general meeting or a special general meeting.
Under our bye-laws, not less than fifteen nor more than sixty days' notice of an annual general meeting or a special general
meeting must be given to each shareholder entitled to vote at such meeting. This notice requirement is subject to the ability
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to hold such meetings on shorter notice if such notice is agreed: (i) in the case of an annual general meeting by all of the
shareholders entitled to attend and vote at such meeting; or (ii) in the case of a special general meeting by a majority in
number of the shareholders entitled to attend and vote at the meeting holding not less than 95% in nominal value of the shares
entitled to vote at such meeting. The quorum required for a general meeting of shareholders is two or more persons present in
person and representing in person or by proxy in excess of 50% of the total issued voting shares in the Company throughout
the meeting, provided that if the Company shall at any time have only one shareholder, one shareholder present in person or
by proxy shall form the quorum. Unless otherwise required by law or by our bye-laws, shareholder action requires a resolution
adopted by the affirmative votes of a majority of votes cast by shareholders at a general meeting at which a quorum is present.
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
shareholders may require a proposal to be submitted to an annual general meeting of shareholders by giving a requisition in
writing to the company. 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 all 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.
Under Bermuda law, the holders of an aggregate of not less than 20% in par value of the company's issued share capital or
any class thereof have the right to apply to the Supreme Court of Bermuda for an annulment of any amendment of the
memorandum of association adopted by shareholders at any general meeting, other than an amendment which alters or
reduces a company's share capital as provided in the Companies Act. Where such an application is made, the amendment
becomes effective only to the extent that it is confirmed by the Bermuda court. An application for an annulment of an
amendment of the memorandum of association must be made within twenty-one days after the date on which the resolution
altering the company's memorandum of association is passed and may be made on behalf of persons entitled to make the
application by one or more of their number as they may appoint in writing for the purpose. No application may be made by
shareholders voting in favour of the amendment.
Business combinations
The amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliated
companies) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its
shareholders. Under the Companies Act, unless the 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
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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.
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 Companies Act or by the 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 security for any debt, liability or obligation of the Company or any third party.
Compulsory Acquisition of Shares Held by Minority Holders
An acquiring party is generally able to acquire compulsorily the common shares of minority holders in the following
ways:
(1) By a procedure under the Companies Act 1981 known as a “scheme of arrangement”. A scheme of arrangement could
be effected by obtaining the agreement of the company and of holders of common shares, representing in the aggregate a
majority in number and at least 75% in value of the common shareholders present and voting at a court ordered meeting held
to consider the scheme of arrangement. The scheme of arrangement must then be sanctioned by the Bermuda Supreme Court.
If a scheme of arrangement receives all necessary agreements and sanctions, upon the filing of the court order with the
Registrar of Companies in Bermuda, all holders of common shares could be compelled to sell their shares under the terms of
the scheme of arrangement.
(2) If the acquiring party is a company it may compulsorily acquire all the shares of the target company, by acquiring
pursuant to a tender offer 90% of the shares or class of shares not already owned by, or by a nominee for, the acquiring party
(the offeror), or any of its subsidiaries. If an offeror has, within four months after the making of an offer for all the shares or
class of shares not owned by, or by a nominee for, the offeror, or any of its subsidiaries, obtained the approval of the holders of
90% or more of all the shares to which the offer relates, the offeror may, at any time within two months beginning with the
date on which the approval was obtained, require by notice any nontendering shareholder to transfer its shares on the same
terms as the original offer. In those circumstances, nontendering shareholders will be compelled to sell their shares unless the
Supreme Court of Bermuda (on application made within a one-month period from the date of the offeror's notice of its
intention to acquire such shares) orders otherwise.
(3) Where one or more parties holds not less than 95% of the shares or a class of shares of a company, such holder(s) may,
pursuant to a notice given to the remaining shareholders or class of shareholders, acquire the shares of such remaining
shareholders or class of shareholders. When this notice is given, the acquiring party is entitled and bound to acquire the shares
of the remaining shareholders on the terms set out in the notice, unless a remaining shareholder, within one month of receiving
such notice, applies to the Supreme Court of Bermuda for an appraisal of the value of their shares. This provision only applies
where the acquiring party offers the same terms to all holders of shares whose shares are being acquired.
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
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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, for instance, 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 to 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 by virtue of which our shareholders waive any claim or right of action that they may
have, both individually and on our behalf, against any director in relation to any action or failure to take action by such
director, including the breach of any fiduciary duty by a director, except in respect of any fraud or dishonesty of such director
or to recover any gain, personal profit or advantage to which such director is not legally entitled.
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 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 our bye-laws with effect on
February 19, 2014, and amended with effect on July 15, 2021. 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 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 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.”
Amalgamations, Mergers and Similar Arrangements. Pursuant to the Companies Act, the amalgamation or merger of a
Bermuda company with another company or corporation (other than certain affiliates) requires the amalgamation or merger
agreement to be approved by the company’s board of directors and 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. The quorum for any such general
meeting must be two or more persons, in person or by proxy, representing more than one-third of the issued shares of the
company. 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 shareholders 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
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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 to 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. See “Item 10—B. Memorandum of association and bye-laws—
Shareholder suits.”
Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they might
have, individually or in the right of the company, against any director for any act or failure to act in performance of such
director’s duties, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or to
recover any gain, personal profit or advantage to which such director is not legally entitled. 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 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 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 judicial 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.
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 in Bermuda. 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, income, any capital asset,
gain or appreciation, or any tax in the nature of estate duty or inheritance, such tax shall not be applicable to us or to any of
our operations or shares, debentures or other obligations, until March 31, 2035, 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. On
December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the
taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of
the last four fiscal years beginning on or after January 1, 2025. We are incorporated in Bermuda as an exempted company and
pay annual Bermuda government fees. In addition, all entities employing individuals in Bermuda
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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, including its
objects and powers, and certain alterations to the memorandum of association. The shareholders have the additional right to
inspect the bye-laws of the company, minutes of general meetings and the company’s audited financial statements, which must
be presented to the annual general meeting. The register of members of a company is also open to inspection by shareholders
and by members of the general public without charge. The register of members is required to be open for inspection for not
less than two hours in any business day (subject to the ability of a company to close the register of members for not more than
thirty days in a year). A company is required to maintain its share register in Bermuda but may, subject to the provisions of the
Companies Act, establish a branch register outside of Bermuda. A company is required to keep at its registered office a register
of directors and officers that is open for inspection for not less than two hours in any business day by members of the public
without charge. A company is also required to file with the Registrar of Companies in Bermuda a list of its directors to be
maintained on a register, which register will be available for public inspection subject to such conditions as the Registrar may
impose and on payment of such fee as may be prescribed. 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 Conyers Corporate Services (Bermuda) 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.
Enforcement of Judgments
We are incorporated as an exempted company limited by shares under the laws of Bermuda, and substantially all of our
assets are located in Colombia, Ecuador, Brazil 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. However, the courts of Bermuda would recognize any final and
conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of
multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement
based thereon provided that (i) 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, (ii) such court
did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the
judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence relevant to the action is
submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct
procedures under the laws of Bermuda.
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
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facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. However, section 281 of the
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.
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, Colombian and Chilean tax
consequences of the acquisition, ownership and disposition of our common shares. The summary is based upon the tax laws of
Bermuda, the United States, Colombia 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. On
December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the
taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of
the last four fiscal years beginning on or after January 1, 2025. 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.
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 U.S. dollar;
● a partnership or other entities classified as partnerships for U.S. federal income tax purposes;
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● a tax-exempt entity, including an “individual retirement account” or “Roth IRA;”
● a person that owns or is deemed to own 10% or more of our shares by vote or value;
● 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. Subject to the passive
foreign investment company rules described below, 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 an established 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
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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 non-U.S. tax is withheld on the sale or disposition of 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 non-U.S. tax. 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 non-U.S. tax on gains may be creditable against the U.S. Holder’s
U.S. federal income tax on foreign-source income from other sources.
The rules governing foreign tax credits are complex. For example, under applicable Treasury regulations, in the absence
of an election to apply the benefits of an applicable income tax treaty, in order for a non-U.S. income tax to be creditable, the
foreign jurisdiction’s income tax rules must be consistent with certain U.S. federal income tax principles, and we have not
determined whether the Chilean or Colombian income tax system meets all these requirements. The IRS has released notices
that provide relief from certain of the provisions of the Treasury regulations described above for taxable years ending before
the date that a notice or other guidance withdrawing or modifying the temporary relief is issued (or any later date specified in
such notice or other guidance). With regards to the possible application of the Chilean or Colombian tax on transfers of shares,
described under "—Chilean tax on transfers of shares" and "—Colombian tax on transfers of shares" below, respectively, you
generally will not be entitled to claim a foreign tax credit for any Chilean or Colombian taxes imposed on gains from taxable
dispositions of our common shares (although it is possible that such taxes may reduce the amount realized on the disposition).
The US-Chile income tax treaty and accompanying protocol (together, the “Treaty”) entered into force on December 19, 2023.
If you qualify for the benefits of the Treaty, with respect to taxes withheld at source, the Treaty will have effect for amounts
paid or credited on or after February 1, 2024. For all other taxes, the Treaty will have effect for taxable periods beginning on
or after January 1, 2024. The rules governing foreign tax credits and the application of the Treaty are complex and, therefore,
you should consult your own tax adviser regarding the creditability or deductibility of any Chilean or Colombian tax on
disposition gains (including any applicable limitations) and the determination of the amount realized in your particular
circumstances.
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
2023, 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.
Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were treated as a PFIC for the taxable year in
which we paid a dividend or the prior taxable year, the preferential dividend rates discussed above with respect to dividends
paid to certain non-corporate U.S. Holders would not apply.
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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
As provided in Decree Law No. 824 of 1974, income tax is triggered 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. Reforms introduced in 2014 imposed 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.
Based on information available to us, (i) no Chilean resident holds 5% or more of our rights to equity, control or profits;
(ii) residents in black-listed jurisdictions do not hold 50% or more of our rights to equity, control or profits; (iii) the Chilean
Assets are not valued at more than UTA 210,000; and (iv) the Chilean Assets do not represent 20% or more of the market
value of the offshore holding companies. 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.
Colombian tax on transfers of shares
In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax set in article 90-3
of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad are
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taxed in Colombia when such transaction represents a transfer of underlying assets located in Colombia. The latter applies
unless (i) shares transferred are listed on a stock exchange recognized by the Colombian Government and no more than 20%
of such shares are owned by a single beneficiary; or (ii) the value of assets indirectly transferred represents less than 20% of
book and/or fair market value of all assets owned by the non-resident entity transferor.
For income tax purposes, indirect transfer shall be assessed at fair market value of the Colombian underlying assets and
the relevant tax basis is the one held in the underlying Colombian asset, which should be calculated based on the Colombian
Tax Code rules. When the underlying assets are held by a Colombian branch, any taxable base determined shall be allocated
first to amortization/depreciation recapture taxed as ordinary income.
When a subsequent indirect transfer is made, the tax basis of the underlying Colombian assets corresponds to the
purchase price paid and allocated to the underlying Colombian assets. However, Decree 1103 clarifies that the tax basis of the
entity owning the underlying asset in Colombia is not stepped up.
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 Colombia.”
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. 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.
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.
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C. Other securities
Not applicable.
D. American Depositary Shares
Not applicable.
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
PART II
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, 2023, 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), which are designed 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. 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, with assistance from other members
of management, have concluded that the disclosure controls and procedures were not effective as of such date due to a
material weakness in internal control over financial reporting, described below.
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
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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.
its
inherent
limitations,
Because of
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.
Under the supervision and with the participation of our management, including our Chief Executive Officer, our Chief
Financial Officer, and our Chief Strategy, Sustainability and Legal Officer, we conducted an evaluation of the effectiveness of
our internal control over financial reporting as of December 31, 2023, based on the criteria established in Internal Control -
Integrated Framework of the Committee of Sponsoring Organizations of the Treadway Commission (2013).
We identified a material weakness in internal control related to ineffective information technology general controls
(ITGCs) over the timely removal of user access upon personnel termination. Our business process controls (both automated
and manual) that are dependent on the affected ITGCs were also deemed ineffective because they could have been adversely
impacted, as we do not have any compensatory control upon the outgoing employees in our ITGC matrix. We believe that
these control deficiencies were a result of (i) IT control processes lacking sufficient documentation such that the successful
operation of ITGCs was overly dependent upon knowledge and actions of certain individuals with IT expertise, (ii)
insufficient training of IT personnel on the importance of ITGCs, and (iii) inadequate risk-assessment processes for the
identification and assessment of changes in IT environments that could impact internal control over financial reporting. Based
on this material weakness, we have concluded that as of December 31, 2023, our internal control over financial reporting was
not effective. Notwithstanding, we have also concluded that the material weakness did not result in any identified
misstatements to the consolidated financial statements, and there were no changes to previously released financial results.
Following identification of the material weakness and prior to filing this annual report on Form 20-F, we completed
substantive procedures for the year ended December 31, 2023. Based on these procedures, management believes that our
consolidated financial statements included in this annual report have been prepared in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards Boards. Our Chief Executive Officer and Chief
Financial Officer have certified that, based on their knowledge, the consolidated financial statements, and other financial
information included in this annual report, fairly present in all material respects the financial condition, results of operations
and cash flows of the Company as of, and for, the periods presented in this annual report. Ernst & Young Audit S.A.S. has
issued an unqualified opinion on our consolidated financial statements. See pages F-2 to F-3 of this annual report.
Remediation
Management has been implementing and continues to implement measures designed to ensure that control deficiencies
contributing to the material weakness are remediated, such that these controls are designed, implemented, and operating
effectively. The remediation actions include: (i) developing a training program addressing ITGCs and related policies,
including educating control owners on the principles and requirements of each control, with a focus on those related to user
access over IT systems impacting financial reporting; (ii) developing and maintaining documentation underlying ITGCs to
promote knowledge transfer upon personnel and function changes; (iii) implementing an IT management review and testing
plan to monitor ITGCs with a specific focus on timely removal of user access to applications systems supporting
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our financial reporting processes upon personnel termination; and (iv) enhanced quarterly reporting on the remediation
measures to the Audit Committee of the board of directors.
As of the date of this annual report, we are implementing remediation actions and we believe that these remediation
actions will remediate the material weakness. However, the weakness will not be considered remediated until the applicable
controls operate for a sufficient period of time and management has concluded, through testing, that these controls are
operating effectively. We expect that the remediation of this material weakness will be completed prior to the end of 2024.
C. Attestation Report of the Registered Public Accounting Firm
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, has been audited
by independent registered public accounting firm, Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited).
Ernst & Young Audit S.A.S., has issued an audit report on the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2023. See pages F-4 to F-5 of this annual report.
D. Changes in Internal Control over Financial Reporting
Except for the material weakness identified and the ongoing implementation of remediation actions as described above,
there have been no changes in the Company’s internal control over financial reporting that occurred during the year ended
December 31, 2023, that have materially affected, or are reasonably likely to materially affect, our internal controls over
financial reporting.
ITEM 16. RESERVED
ITEM 16A. Audit committee financial expert
We have determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou and Ms. Sylvia Escovar are independent,
as such term is defined under SEC rules applicable to foreign private issuers. In addition, Mr. Robert Bedingfield and Ms.
Sylvia Escovar 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. The code of conduct is available
at the Company’s website.
ITEM 16C. Principal Accountant Fees and Services
Our independent registered public accounting firm is Ernst & Young Audit S.A.S. (member of Ernst & Young Global
Limited), beginning with the audit of the year ended December 31, 2023. In 2022, and from 2020, our independent registered
public accounting firm was Pistrelli, Henry Martin y Asociados S.R.L. (member of Ernst & Young Global Limited). See
“ITEM 16F. Change in registrant’s certifying accountant”.
The following table provides detail in respect of audit, audit related, tax and other fees billed by the independent
registered public accounting firm and other member firms of Ernst & Young Global Limited for professional services:
Audit fees
Audit related fees
Tax services fees
Total
138
2023
2022
(in millions of US$)
0.98
0.03
—
1.01
0.94
0.02
0.03
1.00
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Fees are shown net of VAT and other associated tax charges.
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 statutory audits.
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: comfort letters, consents and assistance with and review of documents, accounting consultations and
audits in connection with acquisitions, attestation of services that are not required by statue or regulation and consultation
concerning financial accounting and reporting standards.
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 of directors to be put to shareholders for approval at the Annual General meeting. The Audit
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.
We have recurring programs to repurchase our own shares. The latest renewal took place on November 8, 2023, and
established a program to repurchase up to 10% of our shares outstanding, or approximately 5,611,797 shares, until December
31, 2024. In addition to any repurchases under the aforementioned repurchase program, the company has authority from its
board to repurchase, on a standalone basis, up to US$50 million of our common shares in 2024.
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The following table presents purchases of our common shares by the company and “affiliated purchasers” (as that term is
defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended) during 2023:
2023
January 3, 2023
February 6 to February 28, 2023
March 1 to March 31, 2023
April 4 to April 28, 2023
May 1 to May 30, 2023
June 2 to June 20, 2023
September 12 to September 22, 2023
November 21, 2023
December 14, 2023
Total
Number of
Shares
Purchased
40,000
80,826
521,222
201,305
371,936
508,534
499,765
340,000
510,000
Average Price
Paid per Share
14.17
12.77
11.38
11.21
10.30
9.84
9.91
9.49
8.60
ITEM 16F. Change in registrant’s certifying accountant
Total Number of
Maximum Number (or
Shares Purchased as Approximate Dollar Value) of
Part of Publicly
Announced Plans or
Programs
Shares that May Yet be
Purchased Under the Plans or
Programs
40,000
80,826
521,222
201,305
371,936
508,534
499,765
340,000
510,000
5,010,359 shares
4,929,533 shares
4,408,311 shares
4,207,006 shares
3,835,070 shares
3,326,536 shares
2,826,771 shares
5,271,797 shares
4,761,797 shares
On October 17, 2023, Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited) was appointed as our
independent registered public accounting firm, effective for the consolidated audit for the year ended December 31, 2023,
succeeding Pistrelli, Henry Martin y Asociados S.R.L. (member of Ernst & Young Global Limited), our former independent
registered public accounting firm. The change of our independent registered public accounting firm was made at the request of
the Audit Committee, after careful consideration and evaluation process and was approved by the Audit Committee.
Pistrelli, Henry Martin y Asociados S.R.L. has served as our independent registered public accounting firm since 2020.
Pistrelli, Henry Martin y Asociados S.R.L.’s audit reports on our consolidated financial statements as of and for the past two
fiscal years did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty,
audit scope, or accounting principles. In connection with the audits of the Company's financial statements for each of the two
fiscal years ended December 31, 2022, and in the subsequent interim periods through September 29, 2023, there has been (i)
no disagreements (as defined in Item 16F(a)(1)(iv) of Form 20-F and the related instructions thereto) between us and Pistrelli,
Henry Martin y Asociados S.R.L. on any matter of accounting principles or practices, financial statement disclosure, or
auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Pistrelli, Henry Martin y Asociados
S.R.L., would have caused Pistrelli, Henry Martin y Asociados S.R.L. to make reference to the subject matter in their report.
During the two most recent fiscal years ended December 31, 2022, and in the subsequent interim period prior to the
engagement of Ernst & Young Audit S.A.S. on October 17, 2023, neither we nor anyone acting on our behalf consulted with
Ernst & Young Audit S.A.S. regarding either (i) the application of accounting principles to a specified transaction, either
completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, and
neither a written report nor oral advice was provided to us that Ernst & Young Audit S.A.S. concluded was an important factor
considered by us in reaching a decision as to any accounting, audit or financial reporting issue, (ii) any matter that was the
subject of a disagreement pursuant to Item 16F(a)(1)(iv) of Form 20-F and the related instructions thereto, or (iii) any
reportable event pursuant to Item 16F(a)(1)(v) of Form 20-F.
We have provided Pistrelli, Henry Martin y Asociados S.R.L. with a copy of this Item 16F and have requested and
received from Pistrelli, Henry Martin y Asociados S.R.L. a letter addressed to the SEC stating whether or not Pistrelli, Henry
Martin y Asociados S.R.L. agrees with the above statements. A copy of the letter from Pistrelli, Henry Martin y Asociados
S.R.L. is attached as Exhibit 15.4 to this annual report.
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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 (the “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.
At the date of this annual report, 67% of our board of directors is independent.
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 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
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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.
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 members.
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.
ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
ITEM 16J. Insider trading policies
Not applicable.
ITEM 16K. Cybersecurity
GeoPark prioritizes cybersecurity risk management as an integral part of our overall enterprise risk management model.
Our cybersecurity risk management practices provide a framework for handling cybersecurity threats and incidents and
facilitating coordination across our different departments.
Beginning in 2022, we successfully implemented the NIST framework and established a 24/7 Security Operations Center,
reinforcing our commitment to cybersecurity. This framework includes: the following measures: (i) the inventory and
prioritization of each of the assets connected to the GeoPark network, (ii) the implementation and assessment of the
effectiveness of the necessary controls to protect such assets against cyber threats, (iii) the 24/7 monitoring of cyber threats
and the status of the relevant assets, (iv) the implementation and testing of processes for the mitigation and/or containment of
cyberattacks, (v) cyber-incident management process, and (vi) a recovery plan, should a cyberattack materialize, that
minimizes the impact of such cyberattack on the operations of the company.
Under the NIST framework, we address possible cybersecurity threats associated with third-party service providers by
identifying the dependence of our operations on third-party service providers. We have established cybersecurity requirements
for the provision of services and/or the integration of infrastructures, which are included in the corresponding contractual
documentation with third-party service providers. Additionally, we require our third-party service providers to deliver periodic
information on compliance with said requirements.
In 2023, we reinforced our defenses against cyber threats by enhancing our cybersecurity capabilities with the onboarding
of a new Information Security Manager and creation of an operational security management team. Additionally, we optimize
our platforms using industry-leading protection systems, such as Crowd Strike, Palo Alto firewalls, Multifactor
Authentication, Microsoft Defense, Darktrace, Tanium, DNA Center, Umbrella, GRC, and
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SDWAN. To strengthen our technology infrastructure and enhance data protection practices, we developed a site recovery
solution for critical applications, involving redundant systems in different geographical locations and intercloud backups
across multiple service providers.
Our board of directors has overall oversight responsibility for our risk management and delegates cybersecurity risk
management oversight to the Audit Committee. In this capacity, the Audit Committee reviews and reports to the full board
regarding cybersecurity risks and plans to ensure management has processes in place to identify, evaluate and mitigate
cybersecurity risks. Management is responsible for ongoing risk assessment, monitoring and maintaining cybersecurity
programs, a process led by our corporate IT Director with the support of our Information Security Manager. Our IT Director
and Information Security Manager regularly update the Audit Committee on the company’s cybersecurity programs, risks, and
mitigation strategies. Following our IT Director’s decision to voluntarily exit the company, effective as of February 29, 2024,
we are currently in the process of recruiting a new IT Director with relevant cybersecurity experience and the IT Director’s
responsibilities are being covered in an interim fashion by our Information Security Manager, who, while performing any such
interim duties and until we onboard our new IT Director, will regularly report to our Chief Financial Officer. Our Information
Security Manager holds a master’s degree in computer science and has worked for over 20 years in various information
security and cybersecurity positions with increasing levels of responsibility. He also holds a broad range of cybersecurity-
related certifications such as and among others: (i) Certified Information Systems Auditor (CISA), (ii) Certified Information
Security Manager (CISM), and (iii) Certified in the Governance of Enterprise IT (CGEIT).
In the event a cyberattack materializes, our cyber-incident management process is triggered and an interdisciplinary
committee (which includes our IT Director, our Information Security Manager and the cybersecurity team) is convened. The
interdisciplinary committee is charged with containing the cyberattack in the shortest possible time with the minimum
possible impact to our operations. This process has an escalation matrix where, depending on the infrastructure and
information compromised, management of the incident is scaled to specific roles in the company. Any material incidents are
required to be reported by our IT Director and Information Security Manager to the Audit Committee and the board of
directors.
As part of our risk management process, we seek to determine if there are any risks that have not been identified or that
have not been properly assessed. Accordingly, our IT team and the Information Security Manager conduct annual reviews that
inventory, evaluate, and assess cybersecurity risks, including those related to third-party service providers, at both the
information and operational infrastructure level. With the goal of having an independent judgment, we complement the
internal annual review with the engagement of a third-party cybersecurity expert, with relevant expertise in these kind of
methodologies, risk evaluations and mitigation plans design, who conducts ethical hacking exercises to test: (i) from an
external viewpoint, the paths that an attacker could use to try to compromise our infrastructure and information by simulating
the activity of an attacker using sophisticated tools and expertise, and (ii) from an internal viewpoint, our security operation
center’s capability to detect and contain such simulated attack.
Following the annual review described above, mitigation plans are generated by the Information Security Manager and
approved by the IT director to remove any identified risks or bring them to acceptable levels. Once approved, the IT Director
and the Information Security Manager present the mitigation plans to the Audit Committee. Furthermore, we also engage a
third-party cybersecurity expert for purposes of conducting an annual audit which seeks to assess and evaluate the
effectiveness of cybersecurity controls currently in place. The results of the annual audit are shared with our Audit Committee.
As cyber-threats continue to evolve, we may be required to invest significant additional resources to continue modifying
and enhancing our protective measures and to investigate and remediate any information security vulnerabilities. We have a
cybersecurity insurance policy, and it acknowledges that evolving cyber-threats may require significant additional resources.
In 2023, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect
our business strategy, results of operations, or financial condition. However, despite our efforts, we cannot eliminate all risks
from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident. For more
information about these risks, please see “Risk Factors – Our business could be negatively impacted by cybersecurity threats
and related disruptions.” in this annual report on Form 20-F.
143
Table of Contents
ITEM 17. Financial statements
We have responded to Item 18 in lieu of this item.
ITEM 18. Financial statements
PART III
Financial Statements are filed as part of this annual report, see pages F-1 to F-73 to this annual report.
ITEM 19. Exhibits
1.1
1.2
Exhibit no.
Description
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).
Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1
2.1
2.3
1.4
2.2
1.3
2.4
4.1
(File No. 333-191068) filed with the SEC on September 9, 2013).
Current bye-laws (incorporated herein by reference to Exhibit 1.3 to the Company’s Annual Report on Form 20-F filed with the
SEC on March 31, 2021).
Certificate of Incorporation on Name Change (incorporated herein by reference to Exhibit 1.4 to the Company’s Annual Report on
Form 20-F filed with the SEC on March 31, 2021).
Indenture dated January 17, 2020, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to
Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on April 1, 2020).
First Supplemental Indenture dated August 25, 2021, among GeoPark Limited and GeoPark Colombia S.A.S. and the Bank of New
York Mellon (incorporated herein by reference to Exhibit 2.6 to the Company’s Annual Report on Form 20-F filed with the SEC on
March 31, 2022).
Second Supplemental Indenture dated June 27, 2022, among GeoPark Limited and the Bank of New York Mellon (incorporated
herein by reference to Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on March 30, 2023).
Description of Securities. *
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).
Subsidiaries of GeoPark Limited.*
Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*
Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*
Consent of Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited). *
Consent of Pistrelli, Henry Martin y Asociados (member of Ernst & Young Global Limited). *
Consents of DeGolyer and MacNaughton to use its report.*
Letter of Pistrelli, Henry Martin y Asociados S.R.L., as required by Item 16F of Form 20-F.*
Compensation Recoupment Policy. *
Reserves Report of DeGolyer and MacNaughton dated March 1, 2024, for reserves in Brazil, Chile, Colombia and Ecuador
as of December 31, 2023.*
101.INS
Inline XBRL Instance Document*
101.SCH XBRL Taxonomy Extension Schema Document*
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document*
101.DEF XBRL Taxonomy Extension Definition Linkbase Document*
101.LAB XBRL Taxonomy Extension Label Linkbase Document*
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document*
8.1
12.1
12.2
13.1
13.2
15.1
15.2
15.3
15.4
97.1
99.1
104
104 Cover Page Interactive Data File (formatted in Inline XBRL and included in Exhibit 101)
*
Filed with this Annual Report on Form 20-F.
144
Table of Contents
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.
SIGNATURES
GEOPARK LIMITED
By: /s/ Andrés Ocampo
Name: Andrés Ocampo
Title: Chief Executive Officer and Director
Date: March 27, 2024
145
Table of Contents
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Audited Annual Consolidated Financial Statements—GeoPark Limited
Reports of Independent Registered Public Accounting Firm: Ernst & Young Audit S.A.S. (member of Ernst &
Young Global Limited) located in Bogota, Colombia. PCAOB ID No. 1522.
Report of Independent Registered Public Accounting Firm: Pistrelli, Henry Martin y Asociados S.R.L.
(member of Ernst & Young Global Limited) located in Buenos Aires, Argentina. PCAOB ID No. 1449.
Consolidated Statement of Income and Comprehensive Income for the years ended December 31, 2023, 2022
and 2021.
Consolidated Statement of Financial Position as of December 31, 2023 and 2022.
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2023, 2022 and
2021.
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021.
Notes to the Audited Annual Consolidated Financial Statements.
Page
F-2
F-6
F-7
F-9
F-10
F-11
F-12
F-1
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
GeoPark Limited
Opinion on the Financial Statements
We have audited the accompanying consolidated statement of financial position of GeoPark Limited (the Company) as of
December 31, 2023, the related consolidated statements of income, comprehensive income, changes in equity and cash flows
for the year then ended and the related notes (collectively referred to as the “consolidated financial statements”). In our
opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at
December 31, 2023, and the results of its operations and its cash flows for the year then ended, in conformity with
International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework) and our report dated March 27, 2024 expressed an adverse opinion on the effectiveness of internal control
over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that: (i) relates to accounts or disclosures that
are material to the financial statements and (ii) involved our especially challenging, subjective or complex judgments. The
communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements,
taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the
critical audit matter or on the accounts or disclosures to which it relates.
Impact of estimated proved and probable oil and gas reserves on the depreciation of oil and gas properties
Description of the Matter
As discussed in Note 2.11, the proved and probable reserves are used by the Company in the depreciation of the capitalized
costs of proved oil and gas properties and production facilities and machinery, using the unit-of-production method based on
commercial proved and probable oil and gas reserves, as estimated by independent reserves engineers. As described in Note
10 and 20 to the consolidated financial statements, the carrying value of the Company’s oil and gas properties and production
facilities and machinery was $587 million as of December 31, 2023, and depreciation expense was $108 million
F-2
Table of Contents
for the year then ended. The estimation of proved and probable oil and gas reserves also requires the evaluation of inputs,
including oil and gas prices and quality differentials, historical oil and gas production, royalties and future development and
operating costs, among others.
Auditing the Company’s calculation of depreciation of oil and gas properties was complex because of the use of the work of
the independent reserves engineers and the evaluation of management’s determination of the inputs described above used by
the engineers in estimating proved and probable oil and gas reserves.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls
over its process to calculate depreciation of oil and gas properties, including management’s controls over the completeness
and the accuracy of the financial data provided to the specialists for use in estimating proved and probable oil and gas
reserves.
Our audit procedures included, among others, obtaining the reserves report from the independent reserves engineers and
evaluating the competency and objectivity of the independent reserves engineers and management´s qualified persons
responsible for overseeing the preparation of the reserves estimates through the consideration of their professional
qualifications and experience, as well as the use of generally accepted practices and methodologies in preparing reserves
estimates. Additionally, we evaluated the completeness and accuracy of the financial data and inputs used by the independent
reserves engineers in estimating proved and probable oil and gas reserves by agreeing the inputs to source documentation and
comparing them to historical results. For the future development costs, we also evaluated management’s development plan by
assessing consistency of the development projections with the Company’s drill plan and the availability of capital to develop
such plan. We also tested the mathematical accuracy of the depreciation computations for oil and gas properties, including
testing the underlying data by comparing the proved and probable oil and gas reserves amounts used in the calculations to the
reserves report prepared by the independent reserves engineers.
/s/ ERNST & YOUNG AUDIT S.A.S
Member of Ernst & Young Global Limited
We have served as the Company’s auditor since 2023.
Bogotá, Colombia
March 27, 2024
F-3
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the board of directors of
GeoPark Limited
Opinion on Internal Control over Financial Reporting
We have audited GeoPark Limited’s internal control over financial reporting as of December 31, 2023, based on criteria
established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weakness described
below on the achievement of the objectives of the control criteria, GeoPark Limited (the Company) has not maintained
effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there
is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be
prevented or detected on a timely basis. The following material weakness has been identified and included in management’s
assessment. Management has identified a material weakness in the design and execution of information technology general
controls (ITGCs) over the timely removal of user access upon personnel termination. As a result, application and manual
controls that are dependent on the affected ITGCs were also deemed ineffective.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated statement of financial position of the Company as of December 31, 2023, the related consolidated
statements of income, comprehensive income, changes in equity and cash flows for the year ended December 31, 2023, and
the related notes. This material weakness was considered in determining the nature, timing and extent of audit tests applied in
our audit of the 2023 consolidated financial statements, and this report does not affect our report dated March 27, 2024, which
expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s
Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and
are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) 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 of the company are being made only in accordance with authorizations of management
F-4
Table of Contents
and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to 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.
/s/ ERNST & YOUNG AUDIT S.A.S
Member of Ernst & Young Global Limited
Bogotá, Colombia
March 27, 2024
F-5
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
GeoPark Limited
Opinion on the Financial Statements
We have audited the accompanying consolidated statement of financial position of GeoPark Limited (the Company) as of
December 31, 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows
for each of the two years in the period ended December 31, 2022, and the related notes (collectively referred to as the
“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 2022, and the results of its operations and its cash flows for
each of the two years in the period ended December 31, 2022, in conformity with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board (IASB).
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due
to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
Member of Ernst & Young Global Limited
We served as the Company’s auditor from 2020 to 2023.
Buenos Aires, Argentina
March 8, 2023
F-6
Table of Contents
CONSOLIDATED STATEMENT OF INCOME
Amounts in US$´000
REVENUE
Commodity risk management contracts loss
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Depreciation
Write-off of unsuccessful exploration efforts
Impairment loss for non-financial assets, net
Other (expenses) income (a)
OPERATING PROFIT
Financial expenses
Financial income
Foreign exchange (loss) gain
PROFIT BEFORE INCOME TAX
Income tax expense
PROFIT FOR THE YEAR
Earnings per share (in US$). Basic
Earnings per share (in US$). Diluted
Note
7
8
9
12
13
14
20
20‑37
15
15
15
17
19
19
2023
756,625
—
(232,325)
(11,192)
(43,969)
(13,084)
(120,934)
(29,563)
(13,332)
(21,319)
270,907
(45,815)
6,237
(16,820)
214,509
(103,441)
111,068
1.95
2022
1,049,579
(70,221)
(359,779)
(10,529)
(50,024)
(7,995)
(96,692)
(25,789)
—
527
429,077
(57,073)
3,180
19,725
394,909
(170,474)
224,435
3.78
2021
688,543
(109,191)
(212,790)
(7,891)
(46,828)
(8,730)
(88,969)
(12,262)
(4,334)
(11,739)
185,809
(64,112)
1,652
5,049
128,398
(67,271)
61,127
1.00
1.94
3.75
0.99
(a) Includes results related to business transactions in Chile and Argentina. See Note 36.
The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements.
F-7
Table of Contents
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Amounts in US$´000
Profit for the year
Other comprehensive income:
Items that may be subsequently reclassified to profit or loss
Currency translation differences
Gain on cash flow hedges (a)
Income tax expense relating to cash flow hedges
Other comprehensive profit (loss) for the year
2023
111,068
2022
224,435
2021
61,127
1,624
2,738
(1,369)
2,993
2,121
966
(483)
2,604
(1,438)
—
—
(1,438)
Total comprehensive profit for the year
114,061
227,039
59,689
a) Unrealized result on commodity risk management contracts designated as cash flow hedges. See Note 8.
The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements.
F-8
Table of Contents
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
Amounts in US$´000
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment
Right-of-use assets
Prepayments and other receivables
Other financial assets
Deferred income tax asset
TOTAL NON-CURRENT ASSETS
CURRENT ASSETS
Inventories
Trade receivables
Prepayments and other receivables
Derivative financial instrument assets
Cash and cash equivalents
Assets held for sale
TOTAL CURRENT ASSETS
TOTAL ASSETS
EQUITY
Equity attributable to owners of the Company
Share capital
Share premium
Translation reserve
Other reserves
Retained earnings (Accumulated losses)
TOTAL EQUITY
LIABILITIES
NON-CURRENT LIABILITIES
Borrowings
Lease liabilities
Provisions and other long-term liabilities
Deferred income tax liability
TOTAL NON-CURRENT LIABILITIES
CURRENT LIABILITIES
Borrowings
Lease liabilities
Derivative financial instrument liabilities
Current income tax liabilities
Trade and other payables
Liabilities associated with assets held for sale
TOTAL CURRENT LIABILITIES
TOTAL LIABILITIES
TOTAL EQUITY AND LIABILITIES
Note
2023
2022
20
28
22
25
18
23
24
22
25
25
36
26.1
27
28
29
18
27
28
25
17
30
36
686,824
28,451
3,063
12,564
15,920
746,822
13,552
65,049
25,896
3,775
133,036
28,419
269,727
1,016,549
666,879
37,011
121
12,877
18,943
735,831
14,434
71,794
22,106
967
128,843
—
238,144
973,975
55
111,281
(9,962)
45,116
29,530
176,020
58
134,798
(11,586)
73,462
(81,147)
115,585
488,453
23,387
34,083
64,063
609,986
12,528
8,911
70
44,269
137,817
26,948
230,543
840,529
1,016,549
485,114
22,051
51,947
70,123
629,235
12,528
10,000
19
65,002
141,606
—
229,155
858,390
973,975
The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements.
F-9
Table of Contents
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Amount in US$‘000
Equity as of January 1, 2021
Comprehensive income:
Profit for the year
Other comprehensive loss for the year
Total Comprehensive (loss) profit for the year 2021
Transactions with owners:
Share-based payment (Note 31)
Repurchase of shares (Note 26.1.3)
Cash distribution (Note 26.2)
Total 2021
Balances as of December 31, 2021
Comprehensive income:
Profit for the year
Other comprehensive profit for the year
Total Comprehensive profit for the year 2022
Transactions with owners:
Share-based payment (Note 31)
Repurchase of shares (Note 26.1.3)
Cash distribution (Note 26.2)
Total 2022
Balances as of December 31, 2022
Comprehensive income:
Profit for the year
Other comprehensive profit for the year
Total Comprehensive profit for the year 2023
Transactions with owners:
Share-based payment (Note 31)
Repurchase of shares (Note 26.1.3)
Cash distribution (Note 26.2)
Total 2023
Balances as of December 31, 2023
Attributable to owners of the Company
Share
Share
Translation
Other
Retained
Earnings
(Accumulated
Capital
61
Premium
179,399
Reserve
(12,269)
Reserves
104,485
Losses)
(380,866)
Total
(109,190)
—
—
—
—
(1)
—
(1)
60
—
—
—
1
(3)
—
(2)
58
—
—
—
1
(4)
—
(3)
55
—
—
—
—
(1,438)
(1,438)
—
—
—
61,127
—
61,127
61,127
(1,438)
59,689
1,661
(11,840)
—
(10,179)
169,220
—
—
—
—
— (7,224)
— (7,224)
97,261
(13,707)
4,960
6,621
— (11,841)
(7,224)
—
(12,444)
4,960
(61,945)
(314,779)
—
—
—
—
2,121
2,121
—
483
483
224,435
—
224,435
224,435
2,604
227,039
1,840
(36,262)
—
(34,422)
134,798
—
—
—
—
— (24,282)
— (24,282)
73,462
(11,586)
9,197
11,038
— (36,265)
— (24,282)
(49,509)
115,585
9,197
(81,147)
—
—
—
—
1,624
1,624
—
1,369
1,369
111,068
—
111,068
111,068
2,993
114,061
7,718
(31,235)
—
(23,517)
111,281
—
—
—
—
— (29,715)
— (29,715)
45,116
(9,962)
(391)
7,328
— (31,239)
— (29,715)
(53,626)
176,020
(391)
29,530
The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements.
F-10
Table of Contents
CONSOLIDATED STATEMENT OF CASH FLOWS
Amounts in US$‘000
Cash flows from operating activities
Profit for the year
Adjustments for:
Income tax expense
Depreciation
Loss on disposal of property, plant and equipment
Impairment loss for non-financial assets
Write-off of unsuccessful exploration efforts
Accrual of borrowing’s interests
Borrowings cancellation costs
Amortization of other long-term liabilities
Unwinding of long-term liabilities
Accrual of share-based payment
Foreign exchange loss (gain)
Unrealized gain on commodity risk management contracts
Income tax paid (a)
Changes in working capital (b)
Cash flows from operating activities – net
Cash flows from investing activities
Purchase of property, plant and equipment
Proceeds from disposal of long-term assets
Cash flows used in investing activities – net
Cash flows from financing activities
Proceeds from borrowings
Debt issuance costs paid
Principal paid
Interest paid
Borrowings cancellation and other costs paid
Lease payments
Repurchase of shares
Cash distribution
Payments for transactions with former non-controlling interest
Cash flows used in financing activities – net
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at January 1
Currency translation differences
Cash and cash equivalents at the end of the year
Ending Cash and cash equivalents are specified as follows:
Cash in bank and bank deposits
Cash in hand
Cash and cash equivalents
Note
2023
2022
2021
111,068
224,435
61,127
17
20‑37
20
15
29
15
15
8
5
36
5
5
5
5
5
5
26.1
26.2
103,441
120,934
426
13,332
29,563
30,839
—
(127)
6,456
7,328
19,729
170,474
96,692
73
—
25,789
36,360
5,141
(2,407)
6,026
11,038
(19,725)
— (13,023)
(33,355)
(40,047)
467,471
(115,626)
(26,425)
300,938
67,271
88,969
787
4,334
12,262
44,378
6,308
(223)
5,079
6,621
(5,049)
(463)
(65,273)
(9,351)
216,777
(199,040)
450
(198,590)
(168,808)
15,135
(153,673)
(129,258)
2,700
(126,558)
— 172,174
—
(2,019)
—
—
(274,934)
— (172,522)
(42,592)
(36,514)
(12,908)
(9,118)
(7,518)
(7,851)
(11,841)
(36,265)
(7,224)
(24,282)
—
(3,580)
(190,442)
(286,552)
(100,223)
27,246
(27,500)
—
(10,267)
(31,239)
(29,715)
—
(98,721)
3,627
128,843
566
133,036
100,604
993
128,843
201,907
(1,080)
100,604
133,023
13
133,036
128,831
12
128,843
100,587
17
100,604
(a)
(b)
Includes self-withholding taxes for US$ 35,116,000, US$ 20,767,000 and US$ 12,469,000 in 2023, 2022 and 2021, respectively.
Includes withholding taxes from clients for US$ 27,558,000, US$ 27,256,000 and US$ 16,361,000 in 2023, 2022 and 2021,
respectively.
The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 General Information
GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is
Clarendon House, 2 Church Street, Hamilton HM11, Bermuda.
The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and
production for oil and gas reserves in Colombia, Ecuador and Brazil.
These Consolidated Financial Statements were authorized for issue by the board of directors on March 6, 2024 and have been
approved to be included in our 2023 annual report (Form 20-F) on March 27, 2024.
Note 2 Summary of significant accounting policies
The principal accounting policies applied in the preparation of these Consolidated Financial Statements are set out below.
These policies have been consistently applied to the years presented, unless otherwise stated.
2.1 Basis of preparation
The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with International Financial
Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost
basis, except for the following: certain financial assets and liabilities (including derivative instruments) measured at fair value,
and assets held for sale – measured at fair value less costs to sell.
The Consolidated Financial Statements are presented in thousands of United States Dollars (US$’000) and all values are
rounded to the nearest thousand (US$’000), except in the footnotes and where otherwise indicated.
The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It
also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas
involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the
Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”.
All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise
indicated.
2.1.1 Changes in accounting policy and disclosure
2.1.1.1 New and amended standards and interpretations
The Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or
after January 1, 2023, as follows:
IFRS 17 Insurance Contracts
IFRS 17 Insurance Contracts is a comprehensive new accounting standard for insurance contracts covering recognition and
measurement, presentation, and disclosure.
This new accounting standard replaces IFRS 4 Insurance Contracts. IFRS 17 applies to all types of insurance contracts (i.e.,
life, non-life, direct insurance, and re-insurance), regardless of the type of entity that issues them, as well as certain guarantees
and financial instruments with discretionary participation features. A few scope exceptions will apply.
The overall objective of IFRS 17 is to provide a comprehensive accounting model for insurance contracts that is more useful
and consistent for insurers, covering all relevant accounting aspects. IFRS 17 is based on a general model, supplemented by:
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● a specific adaptation for contracts with direct participation features (the variable fee approach), and
● a simplified approach (the premium allocation approach) mainly for short-duration contracts.
The new standard had no impact on the Consolidated Financial Statements of the Group.
Definition of Accounting Estimates - Amendments to IAS 8
The amendments to IAS 8 clarify the distinction between changes in accounting estimates, changes in accounting policies and
the correction of errors. They also clarify how to use measurement techniques and inputs to develop accounting estimates.
These amendments had no impact on the Consolidated Financial Statements of the Group.
Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS Practice Statement 2
The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements provide guidance to apply
materiality judgements to accounting policy disclosures. The amendments aim to provide accounting policy disclosures that
are more useful by replacing the requirement to disclose their ‘significant’ accounting policies with a requirement to disclose
their ‘material’ accounting policies and adding guidance on how to apply the concept of materiality in making decisions about
accounting policy disclosures.
These amendments had no impact on the Consolidated Financial Statements of the Group.
Deferred Tax related to Assets and Liabilities arising from a Single Transaction – Amendments to IAS 12
The amendments to IAS 12 Income Tax narrow the scope of the initial recognition exception, so that it no longer applies to
transactions that give rise to equal taxable and deductible temporary differences such as leases and decommissioning
liabilities.
These amendments had no impact on the Consolidated Financial Statements of the Group.
International Tax Reform—Pillar Two Model Rules – Amendments to IAS 12
The amendments to IAS 12 have been introduced in response to the OECD’s BEPS Pillar Two model rules and include:
● a mandatory temporary exception to the recognition and disclosure of deferred taxes arising from the jurisdictional
implementation of the Pillar Two model rules,
● disclosure requirements to assist in better understanding the Pillar Two income taxes arising from that legislation,
particularly before its effective date.
The mandatory temporary exception applies immediately. The disclosure requirements apply for annual reporting periods
beginning on or after January 1, 2023, but not for any interim periods ending on or before December 31, 2023.
The amendments had no impact on the Consolidated Financial Statements of the Group.
2.1.1.2 Standards issued but not yet effective
The new and amended standards and interpretations that have been issued, but are not yet effective, as of the date of issuance
of these Consolidated Financial Statements are disclosed below. The Group has not early adopted these new and amended
standards and interpretations, and intends to adopt them, if applicable, when they become effective.
Amendments to IFRS 16: Lease Liability in a Sale and Leaseback
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In September 2022, the IASB issued amendments to IFRS 16 to specify the requirements that a seller-lessee uses in measuring
the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognize any amount of the
gain or loss that relates to the right of use it retains.
The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied
retrospectively to sale and leaseback transactions entered into after the date of initial application of IFRS 16. Earlier
application is permitted, and any earlier application must be disclosed.
The amendments are not expected to have a material impact on the Consolidated Financial Statements of the Group.
Amendments to IAS 1: Classification of Liabilities as Current or Non-current
In January 2020 and October 2022, the IASB issued amendments to paragraphs 69 to 76 of IAS 1 to specify the requirements
for classifying liabilities as current or non-current. The amendments clarify:
● what is meant by a right to defer settlement;
● that a right to defer must exist at the end of the reporting period;
● that classification is unaffected by the likelihood that an entity will exercise its deferral right; and
● that only if an embedded derivative in a convertible liability is itself an equity instrument would the terms of a
liability not impact its classification.
In addition, a requirement has been introduced to require disclosure when a liability arising from a loan agreement is classified
as non-current and the entity’s right to defer settlement is contingent on compliance with future covenants within twelve
months.
The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied
retrospectively. The Group is currently assessing the impact the amendments will have on current practice and whether
existing loan agreements may require renegotiation.
Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7
In May 2023, the IASB issued amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures
to clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements.
The disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects
of supplier finance arrangements on an entity’s liabilities, cash flows and exposure to liquidity risk.
The amendments will be effective for annual reporting periods beginning on or after January 1, 2024. Early adoption is
permitted but would need to be disclosed. The amendments are not expected to have a material impact on the Group’s
Consolidated Financial Statements.
The Enhancement and Standardization of Climate-Related Disclosures for Investors
On March 06, 2024, the Securities and Exchange Commission (SEC) issued the final rule on The Enhancement and
Standardization of Climate-Related Disclosures for Investors. This rule mandates the disclosure of information regarding a
registrant’s climate-related risks that have materially impacted or are reasonably likely to have a material impact on, its
business strategy, results of operations, or financial condition. While compliance with this rule is phased in and not required
for these Consolidated Financial Statements, the Group is currently assessing the impact of this rule and planification efforts
ahead of initial required compliance.
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 forecasted operational and investment funding requirements. Sensitivities are run to reflect latest
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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 the performance of the operations, the Group’s cash position of US$ 133,036,000, the oil hedges to mitigate the
price risk exposure within the next twelve to fifteen months, the deleveraging process executed in 2021 and 2022 (see Note
27), and the fact that its total indebtedness as of December 31, 2023, matures in January 2027, the Directors have formed a
judgement, at the time of approving the Consolidated 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.
Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are
eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset
transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure
consistency with the accounting policies adopted by the Group.
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 Chief Executive
Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy,
Sustainability and Legal Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to
assess performance and allocate resources. Management has determined the operating segments based on these reports.
2.5 Foreign currency translation
2.5.1 Functional and presentation currency
The Consolidated Financial Statements are presented in US Dollars, which is the Group’s presentation currency.
Items included in the Consolidated Financial Statements of each of the Group’s entities are measured using the currency of the
primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group
companies incorporated in Colombia, Ecuador, Chile and Argentina is the US Dollar, meanwhile for the Group´s Brazilian
company the functional currency is the local currency, which is the Brazilian Real.
2.5.2 Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the
transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at
period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the
Consolidated Statement of Income.
The results and financial position of foreign operations that have a functional currency different from the presentation
currency are translated into the presentation currency as follows: assets and liabilities are translated at the closing rate, and
income and expenses are translated at average exchange rates. All resulting exchange differences are recognized in Other
comprehensive income.
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2.6 Joint arrangements
Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures depending on the
contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined
them to be joint operations. The Group combines its share in the joint operations individual assets, liabilities, results and cash
flows on a line-by-line basis with similar items in its Consolidated Financial Statements.
2.7 Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate
of the consideration transferred, which is measured at the acquisition date fair value, and the amount of any non-controlling
interests in the acquiree. For each business combination, the Group elects whether to measure the non-controlling interests in
the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition-related costs are
expensed as incurred and included in administrative expenses.
The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a
substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered
substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organized workforce
with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to
continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay
in the ability to continue producing outputs.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and
designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition
date. This includes the separation of embedded derivatives in host contracts by the acquiree.
Any contingent consideration to be transferred by the acquirer will be recognized at fair value at the acquisition date.
Contingent consideration classified as equity is not remeasured and its subsequent settlement is accounted for within equity.
Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9
Financial Instruments, is measured at fair value with the changes in fair value recognized in the statement of profit or loss in
accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at
each reporting date with changes in fair value recognized in profit or loss.
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount
recognized for non-controlling interests and any previous interest held over the net identifiable assets acquired and liabilities
assumed). If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-
assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the
procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess
of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or
loss.
2.8 Revenue recognition
Revenue from the sale of crude oil and gas is recognized at the point in time when control of the product is transferred to the
customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the
customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of
crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the
contractual arrangements in place.
The Group’s sales of crude oil are priced based on market prices. The sales price is linked to US dollar denominated crude oil
international benchmarks, such as Brent, adjusted for certain marketing and quality discounts based on, among other things,
American Petroleum Institute (“API”) gravity, viscosity, sulphur content, delivery point and transport costs. The Group’s sales
of natural gas are priced based on long-term Gas Supply contracts with customers.
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Revenue is shown net of VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas
properties where the royalty arrangements represent a retained working interest in the property. See Note 33.1.
2.9 Production and operating costs
Production and operating costs are recognized in the Consolidated Statement of Income on the accrual basis of accounting.
These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials
and consumables, rentals, and royalties and economic rights in cash are also included within this account.
2.10 Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities,
and foreign exchange gains and losses. The Group has capitalized the borrowing cost directly attributable to wells and
facilities identified as qualifying assets, if applicable. Qualifying assets are assets that necessarily take a substantial period of
time to get ready for their intended use or sale. The capitalization rate used to determine the amount of borrowing costs to be
capitalized, if any, is the weighted average interest rate applicable to the Group’s general borrowings.
2.11 Property, plant and equipment
Property, plant and equipment are stated at historical cost less depreciation and impairment charges, if applicable. Historical
cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement
obligation.
Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field
by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and
Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of
producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed
immediately to the Consolidated Statement of Income.
Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e., seismic), direct
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 (exploration costs) in the period in which the determination is made, depending on whether they have
discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be
clearly demonstrated that the carrying value of the investment is recoverable.
A charge of US$ 29,563,000 has been recognized in the Consolidated Statement of Income within the ‘Write-off of
unsuccessful exploration efforts’ line item (US$ 25,789,000 in 2022 and US$ 12,262,000 in 2021). See Note 20.
All field development costs are considered construction in progress until they are finished and capitalized within oil and gas
properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of
production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development
purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties.
Workovers of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance
costs are charged to the Consolidated Statement of Income when incurred.
Capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area
by the licensed area basis, using the unit of production method, based on commercial proved and probable oil and gas
reserves. The calculation of the “unit of production” depreciation considers estimated future finding and development costs
and is based on current year-end unescalated price levels. Changes in reserves and cost estimates are recognized prospectively.
Reserves are converted to equivalent units on the basis of approximate relative energy content.
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Depreciation of the remaining property, plant and equipment assets (i.e., furniture and vehicles) not directly associated with oil
and gas activities has been calculated by means of the straight-line method by applying such annual rates as required to write-
off their value at the end of their estimated useful lives. The useful lives range between 3 years and 10 years.
Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow the performance of the
business.
An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater
than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.13).
2.12 Provisions and other long-term liabilities
Provisions for asset retirement obligations and other environmental liabilities, deferred income, restructuring obligations and
legal claims are recognized when the Group has a present legal or constructive obligation as a result of past events, it is
probable that an outflow of resources will be required to settle the obligation, and the amount has been reliably estimated.
Restructuring provisions, if any, comprise lease termination penalties and employee services termination payments.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax
rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in
the provision due to the passage of time is recognized as financial expense.
2.12.1 Asset Retirement Obligation
The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled.
When the liability is initially recorded, the Group capitalizes the cost by increasing the carrying amount of the related long-
lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is
depreciated over the estimated useful life of the related asset. According to interpretations and the application of current
legislation, and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the
environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of
this recalculation are included in the Consolidated 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.
2.12.2 Deferred Income
Government grants and other contributions relating to the purchase of property, plant and equipment are included in non-
current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of
the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the
grant will be received and the Group will comply with all attached conditions.
2.13 Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to
depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable.
An impairment loss is recognized for the excess of the asset’s carrying amount over its recoverable amount. The recoverable
amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets
are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a
licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the
impairment at each reporting date.
No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly
demonstrated that the carrying value of the investment will be recoverable.
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Impairment losses were recognized for US$ 13,332,000 in 2023 (no impairment losses were recognized in 2022 and US$
4,334,000 were recognized in 2021). See Note 37. The write-offs are detailed in Note 20.
2.14 Lease contracts – Group as a lessee
The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to
control the use of an identified asset for a period of time in exchange for consideration.
2.14.1 Right-of-use assets
The Group recognizes right-of-use assets at the commencement date of the lease. Right of use assets are measured at cost, less
any accumulated depreciation and impairment losses, an adjusted for any measurement of lease liabilities.
The cost of right-of-use assets comprise the following:
● the amount of the initial measurement of lease liability,
● any lease payments made at or before the commencement date less any lease incentives received,
● any initial direct costs, and
● restoration costs.
The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of
1 to 15 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of
different terms and conditions. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term
and the estimated useful lives of the assets.
If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a
purchase option, depreciation is calculated using the estimated useful life of the asset. The right-of-use assets are also subject
to impairment.
2.14.2 Lease liabilities
At the commencement date of the lease, the Group recognizes lease liabilities measured at the present value of lease payments
to be made over the lease term. Lease liabilities include the net present value of the following lease payments:
● fixed payments, less any lease incentives receivable,
● variable lease payments that are based on an index or a rate,
● amounts expected to be payable by the lessee under residual value guarantees,
● the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and
● payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
In calculating the present value, the lease payments are discounted using the interest rate implicit in the lease. If that rate
cannot be determined, the Group’s incremental borrowing rate is used, being the rate that the lessee would have to pay to
borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and
conditions. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and
reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a
modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a
change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the
underlying asset.
2.14.3 Short-term leases and leases of low-value assets
The Group applies the short-term lease recognition exemption to its short-term leases of machinery and equipment (i.e., those
leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also
applies the lease of low-value assets recognition exemption to leases of IT equipment and small items of
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office furniture that are considered to be low value. Lease payments on short-term leases and leases of low-value assets are
recognized as expense on a straight-line basis over the lease term.
2.15 Inventories
Inventories comprise crude oil and materials.
Crude oil is measured at the lower of cost and net realizable value. Materials are measured at the lower of cost and recoverable
amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar
costs. Cost is determined using the first-in, first-out (FIFO) method.
2.16 Current and deferred income tax
The tax expense for the year comprises current and deferred income tax. Income tax is recognized in the Consolidated
Statement of Income.
The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the financial
statements date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of
the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution
of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take
several years to complete and, in some cases, it is difficult to predict the ultimate outcome.
Deferred income tax is recognized, using the liability method, on temporary differences arising between the tax bases of assets
and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using
tax rates (and laws) that have been enacted or substantially enacted as of the financial statements date and are expected to
apply when the related deferred income tax asset is realized, or the deferred income tax liability is settled. In addition, the
Group has tax-loss carry-forwards in certain tax jurisdictions that are available to be offset against future taxable profit.
However, deferred income 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
income tax is recognized in respect of the retained earnings of overseas subsidiaries only if at the date of the Consolidated
Financial Statements, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future
has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will
revert in the foreseeable future.
Deferred income tax balances are provided in full, with no discounting.
2.17 Non-current assets or disposal groups held for sale
Non-current assets or disposal groups are classified as held for sale if their carrying amount will be recovered principally
through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at
the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising
from employee benefits, financial assets and investment property that are carried at fair value and contractual rights under
insurance contracts, which are specifically exempt from this requirement.
An impairment loss is recognized for any initial or subsequent write-down of the asset or disposal group to fair value less
costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset or disposal group,
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but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the
date of the sale of the non-current asset or disposal group is recognized at the date of derecognition.
Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified
as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue
to be recognized.
Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented
separately from the other assets in the Consolidated Statement of Financial Position. The liabilities of a disposal group
classified as held for sale are presented separately from other liabilities in the Consolidated Statement of Financial Position.
As of December 31, 2023, the Group classified non-current assets and liabilities corresponding to the Chilean companies as
held for sale due to the divestment process that was agreed to in December 2023 and which closed in January 2024. See Note
36.1.
2.18 Financial assets
Financial assets are divided into the following categories: amortized cost; financial assets at fair value through profit or loss
and fair value through other comprehensive income. The classification depends on the Group’s business model for managing
the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when
its business model for managing those assets changes.
All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs.
Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss.
Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred
and substantially all the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at
each balance sheet date.
Interest and other cash flows resulting from holding financial assets are recognized in the Consolidated Statement of Income
when receivable, regardless of how the related carrying amount of financial assets is measured.
Amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active
market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date.
These are classified as non-current assets. These financial assets comprise trade and other receivables and cash and cash
equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or
services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at
amortized cost using the effective interest method, less provision for impairment, if applicable.
Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of
Income. All of the Group’s financial assets are classified as amortized cost.
2.19 Other financial assets
Non-current other financial assets include contributions made for environmental obligations according to a Colombian and
Brazilian government request and are restricted for those purposes.
Current other financial assets include short-term investments with original maturities up to twelve months and over three
months.
2.20 Impairment of financial assets
The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment
methodology applied depends on whether there has been a significant increase in credit risk. For trade
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receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be
recognized from initial recognition of the receivables.
2.21 Cash and cash equivalents
Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments
with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to
an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the
current liabilities section of the Consolidated Statement of Financial Position.
2.22 Trade and other payables
Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from
suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal
operating cycle of the business if longer). If not, they are presented as non-current liabilities.
Trade payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest
method.
2.23 Derivatives and hedging activities
Derivative financial instruments are recognized in the Consolidated Statement of Financial Position as assets or liabilities and
initially and subsequently measured at fair value. They are presented as current assets or liabilities if they are expected to be
settled within 12 months after the end of the reporting period.
The mark-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market
rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level
2 of the fair value hierarchy.
2.23.1 Cash flow hedges that qualify for hedge accounting
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is
recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion is recognized immediately in
the Consolidated Statement of Income.
When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward
contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the
forward contracts are recognized in Other Reserves within Equity.
Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and
losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost
of the asset.
When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge
accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until
the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer
expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately
reclassified to the Consolidated Statement of Income.
For more information about derivatives designated as cash flow hedges please refer to Note 36.1 and Note 8.
2.23.2 Other Derivatives
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Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that
does not qualify for hedge accounting are recognized immediately in the Consolidated Statement of Income.
For more information about derivatives related to commodity risk management please refer to Note 8 and for more
information about derivatives related to currency risk management please refer to Note 3 Currency risk.
2.24 Borrowings
Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of
the instrument.
Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at
amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the
Consolidated Statement of Income over the period of the borrowings using the effective interest method.
Direct issue costs are charged to the Consolidated Statement of Income on an accrual basis using the effective interest method.
2.25 Share capital
Equity comprises the following:
● "Share capital" representing the nominal value of equity shares.
● "Share premium" representing the excess over nominal value of the fair value of consideration received for equity
shares, net of expenses of the share issuance.
● "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries.
● "Other reserves" representing:
-
-
the difference between the proceeds from transactions with non-controlling interests received against the
book value of the shares acquired in subsidiaries, and
the changes in the fair value of the effective portion of derivatives designated as cash flow hedges.
● "Retained earnings (Accumulated losses)" representing:
-
-
accumulated earnings and losses, and
the equity element attributable to shares granted according to IFRS 2 but not issued at year end.
2.26 Share-based payment
The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to
employees and other third-party contractors. Share-based payment transactions are measured in accordance with IFRS 2.
The fair value of the share awards payments is determined at the grant date by reference to the market value of the shares,
calculated using the Geometric Brownian Motion method or the Monte Carlo simulation, and recognized as an expense over
the vesting period.
Service and non-market performance conditions are not taken into account when determining the grant date fair value of
awards, but the likelihood of the conditions being met is assessed as part of the Group’s best estimate of the number of equity
instruments that will ultimately vest. Market performance conditions are reflected within the grant date fair value. Any other
conditions attached to an award, but without an associated service requirement, are considered to be non-vesting conditions.
Non-vesting conditions are reflected in the fair value of an award and lead to an immediate expensing of an award unless there
are also service and/or performance conditions.
No expense is recognized for awards that do not ultimately vest because non-market performance and/or service conditions
have not been met. Where awards include a market or non-vesting condition, the transactions are treated as vested irrespective
of whether the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are
satisfied.
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At each reporting date, the entity revises its estimates of the number of options that are expected to vest. It recognizes the
impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment
to equity.
When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable
transaction costs are credited to share capital (nominal value) and share premium.
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
The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are
managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is
described in more detail below.
Currency risk
In Colombia, Ecuador, Chile and Argentina the functional currency is the US Dollar. The fluctuation of the local currencies of
these countries against the US Dollar, except for Ecuador where the local currency is the US Dollar, does not impact the loans,
costs and revenue held in US Dollars; but it does impact receivables or payables originated in local currency mainly
corresponding to VAT and income tax.
The Group minimises the local currency positions in Colombia, Chile and Argentina by seeking to balance local and foreign
currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore, the
Group maintains a net exposure to them, except for what it is described below.
From time to time, the Group enters into derivative financial instruments in order to anticipate any currency fluctuation with
respect to income taxes to be paid during the first half of the following year. No currency risk management contracts were in
place as of December 31, 2023, and onwards. In January 2023, GeoPark entered into derivative financial instruments (zero-
premium collars) with local banks in Colombia, for an amount equivalent to US$ 38,000,000 in order to anticipate any
currency fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023.
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 2023, the Colombian Peso revalued by 21% (devalued by 21% and 16% in 2022 and 2021, respectively), the Chilean
Peso devalued by 3% (1% and 19% in 2022 and 2021, respectively), and the Argentine Peso devalued by 356% (72% and
22% in 2022 and 2021, respectively), all against the US Dollar.
If the Colombian Peso, the Chilean Peso, and the Argentine Peso had each devalued an additional 10% against the US dollar,
with all other variables held constant, post-tax profit for the year would have been higher by US$ 13,971,000 (US$
14,695,000 in 2022 and US$ 9,070,000 in 2021).
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
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balances denominated in US Dollars. Such is the case of the provision for asset retirement obligation and the lease liabilities.
During 2023, the Brazilian Real revalued by 7% against the US Dollar (revalued by 7% in 2022 and devalued by 7% 2021). If
the Brazilian Real had devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit
for the year would have been lower by US$ 728,000 (US$ 726,000 in 2022 and US$ 780,000 in 2021).
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 realized oil price for the Group is linked to US dollar denominated crude oil international benchmarks. The market price
of this commodity is subject to significant volatility and has historically fluctuated widely in response to relatively minor
changes in the global supply and demand for oil, the geopolitical landscape, armed conflicts, the economic conditions and a
variety of additional factors. The main factors affecting realized prices for gas sales vary across countries with some closely
linked to international references while others are more domestically driven.
In Colombia, the realized oil price is linked to either the Vasconia crude reference price, a marker broadly used in the Llanos
Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of
the Putumayo Basin that is transported through Ecuador. In both basins, the reference price is then adjusted for certain
marketing and quality discounts based on, among other things, API, viscosity, sulphur content, delivery point and transport
costs.
In Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles Oriente
crude reference.
In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of
gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian
General Market Price Index (Indice Geral de Preços do Mercado), or IGPM.
In Chile, the oil price was linked to Dated Brent minus certain marketing and quality discounts such as, API, sulphur content
and others. The gas price, under a long-term Gas Supply Contract with Methanex, was determined by a formula that considers
a basket of international methanol prices, including US and European price indices.
If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant,
considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$
42,393,000 (US$ 47,330,000 in 2022 and US$ 17,899,000 in 2021).
GeoPark seeks to partially mitigates its exposure to crude oil price volatility using derivatives by hedging a portion of its
production for a limited period going forward. The Group uses a combination of options to manage its exposure to commodity
price risk, which considers forecasted production and budget price levels, among other factors. GeoPark has also obtained
credit lines from different counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8).
Credit risk– concentration
The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognized values of
commodities sold or hedged. GeoPark considers that there is no significant risk associated to the Group’s major customers and
hedging counterparties.
In Colombia, GeoPark allocates its sales on a competitive basis to industry leading participants including traders and other
producers. During 2023, the oil and gas production was sold to three clients which concentrate 96% of the Colombian
subsidiaries’ revenue, accounting for 89% of the consolidated revenue (97% and 99% of the Colombian subsidiaries’
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revenue, accounting for 90% and 89% of the consolidated revenue in 2022 and 2021). Delivery points include wellhead and
other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is
delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador
that affect the transport through the Ecuadorian pipeline system. The outstanding contracts for Colombian production extend
through the first half of 2024. GeoPark manages its counterparty credit risk associated to sales contracts by periodic evaluation
of the counterparties’ credit profile and, in certain contracts, including early payment conditions to minimize the exposure.
In Ecuador, oil is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of the
sales are exported on a competitive basis to industry leading participants including traders and other producers. Sales of crude
oil in Ecuador accounted for 3% of the consolidated revenue in 2023 (1% in 2022).
In Brazil, all the gas from the Manati Block is sold to Petrobras, the State-owned company, which is also the operator of the
Manati Field (2% of the consolidated revenue in 2023 and 2022, and 3% in 2021).
In Chile, the oil production was sold to ENAP, the State-owned oil and gas company (1% of the consolidated revenue in 2023,
2022 and 2021), and the gas production was sold to the local subsidiary of Methanex, a Canadian public company (1% of the
consolidated revenue in 2023 and 2022, and 2% in 2021).
GeoPark Limited has entered into a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes
purchased are transported and exported alongside the Group’s Putumayo Basin production. Sales of crude oil purchased from
third parties accounted for 1% of the consolidated revenue in 2023 and 2022.
The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do
not consider there to be a significant collection risk.
GeoPark executes oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect
from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions
and trading companies; therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes
8 and 25.
Funding and Liquidity risk
In the past, the Group has been able to raise capital through different sources of funding including equity, strategic
partnerships and financial debt.
The Group is positioned at the end of 2023 with a cash balance of US$ 133,036,000, and has access to a US$ 80,000,000
senior unsecured credit facility with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A., and to
US$ 179,600,000 in uncommitted credit lines, and its total indebtedness matures in January 2027. In addition, the Group has a
large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 38,000 boepd
in production at year end. This scale and positioning permit the Group to protect its financial condition and selectively allocate
capital to the optimal projects subject to prevailing macroeconomic conditions.
The Indentures governing the Company Notes 2027 include incurrence test covenants related to compliance with certain
thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the
incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur
additional indebtedness, as specified in the indentures governing the Notes. As of the date of these Consolidated Financial
Statements, the Group is in compliance with all the indentures’ provisions and covenants.
Interest rate risk
The Group’s interest rate risk could arise from long-term borrowings issued at variable rates, which would expose the Group
to interest rate risk.
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Table of Contents
The Group does not currently face interest rate risk on its US$ 500,000,000 Notes which carry a fixed rate coupon of 5.50%
per annum and mature in January 2027. Consequently, the accruals and interest payments are not substantially affected by
changes in prevailing interest rates.
As of December 31, 2023, there were no outstanding borrowings affected by a variable rate.
Capital risk
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. The Group manages its capital structure and makes adjustments in light of changes in economic conditions,
operating risks and working capital requirements. To maintain or adjust its capital structure, the Group may issue or buy back
shares, change its dividend policy, raise or refinance debt and/or adjust its capital expenditures to manage its operating and
growth objectives. Additionally, the Group utilizes a planning, budgeting and forecasting process to help determine and
monitor the funds needed to maintain appropriate liquidity for operational, capital and financial needs.
As of December 31, 2023 and 2022, GeoPark is in compliance with the debt covenant ratios associated with the Company´s
Notes due 2027. See Note 27.
The following table summarizes the Group’s capital structure balances:
Amounts in US$‘000
Total Equity
Net Debt (a)
Working capital (b)
2023
176,020
367,945
39,184
2022
115,585
368,799
8,989
(a) Calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the Consolidated Statement of
Financial Position) less cash and cash equivalents.
(b) Calculated as ‘current assets’ less ‘current liabilities’.
Note 4 Accounting estimates and assumptions
Estimates and assumptions are used in preparing financial statements. Although these estimates are based on management’s
best knowledge of current events and actions, actual results may differ. Estimates and judgements are continually evaluated
and are based on historical experience and other factors, including expectations of future events that are believed to be
reasonable under the circumstances.
The key estimates and assumptions used in these Consolidated Financial Statements are noted below:
● The process of estimating reserves is complex. It requires significant judgements and decisions based on available
geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural
gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2023,
prepared by DeGolyer and MacNaughton Corp., an independent international oil and gas consulting firm based in
Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum
Resources Management Reporting System (PRMS) framework.
It incorporates many factors and assumptions including:
o
o
o
o
o
o
expected reservoir characteristics based on geological, geophysical and engineering assessments;
future production rates based on historical performance and expected future operating and investment activities;
future oil and gas prices and quality differentials;
assumed effects of regulation by governmental agencies;
tax rates by jurisdiction; and
future development and operating costs.
F-27
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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.
Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of
exploration and evaluation assets; oil and gas properties and other property, plant and equipment; may be affected due
to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of
Income may change where such charges are determined using the unit of production method, or where the useful life
of the related assets change, (c) provisions for abandonment may require revision -where changes to reserves
estimates affect expectations about when such activities will occur and the associated cost of these activities- and, (d)
the recognition and carrying value of deferred income tax assets may change due to changes in the judgements
regarding the existence of such assets and in estimates of the likely recovery of such assets.
● Cash flows estimates for impairment assessments of non-financial assets require assumptions about three primary
elements: future prices, reserves and discount rate. Estimates of future prices require significant judgments about
highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s
forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts
and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and
operating and development costs. Given the significant assumptions required and the possibility that actual
conditions may differ, management considers the assessment of impairment to be a critical accounting estimate (see
Note 37).
● The Group adopted the successful efforts method of accounting. The Management of the Group makes assessments
and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such
when insufficient information exists. This assessment is made on a quarterly basis considering the advice from
qualified experts.
The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to
determine whether future economic benefits are likely from future either exploitation or sale, or whether activities
have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of
reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on
how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation
expenditure. The deferral policy requires management to make certain estimates and assumptions about future events
and circumstances, in particular, whether an economically viable extraction operation can be established. Any such
estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized,
information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized
amount is written-off in the Consolidated Statement of Income in the period when the new information becomes
available.
● Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”)
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. This
results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block.
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present
assessments of economically recoverable reserves of the block at which the asset is located. These calculations
require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future
capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual
production in the future is different from current forecast production based on total proved and probable reserves, or
future capital expenditure estimates change. Changes to proved and probable reserves could arise due to
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changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved and probable
reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen
operational issues.
● Obligations related to the abandonment of wells once operations are terminated may result in the recognition of
significant obligations. Estimating the future abandonment costs is difficult and requires management to make
estimates and judgments because most of the obligations are many years in the future. Technologies and costs are
constantly changing as well as political, environmental, safety and public relations considerations. The Group has
adopted the following criterion for recognizing well plugging and abandonment related costs: the present value of
future costs necessary for well plugging and abandonment is calculated for each area at the present value of the
estimated future expenditure. The liabilities recognized are based upon estimated future abandonment costs, wells
subject to abandonment, time to abandonment, and future inflation rates.
The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil
and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and
assumptions are made in determining the provision for decommissioning. As a result, there could be significant
adjustments to the provisions established which would affect future financial results.
The provision at reporting date represents management’s best estimate of the present value of the future abandonment
costs required.
● From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal
course of business, including employment, commercial, tax, environmental, safety and health matters. For example,
from time to time, the Group receives notice of environmental, health and safety violations. Based on what the
Group’s Management currently knows, such claims are not expected to have a material impact on the Consolidated
Financial Statements.
Note 5 Consolidated Statement of Cash Flows
The Consolidated Statement of Cash Flows shows the Group’s cash flows for the year for operating, investing and financing
activities and the change in cash and cash equivalents during the year.
Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes
in net working capital and corporate tax. Income tax paid is presented as a separate item under operating activities.
Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and
equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any.
Cash flows from financing activities include changes in equity and proceeds from borrowings and repayment of loans.
Cash and cash equivalents include bank overdraft, if any, and liquid funds with a term of less than three months.
The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flows:
Amounts in US$‘000
Increase (Decrease) in asset retirement obligation
Increase (Decrease) in provisions for other long-term liabilities
Purchase of property, plant and equipment
Additions / changes in estimates of right-of-use assets
2023
7,374
2,370
(7,864)
137
2022
(4,942)
(2,616)
7,864
22,462
2021
(651)
(443)
—
5,288
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Changes in working capital shown in the Consolidated Statement of Cash Flows are disclosed as follows:
Amounts in US$‘000
(Increase) Decrease in Inventories
Decrease (Increase) in Trade receivables
Increase in Prepayments and other receivables and Other assets (a)
Increase (Decrease) in Trade and other payables
2023
(1,330)
6,820
(33,328)
1,413
(26,425)
2022
(6,694)
(1,425)
(30,929)
(999)
(40,047)
2021
1,241
(23,290)
(13,817)
26,515
(9,351)
(a)
Includes withholding taxes from clients for US$ 27,558,000, US$ 27,256,000 and US$ 16,361,000, in 2023, 2022 and
2021, respectively.
The following chart shows the movements in the borrowings and lease liabilities for each of the periods presented:
Amounts in US$‘000
As of January 1, 2021
Proceeds from borrowings
Debt issuance costs paid
Addition to lease liabilities
Accrual of borrowing's interests
Exchange difference
Foreign currency translation
Unwinding of discount
Principal paid
Interest paid
Borrowings cancellation costs
Borrowings cancellation and other costs paid
Lease payments
As of December 31, 2021
Addition to lease liabilities
Accrual of borrowing's interests
Exchange difference
Foreign currency translation
Unwinding of discount
Principal paid
Interest paid
Borrowings cancellation costs
Borrowings cancellation and other costs paid
Lease payments
As of December 31, 2022
Addition to lease liabilities
Accrual of borrowing's interests
Exchange difference
Liabilities associated with assets held for sale (Note 36.1)
Foreign currency translation
Unwinding of discount
Interest paid
Lease payments
As of December 31, 2023
F-30
Borrowings
784,586
172,174
(2,019)
—
44,323
(581)
(265)
—
(274,934)
(42,592)
6,308
(12,908)
—
674,092
—
36,360
—
203
—
(172,522)
(36,514)
5,141
(9,118)
—
497,642
—
30,839
—
—
—
—
(27,500)
—
500,981
Lease
Liabilities
22,347
—
—
5,288
—
(365)
(461)
1,453
—
—
—
—
(7,518)
20,744
22,462
—
Total
806,933
172,174
(2,019)
5,288
44,323
(946)
(726)
1,453
(274,934)
(42,592)
6,308
(12,908)
(7,518)
694,836
22,462
36,360
(6,426)
(6,426)
284
2,838
—
—
—
—
(7,851)
32,051
137
—
7,061
(26)
174
3,168
—
(10,267)
32,298
487
2,838
(172,522)
(36,514)
5,141
(9,118)
(7,851)
529,693
137
30,839
7,061
(26)
174
3,168
(27,500)
(10,267)
533,279
Table of Contents
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 Chief Executive
Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy,
Sustainability and Legal Officer and Chief People Officer. 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 (loss) for the period (determined as if IFRS 16 Leases has not been adopted), before net
finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of
unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts,
geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Other information
provided to the Executive Committee is measured in a manner consistent with that in the Consolidated Financial Statements.
Segment areas (geographical segments)
Amounts in US$ ‘000
2023
Revenue
Sale of crude oil
Sale of purchased crude oil
Sale of gas
Commodity risk management contracts
designated as cash flow hedges
Production and operating costs
Royalties in cash
Economic rights in cash
Share-based payment
Other operating costs
Adjusted EBITDA
Depreciation
Recognition of impairment losses
Write-off of unsuccessful exploration efforts
Total assets
Employees (average) (a)
Employees at year end (a)
Colombia Ecuador Brazil
Chile (b)
Argentina Corporate
Total
14,019
490
—
13,529
—
(4,946)
(1,096)
—
—
(3,850)
6,374
(2,332)
—
—
27,891
4
4
15,644
5,052
—
10,592
—
(8,226)
(548)
—
(72)
(7,606)
4,952
(9,815)
(13,332)
—
36,192
33
27
—
—
—
—
—
—
—
—
—
—
(2,620)
(22)
—
—
357
18
15
5,464
—
5,464
—
—
(4,666)
—
—
—
(4,666)
(8,838)
(3)
—
—
15,873
8
7
756,625
726,947
5,464
25,024
(810)
(232,325)
(12,845)
(72,032)
(750)
(146,698)
451,862
(120,934)
(13,332)
(29,563)
1,016,549
469
470
702,401
702,308
—
903
(810)
(204,245)
(11,201)
(72,032)
(671)
(120,341)
446,835
(101,666)
—
(29,563)
895,900
400
412
19,097
19,097
—
—
—
(10,242)
—
—
(7)
(10,235)
5,159
(7,096)
—
—
40,336
6
5
F-31
Table of Contents
Amounts in US$ ‘000
2022
Revenue
Sale of crude oil
Sale of purchased crude oil
Sale of gas
Realized loss on commodity risk
management contracts
Production and operating costs
Royalties in cash
Economic rights in cash
Share-based payment
Other operating costs
Adjusted EBITDA
Depreciation
Write-off of unsuccessful exploration efforts
Total assets
Employees (average) (a)
Employees at year end (a)
Amounts in US$ ‘000
2021
Revenue
Sale of crude oil
Sale of gas
Realized loss on commodity risk
management contracts
Production and operating costs
Royalties in cash
Economic rights in cash
Share-based payment
Other operating costs
Adjusted EBITDA
Depreciation
Recognition of impairment losses
Write-off of unsuccessful exploration efforts
Total assets
Employees (average) (a)
Employees at year end (a)
(a) Unaudited.
(b) Divested in January 2024. See Note 36.1.
Colombia Ecuador Brazil
Chile (b)
Argentina Corporate
Total
978,423
977,184
—
1,239
(83,244)
(327,626)
(60,314)
(188,989)
(843)
(77,480)
525,593
(78,775)
(21,318)
797,390
362
388
10,671
10,671
—
—
—
(3,220)
—
—
(10)
(3,210)
4,197
(788)
(4,471)
35,690
7
8
19,873
796
—
29,196
14,460
—
19,077
14,736
—
(5,299)
(1,546)
—
—
(3,753)
11,654
(2,796)
—
34,329
5
4
—
(14,126)
(1,165)
—
(103)
(12,858)
11,753
(14,076)
—
63,379
53
49
1,962
1,664
—
298
—
(1,579)
(273)
—
1
(1,307)
(3,643)
(254)
—
1,296
33
24
9,454
1,049,579
— 1,004,775
9,454
—
—
(7,929)
—
—
—
(7,929)
(8,775)
(3)
—
41,891
9
9
9,454
35,350
(83,244)
(359,779)
(63,298)
(188,989)
(955)
(106,537)
540,779
(96,692)
(25,789)
973,975
469
482
Colombia Ecuador Brazil
Chile (b)
Argentina Corporate Total
618,268
616,133
2,135
(109,654)
(178,384)
(33,385)
(72,956)
(334)
(71,709)
294,847
(61,279)
—
(7,827)
689,401
308
321
—
—
—
—
—
—
—
—
—
(2,071)
(200)
—
—
7,782
8
3
20,109
661
19,448
—
(4,596)
(1,575)
(67)
—
(2,954)
12,569
(4,082)
—
—
38,846
4
4
21,471
6,297
15,174
—
(11,050)
(770)
—
(31)
(10,249)
7,639
(14,275)
(17,641)
(4,435)
71,515
55
52
28,695
24,468
4,227
—
(18,760)
(4,270)
—
26
(14,516)
2,124
(9,130)
13,307
—
38,111
92
74
—
—
—
688,543
647,559
40,984
— (109,654)
— (212,790)
(40,000)
—
(73,023)
—
(339)
—
(99,428)
—
300,800
(14,308)
(88,969)
(3)
(4,334)
—
(12,262)
—
895,741
50,086
476
9
463
9
In 2023, approximately 89% of capital expenditure was incurred by Colombia (82% in 2022 and 93% in 2021) and 11% was
incurred by Ecuador (11% in 2022 and 4% in 2021). No capital expenditure was incurred by Chile in 2023 (7% in 2022 and
3% in 2021).
F-32
Table of Contents
A reconciliation of total Adjusted EBITDA to total profit (loss) before income tax is provided as follows:
Amounts in US$ ‘000
Adjusted EBITDA
Unrealized gain on commodity risk management contracts
Depreciation (a)
Share-based payment
Impairment and write-off of unsuccessful exploration efforts, net
Lease accounting - IFRS 16
Others (b)
Operating profit
Financial expenses
Financial income
Foreign exchange (loss) gain
Profit before tax
2023
451,862
—
(120,934)
(7,328)
(42,895)
10,267
(20,065)
270,907
(45,815)
6,237
(16,820)
214,509
2022
540,779
13,023
(96,692)
(11,038)
(25,789)
7,851
943
429,077
(57,073)
3,180
19,725
394,909
2021
300,800
463
(88,969)
(6,621)
(16,596)
7,518
(10,786)
185,809
(64,112)
1,652
5,049
128,398
(a) Net of capitalized costs for oil stock included in Inventories.
(b)
Includes allocation to capitalized projects. In 2023, also includes termination and other costs incurred because of the
divestment process in Chile, including a provision for investment commitments maintained by GeoPark after the
transaction, for a total amount of US$ 9,742,000 (see Note 36.1), together with the amount paid for transferring the
working interest in the Los Parlamentos Block in Argentina to the joint operation partner for US$ 7,023,000 (see Note
36.2), and others. In 2022, also includes gain from the sale of the Aguada Baguales, El Porvenir and Puesto Touquet
Blocks in Argentina. In 2021, also includes termination costs and write-down of tax credits in Argentina.
Note 7 Revenue
Amounts in US$ ‘000
Sale of crude oil
Sale of purchased crude oil
Sale of gas
Commodity risk management contracts designated as cash flow hedges (a)
2023
726,947
5,464
25,024
(810)
756,625
2022
1,004,775
9,454
35,350
—
1,049,579
2021
647,559
—
40,984
—
688,543
(a) Realized result on commodity risk management contracts designated as cash flow hedges. See Note 8.
Note 8 Commodity risk management contracts
The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are
zero-premium collars 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 that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were
accounted for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were
recognized immediately as gains or losses in the results of the periods in which they occurred as part of the ‘Commodity risk
management contracts’ line item in the Consolidated Statement of Income.
The table below summarizes the results on non-hedge derivative commodity risk management contracts:
Realized loss on commodity risk management contracts
Unrealized gain on commodity risk management contracts
2023
2022
— (83,244)
— 13,023
— (70,221)
2021
(109,654)
463
(109,191)
F-33
Table of Contents
The Group’s derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, onwards are
designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are
recognized in ‘Other Reserves’ within ‘Equity’. The gain or loss relating to the ineffective portion, if any, is recognized
immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in ‘Other Reserves’
is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash
flows affect profit or loss as part of the ‘Revenue’ line item in the Consolidated Statement of Income.
The following table presents the Group’s production hedged during the year ended December 31, 2023, and for the following
periods as a consequence of the derivative contracts in force as of December 31, 2023:
Period
January 1, 2023 - March 31, 2023
April 1, 2023 - June 30, 2023
July 1, 2023 - September 30, 2023
October 1, 2023 - December 31, 2023
January 1, 2024 - March 31, 2024
April 1, 2024 - June 30, 2024
July 1, 2024 - September 30, 2024
October 1, 2024 - December 31, 2024
Reference
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
ICE BRENT
Type
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Zero Premium Collars
Volume bbl/d Weighted average price US$/bbl
9,500
10,000
9,000
9,000
8,500
9,000
7,000
1,000
66.05 Put 112.59 Call
69.25 Put 110.56 Call
70.00 Put 94.69 Call
69.44 Put 91.82 Call
65.59 Put 92.04 Call
67.50 Put 96.99 Call
66.43 Put 99.32 Call
70.00 Put 96.00 Call
Note 9 Production and operating costs
Amounts in US$ '000
Staff costs (Note 11)
Share-based payment (Note 11)
Royalties in cash (a)
Economic rights in cash (a)
Well and facilities maintenance
Operation and maintenance
Consumables (b)
Equipment rental
Transportation costs
Field camp
Safety and insurance costs
Personnel transportation
Consultant fees
Gas plant costs
Non-operated blocks costs (c)
Crude oil stock variation
Purchased crude oil
Other costs
2023
13,889
750
12,845
72,032
26,089
8,143
37,556
4,314
5,850
6,546
5,487
3,363
2,291
1,865
20,421
2,004
4,666
4,214
232,325
2022
13,114
955
63,298
188,989
20,779
6,545
21,789
7,580
4,021
4,070
3,745
2,480
2,133
1,680
12,650
(6,449)
7,929
4,471
359,779
2021
16,655
339
40,000
73,023
17,989
7,826
19,270
8,127
3,383
4,386
4,216
2,397
1,732
2,596
4,941
1,271
—
4,639
212,790
(a) Royalties and economic rights in Colombia are payable to the National Hydrocarbons Agency (“ANH”) and are
determined on a field-by-field basis depending on different variables such as crude quality and price levels, among others
(see Note 33). During 2023, the mix of royalties and economic rights paid “in-kind” increased as compared to royalties
and economic rights paid ‘in-cash”. These changes caused variations in the ‘royalties in cash’ and ‘economic rights in
cash’ line items from year to year, which are compensated by variations in the quantities of oil sales impacting the
‘Revenue’ line item in the Consolidated Statement of Income.
(b) Consumables include energy costs of US$ 26,348,000 in the Llanos 34 Block in 2023 (US$ 6,086,000 in 2022) due to a
drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power.
(c) Non-operated block costs show the increase in activities in the CPO-5 and Perico Blocks in Colombia and Ecuador,
respectively.
F-34
Table of Contents
Note 10 Depreciation
Amounts in US$ ‘000
Oil and gas properties
Production facilities and machinery
Furniture, equipment and vehicles
Buildings and improvements
Depreciation of property, plant and equipment (a)
Related to:
Productive assets
Administrative assets
Depreciation total (a)
2023
95,369
12,896
1,304
503
110,072
108,265
1,807
110,072
2022
76,720
12,244
1,344
672
90,980
88,964
2,016
90,980
2021
66,011
12,468
1,960
700
81,139
78,479
2,660
81,139
(a) Depreciation without considering capitalized costs for oil stock included in Inventories nor depreciation of right-of-use
assets.
Note 11 Staff costs and Directors’ Remuneration
Number of employees at year end (a)
Amounts in US$ ‘000
Wages and salaries
Share-based payments (Note 31)
Social security charges
Director’s fees and allowance
Recognized as follows:
Production and operating costs
Geological and geophysical expenses
Administrative expenses
Selling expenses
Board of Directors’ and key managers’ remuneration
Salaries and fees
Share-based payments
Other benefits in kind
(a) Unaudited.
F-35
2023
470
41,917
7,328
5,992
896
56,133
14,639
8,407
32,604
483
56,133
6,081
4,886
—
10,967
2022
482
38,699
11,038
5,593
1,172
56,502
14,069
7,490
34,533
410
56,502
10,317
8,728
171
19,216
2021
463
42,516
6,621
6,901
2,853
58,891
16,994
6,219
35,360
318
58,891
9,069
5,759
296
15,124
Table of Contents
Directors’ Remuneration
James F. Park (a)
Andrés Ocampo (b)
Robert Bedingfield (c)
Constantin Papadimitriou (d)
Somit Varma (e)
Sylvia Escovar Gomez (f)
Brian Maxted (g)
Carlos Macellari (h)
Marcela Vaca (i)
Non-Executive Director Fees Cash Equivalent
Directors’ Fees Paid in Shares Total Remuneration
(in US$)
—
—
—
120,000
—
—
120,000
205,000
100,000
(No. of Shares)
—
—
21,098
8,791
20,219
23,109
8,791
8,791
8,791
(in US$)
—
—
240,000
220,000
230,000
262,500
220,000
305,000
200,000
(a) Mr. Park has a consulting agreement with the Company to act as CEO advisor and provide support and assistance in
addition to his role as Vicechair, non-executive Director and Strategy and Risk Committee Chairman, and he relinquished
his fees as a member of the Board.
(b) Mr. Ocampo has a service contract to act as Chief Executive Officer, and he relinquished his fees as a member of the
Board.
(c) Audit Committee Chairman.
(d) Compensation Committee Chairman.
(e) Nomination and Corporate Governance Committee Chairman.
(f)
Independent Chair of the Board.
(g) Technical Committee Chairman.
(h) Mr. Macellari, as member of the Technical Committee, instructed by the Board, was awarded additional fees on strategic
and technical exploration advisory.
(i) SPEED Committee Chairman.
Note 12 Geological and geophysical expenses
Amounts in US$ ‘000
Staff costs (Note 11)
Share-based payment (Note 11)
Communication and IT costs
Consultant fees
Allocation to capitalized project
Other services
Note 13 Administrative expenses
Amounts in US$ ‘000
Staff costs (Note 11)
Share-based payment (Note 11)
Consultant fees
Safety and insurance costs
Travel expenses
Non-operated blocks expenses
Director’s fees and allowance (Note 11)
Communication and IT costs
Allocation to joint operations
Other administrative expenses
F-36
2023
7,879
528
2,139
1,373
(1,254)
527
11,192
2023
25,675
6,033
10,645
3,890
1,730
1,568
896
3,760
(13,986)
3,758
43,969
2022
7,097
393
1,743
917
(416)
795
10,529
2022
23,671
9,690
9,574
3,834
2,336
1,390
1,172
3,419
(9,642)
4,580
50,024
2021
6,042
177
1,071
854
(953)
700
7,891
2021
26,402
6,105
10,806
3,142
719
799
2,853
4,214
(8,574)
362
46,828
Table of Contents
Note 14 Selling expenses
Amounts in US$ ‘000
Staff costs (Note 11)
Shared-based payment (Note 11)
Transportation (a)
Selling taxes and other
2023
466
17
9,022
3,579
13,084
2022
2021
410
—
4,881
2,704
7,995
318
—
4,233
4,179
8,730
(a) The rise in transportation costs in 2023 is mainly attributed to deliveries at different sales points in the CPO-5 Block in
Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to
alternative delivery points are recognized as selling expenses.
Note 15 Financial results
Amounts in US$ '000
Financial expenses
Interest and amortization of debt issue costs
Borrowings cancellation costs
Bank charges and other financial results
Unwinding of long-term liabilities
Financial income
Interest received
Foreign exchange gains and losses
Foreign exchange (loss) gain, net
Realized result on currency risk management contracts
Total Financial results
Note 16 Tax reform in Colombia
2023
2022
2021
(30,839)
—
(8,520)
(6,456)
(45,815)
(36,360)
(5,141)
(9,546)
(6,026)
(57,073)
(44,713)
(6,308)
(8,012)
(5,079)
(64,112)
6,237
6,237
3,180
3,180
1,652
1,652
(19,729)
2,909
(16,820)
(56,398)
19,725
—
19,725
(34,168)
5,049
—
5,049
(57,411)
In November 2022, the Colombian Congress approved a Tax Reform (“Law 2277”) which contemplated an increase in the
effective tax rate and the government take for certain entities of the oil and gas industry.
A relevant provision included in the Law 2277 establishes a permanent surtax for companies developing crude oil extractive
activities, ranging between 0% and 15%. The surtax triggers when the Brent price average during the fiscal year meets
percentiles 30 and upwards of the Brent price average of the last 10 years (as shown in the table below regarding fiscal year
2024) and is calculated as additional percentage points of the CIT rate that is applicable to the taxable base determined on a
regular basis for CIT purposes. The applicable surtax for 2023 was 10%. Income derived from gas production is exempted of
surtax.
Surcharge Price Triggers applicable for fiscal year 2024
< US$ 67.18 /bbl
US$ 67.18 to US$ 76.39 /bbl
US$ 76.39 to US$ 79.87 /bbl
> US$ 79.87 /bbl
Surcharge rate
0%
5%
10%
15%
In addition to the aforementioned rules, the Law 2277 included other measures such as the strike off of the straight-line
amortization method for new exploratory assets which will pass to be calculated under the ‘unit of production’ method, and
repeals the tax credit of 50% of the industry and commerce tax paid during the year, which will no longer be treated
F-37
Table of Contents
as a tax credit but as a common deduction. The tax rate for dividends increased to 20% as well as the rate for capital gains tax
that increased to 15%.
These tax provisions became effective in 2023, but the surtax was considered for deferred income tax purposes from the year
ended December 31, 2022.
Note 17 Income tax
Amounts in US$ ‘000
Current income tax liabilities
Amounts in US$ ‘000
Current income tax charge
Deferred income tax benefit (charge) (Note 18)
2023
44,269
44,269
2023
(107,740)
4,299
(103,441)
2022
(126,269)
(44,205)
(170,474)
2022
65,002
65,002
2021
(49,291)
(17,980)
(67,271)
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax
rate applicable to profits of the consolidated entities as follows:
Amounts in US$ ‘000
Profit before tax
Tax losses from non-taxable jurisdictions
Taxable profit
Income tax calculated at domestic tax rates applicable to Profit in the respective
countries
Tax losses where no deferred income tax benefit is recognized
Effect of currency translation on tax base
Effect of inflation adjustment for tax purposes
Changes in the income tax rate (Note 16)
Write-down of deferred income tax benefits previously recognized (a)
Previously unrecognized tax losses
Income tax on dividends (b)
Fiscal recognition of property, plant and equipment
Non-taxable results (c)
Income tax
2023
214,509
39,526
254,035
2022
394,909
53,005
447,914
2021
128,398
91,351
219,749
(123,202)
(6,918)
36,691
—
(8,853)
(3,895)
632
(2,595)
—
4,699
(103,441)
(157,315)
(2,832)
(10,797)
—
(3,820)
(2,938)
9,067
(3,038)
—
1,199
(170,474)
(71,086)
(7,510)
(10,354)
2,482
(1,703)
(7,261)
9,593
—
8,919
9,649
(67,271)
(a)
(b)
(c)
Includes write-down of tax losses and other deferred income tax assets in Chile, Brazil and Argentina where there is
insufficient evidence of future taxable profits to offset them, in accordance with the expected future cash-flows as of
December 31, 2023, 2022 and 2021.
Includes income tax payable in Spain due to dividends received from subsidiaries.
Includes non-deductible expenses and non-taxable gains in each jurisdiction.
Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The
Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed,
they will be exempt from taxation in Bermuda until March 2035. Income tax rate in Colombia may range from 35% to 50%,
depending on the surcharge applicable for each year (see Note 16). Income tax rates in other countries where the Group
operates (Ecuador, Brazil and Chile) ranges from 15% to 34%. There are no income tax consequences attached to the payment
of dividends by the Group to its shareholders.
F-38
Table of Contents
The Group has tax losses available which can be utilized against future taxable profit in the following countries:
Amounts in US$ ‘000
Colombia
Brazil (a)
Chile (a) (c)
Argentina (b)
Spain (a)
Total tax losses as of December 31
2023
—
26,808
313,409
9,981
6,936
357,134
2022
4,837
26,736
323,929
24,065
7,205
386,772
2021
15,557
26,781
285,456
35,773
9,443
373,010
(a) Taxable losses have no expiration date.
(b) Tax losses accumulated as of December 31, 2023, are: US$ 2,551,000, US$ 939,000, US$ 2,297,000, US$ 927,000 and
US$ 3,267,000 expiring in 2024, 2025, 2026, 2027 and 2028, respectively.
(c) The Chilean business was divested on January 18, 2024 (see Note 36.1), and therefore these tax losses no longer belong
to GeoPark from such date.
As of December 31, 2023, deferred income tax assets in respect of tax losses in Chile and Argentina and a portion of tax losses
in Brazil have not been recognized as there is insufficient evidence of future taxable profits to offset them.
Note 18 Deferred income tax
The gross movement on the deferred income tax account is as follows:
Amounts in US$ ‘000
Deferred income tax as of January 1
Currency translation differences
Income tax expense relating to cash flow hedges recognized in OCI
Income statement benefit (charge)
Deferred income tax as of December 31
2023
(51,180)
107
(1,369)
4,299
(48,143)
2022
(6,875)
383
(483)
(44,205)
(51,180)
The breakdown and movement of deferred income tax assets and liabilities as of December 31, 2023, and 2022, are as
follows:
Amounts in US$ ‘000
Deferred income tax assets
Difference in depreciation rates and other
Tax losses
Total 2023
Total 2022
Amounts in US$ ‘000
Deferred income tax liabilities
Difference in depreciation rates and other
Total 2023
Total 2022
At the
beginning Charged to
net profit
of year
Currency
translation
differences Reclassification
At the end
of year
4,759
14,184
18,943
14,072
8,911
(11,485)
(2,574)
4,488
(108)
215
107
383
(556)
—
(556)
13,006
2,914
15,920
— 18,943
At the beginning
of year
Charged to
net profit
Income tax expense
relating to
cash flow hedges
Reclassification
At the end
of year
(70,123)
(70,123)
(20,947)
6,873
6,873
(48,693)
(1,369)
(1,369)
(483)
556
556
—
(64,063)
(64,063)
(70,123)
F-39
Table of Contents
Note 19 Earnings per share
Amounts in US$ ‘000 except for shares
Numerator: Profit for the year
Denominator: Weighted average number of shares used in basic EPS
Earnings after tax per share (US$) – basic
2023
111,068
56,836,682
1.95
2022
224,435
59,330,421
3.78
2021
61,127
60,901,109
1.00
Amounts in US$ ‘000 except for shares
Weighted average number of shares used in basic EPS
Effect of dilutive potential common shares
Stock awards at US$ 0.001
Weighted average number of common shares for the purposes of diluted earnings
per shares
Earnings after tax per share (US$) – diluted
2023
56,836,682
2022
59,330,421
2021
60,901,109
359,587
552,466
559,012
57,196,269
1.94
59,882,887
3.75
61,460,121
0.99
Note 20 Property, plant and equipment
Amounts in US$’000
Cost as of January 1, 2021
Additions / ARO change
Currency translation differences
Disposals
Write-off / Impairment
Transfers
Assets held for sale (Note 36.3)
Cost as of December 31, 2021
Additions / ARO change
Currency translation differences
Disposals
Write-off / Impairment
Transfers
Cost as of December 31, 2022
Additions / ARO change
Currency translation differences
Disposals
Write-off / Impairment
Transfers
Assets held for sale (Note 36.1)
Cost as of December 31, 2023
Furniture, Production Buildings
Oil & gas
properties
968,617
(1,094)(b)
(3,284)
—
(1,575)(c)
68,315
(73,047)
957,932
(7,558)(b)
2,921
—
—
125,962
1,079,257
9,744 (b)
3,477
—
(13,332)(c)
171,538
(330,024)
920,660
facilities and
equipment
and vehicles machinery
197,829
—
(246)
(900)
(2,759)(c)
13,305
(6,052)
201,177
6
232
(26)
—
21,338
222,727
12
277
—
—
21,262
(74,491)
169,787
20,707
930
(43)
(1,762)
—
58
(1,178)
18,712
1,620
37
(1,290)
—
14
19,093
1,683
46
(1,223)
—
93
(6,559)
13,133
and
improvements
12,442
—
(16)
(978)
—
391
(177)
11,662
(14)
6
(774)
—
147
11,027
17
8
(2,150)
—
93
(4,948)
4,047
Depreciation and write-down as of January 1, 2021
Depreciation
Disposals
Currency translation differences
Assets held for sale (Note 36.3)
Depreciation and write-down as of December 31, 2021
Depreciation
Disposals
Currency translation differences
Depreciation and write-down as of December 31, 2022
Depreciation
Disposals
Currency translation differences
Assets held for sale (Note 36.1)
Depreciation and write-down as of December 31, 2023
Carrying amount as of December 31, 2021
Carrying amount as of December 31, 2022
Carrying amount as of December 31, 2023
(548,445)
(66,011)
—
2,219
49,080
(563,157)
(76,720)
—
(2,403)
(642,280)
(95,369)
—
(3,179)
310,683
(430,145)
394,775
436,977
490,515
(109,987)
(12,468)
900
246
4,692
(116,617)
(12,244)
19
(231)
(129,073)
(12,896)
—
(277)
68,765
(73,481)
84,560
93,654
96,306
(6,975)
(700)
838
16
153
(6,668)
(672)
752
(6)
(6,594)
(503)
1,877
(8)
2,158
(3,070)
4,994
4,433
977
(16,985)
(1,960)
1,325
37
915
(16,668)
(1,344)
1,246
(33)
(16,799)
(1,304)
1,189
(41)
6,488
(10,467)
2,044
2,294
2,666
F-40
Construction in
progress
Exploration
and evaluation
assets(a)
18,848
82,094
(18)
(3,372)
— (c)
(70,321)
(27)
27,204
107,171
18
—
—
(117,913)
16,480
116,304
21
(119)
—
(116,905)
—
15,781
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
78,614
46,234
(30)
(338)
(12,262)(d)
(11,748)
—
100,470
67,889
19
—
(25,789)(e)
(29,548)
113,041
73,160
22
—
(29,563)(f)
(76,081)
—
80,579
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
27,204
16,480
15,781
100,470
113,041
80,579
Total
1,297,057
128,164
(3,637)
(7,350)
(16,596)
—
(80,481)
1,317,157
169,114
3,233
(2,090)
(25,789)
—
1,461,625
200,920
3,851
(3,492)
(42,895)
—
(416,022)
1,203,987
(682,392)
(81,139)
3,063
2,518
54,840
(703,110)
(90,980)
2,017
(2,673)
(794,746)
(110,072)
3,066
(3,505)
388,094
(517,163)
614,047
666,879
686,824
Table of Contents
(a) Exploration wells movement and balances are shown in the table below; mining property associated with unproved
reserves and resources, seismic and other exploratory assets amount to US$ 72,581,000 (US$ 96,041,000 in 2022 and
US$ 90,166,000 in 2021).
Amounts in US$ ‘000
Exploration wells as of December 31, 2021
Additions
Write-offs
Transfers
Exploration wells as of December 31, 2022
Additions
Write-offs
Transfers
Exploration wells as of December 31, 2023
Total
10,304
56,491
(21,460)
(28,335)
17,000
61,500
(24,815)
(45,687)
7,998
As of December 31, 2023, there were two exploratory wells that have been capitalized for a period less than three years
amounting to US$ 7,998,000.
(b) Corresponds to the effect of change in estimate of assets retirement obligations.
(c) See Note 37.
(d) Corresponds to two unsuccessful exploratory wells drilled in the Llanos 32 Block (Colombia), other exploration costs
incurred in the Fell Block (Chile), an exploratory well drilled in previous years in the CPO-5 Block (Colombia) and other
exploration costs incurred in previous years in the PUT-30 Block (Colombia).
(e) Corresponds to exploration costs incurred in previous years in the Tacacho and Terecay Blocks (Colombia), four
exploratory wells drilled in the CPO-5, Platanillo, Llanos 34 and Llanos 94 Blocks (Colombia), and certain exploration
costs incurred in the Espejo Block (Ecuador).
(f) Corresponds to three unsuccessful exploratory wells drilled in the Llanos 87 Block (Colombia), an unsuccessful
exploratory well drilled in the Llanos 124 Block (Colombia) and other exploration costs incurred in the Llanos 94, Coati
and Llanos 124 Blocks (Colombia).
F-41
Table of Contents
Note 21 Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of December 31, 2023:
(1) GeoPark Ecuador S.A. holds 50% working interest in the consortiums that operate the Espejo and Perico Blocks.
During the year ended December 31, 2023, the following change to the Group structure has taken place:
● The merger process between GeoPark Colombia S.A.S., GeoPark Colombia E&P S.A. and Petrodorado South America
S.A., with GeoPark Colombia S.A.S. being the surviving company, became effective as of its registration in the Public
Registry of the Chamber of Commerce of Bogota on January 27, 2023.
● As a result of the abovementioned merger and to comply with local regulatory obligations, GeoPark Colombia S.A.S.
incorporated a branch in Panama, which is currently dormant.
F-42
Table of Contents
Details of all the subsidiaries of the Group as of December 31, 2023, are set out below:
Name and registered office
Ownership interest
Subsidiaries
GeoPark Argentina S.A. (Argentina)
GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda. (Brazil)
GeoPark Chile S.p.A. (Chile)
GeoPark Fell S.p.A. (Chile)
GeoPark Magallanes Limitada (Chile)
GeoPark TdF S.p.A. (Chile)
GeoPark Colombia S.A.S. (Colombia)
GeoPark Colombia, S.L.U. (Spain)
GeoPark Perú S.A.C. (Peru)
GeoPark Mexico S.A.P.I. de C.V. (Mexico)
GeoPark E&P S.A.P.I. de C.V. (Mexico)
GeoPark Ecuador S.A. (Ecuador)
GeoPark (UK) Limited (United Kingdom)
Amerisur Resources Limited (United Kingdom)
Amerisur Exploración Colombia Limited (British Virgin Islands)
Amerisur Exploración Colombia Limited Sucursal Colombia (Colombia)
Yarumal S.A.S. (Colombia)
Fenix Oil & Gas Limited (British Virgin Islands)
Fenix Oil & Gas Limited Sucursal Colombia (Colombia)
Amerisurexplor Ecuador S.A. (Ecuador)
Amerisur S.A. (Paraguay)
Market Access LLP (United States)
GeoPark Colombia S.A.S. Sucursal Panama (Panama)
100% (a)
100% (a)
100% (a) (c)
100% (a) (c)
100% (a) (c)
100% (a) (c)
100% (a)
100% (a)
100% (a)
100% (a) (b)
100% (a) (b)
100% (a)
100%
100% (a)
100% (a)
100% (a)
100% (a) (b)
100% (a) (b)
100% (a) (b)
100% (a) (b)
100% (a) (b)
9%
100% (a) (b)
(a)
Indirectly owned.
(b) Dormant companies.
(c) Divested in January 2024. See Note 36.1.
F-43
Table of Contents
Details of the joint operations of the Group as of December 31, 2023, are set out below:
Name and registered office
Ownership interest
Joint operations
Flamenco Block (Chile)
Campanario Block (Chile)
Isla Norte Block (Chile)
Llanos 34 Block (Colombia)
Llanos 32 Block (Colombia)
Puelen Block (Argentina)
Los Parlamentos (Argentina)
Manati Field (Brazil)
POT-T-785 Block (Brazil)
Espejo Block (Ecuador)
Perico Block (Ecuador)
Llanos 86 Block (Colombia)
Llanos 87 Block (Colombia)
Llanos 104 Block (Colombia)
Llanos 123 Block (Colombia)
Llanos 124 Block (Colombia)
CPO-5 Block (Colombia)
Mecaya Block (Colombia)
PUT-8 Block (Colombia)
PUT-9 Block (Colombia)
Tacacho Block (Colombia)
Terecay Block (Colombia)
Llanos 94 Block (Colombia)
PUT-36 Block (Colombia)
CPO-4-1 Block (Colombia)
In process of relinquishment.
(a) GeoPark is the operator.
(b)
(c) Divested in January 2024. See Note 36.1.
(d) GeoPark agreed to transfer its 50% working interest to its joint operation partner.
Note 22 Prepayments and other receivables
Amounts in US$ '000
V.A.T.
Income tax payments in advance
Other prepaid taxes
To be recovered from co-venturers (Note 34)
Prepayments and other receivables
Classified as follows:
Current
Non-current
F-44
50% (a) (c)
50% (a) (c)
60% (a) (c)
45% (a)
12.5%
18% (b)
50% (d)
10%
70% (a)
50% (a)
50%
50% (a)
50% (a)
50% (a)
50% (a)
50% (a)
30%
50% (a)
50% (a)
50% (a)
50% (a) (b)
50% (a) (b)
50% (d)
50% (a)
50%
2023
4,310
3,685
23
8,630
12,311
28,959
25,896
3,063
28,959
2022
1,826
3,156
37
8,750
8,458
22,227
22,106
121
22,227
Table of Contents
Movements on the Group provision for impairment are as follows:
Amounts in US$ '000
At January 1
Additions
Foreign exchange gain (loss)
Note 23 Inventories
Amounts in US$ '000
Crude oil
Materials and spares
The carrying amount of inventories is not pledged as security for liabilities.
Note 24 Trade receivables
Amounts in US$ '000
Trade receivables
2023
2022
14
—
4
18
7
10
(3)
14
2023
9,441
4,111
13,552
2022
12,630
1,804
14,434
2023
65,049
65,049
2022
71,794
71,794
As of December 31, 2023, and 2022, there are no balances that were aged by more than 3 months. Trade receivables that are
aged by less than three months are not considered impaired.
The credit period for trade receivables is 30 days. The maximum exposure to credit risk at the reporting date is the carrying
value of each class of receivable. The Group does not hold any collateral as security related to trade receivables.
The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their
short-term nature.
Note 25 Financial instruments by category
Amounts in US$ '000
Financial assets at fair value through profit or loss
Derivative financial instrument assets
Cash and cash equivalents
Other financial assets at amortized cost
Trade receivables
To be recovered from co-venturers (Note 34)
Other financial assets (a)
Cash and cash equivalents
Total financial assets
Assets as per statement
of financial position
2022
2023
3,775
—
3,775
65,049
8,630
12,564
133,036
219,279
223,054
967
242
1,209
71,794
8,750
12,877
128,601
222,022
223,231
(a) Non-current other financial assets relate to restricted deposits made for environmental obligations according to Brazilian
government regulations. Current other financial assets correspond to short-term investments with original maturities up to
twelve months and over three months.
F-45
Table of Contents
Amounts in US$ ‘000
Liabilities at fair value through profit and loss
Derivative financial instrument liabilities
Other financial liabilities at amortized cost
Trade payables
To be paid to co-venturers (Note 34)
Lease liabilities
Borrowings
Total financial liabilities
25.1 Credit quality of financial assets
Liabilities as per statement
of financial position
2022
2023
70
70
19
19
108,977
522
32,298
500,981
642,778
642,848
102,125
2,815
32,051
497,642
634,633
634,652
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
Trade receivables
Counterparties with an external credit rating (Moody’s, S&P, Fitch)
Aa3
A3
Baa1
Baa3
Ba1
Ba2
Ba3
B2
Counterparties without an external credit rating
Group 1 (a)
Total trade receivables
2023
2022
—
949
1,721
151
15,068
2,953
—
63
44,144
65,049
2,013
1,557
99
198
23,755
—
2,745
4,085
37,342
71,794
(a) Group 1 – no existing balances with customers aged by more than 3 months.
All trade receivables are denominated in US Dollars, except in Brazil where they are denominated in Brazilian Real.
F-46
Table of Contents
Cash at bank and other financial assets (a)
Amounts in US$ ‘000
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC
Investor Services)
Aa3
A1
A2
A3
Baa1
Baa2
Baa3
Ba1
Ba2
Ba3
B3
Counterparties without an external credit rating
Total
2023
2022
—
91,747
268
16,147
18
17,585
125
—
6,528
5
593
12,571
145,587
10,362
96,077
57
10,389
39
7,030
1,352
64
268
3,066
51
12,953
141,708
(a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 13,000
(US$ 12,000 in 2022).
25.2 Financial liabilities- contractual undiscounted cash flows
The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the
balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.
Amounts in US$ ‘000
As of December 31, 2023
Borrowings
Lease liabilities
Trade payables
To be paid to co-venturers (Note 34)
As of December 31, 2022
Borrowings
Lease liabilities
Trade payables
To be paid to co-venturers (Note 34)
Less than 1 Between 1 Between 2 Over 5
years
and 5 years
and 2 years
year
27,500
9,416
108,977
522
146,415
27,500
10,939
102,125
2,815
143,379
27,500
6,515
—
—
34,015
27,500
5,653
—
—
33,153
541,250
11,719
—
—
552,969
568,750
11,209
—
—
579,959
—
25,134
—
—
25,134
—
25,012
—
—
25,012
25.3 Fair value measurement of financial instruments
Accounting policies for financial instruments have been applied to classify as either: amortized cost, financial assets at fair
value through profit or loss and fair value through other comprehensive income. For financial instruments that are measured in
the statement of financial position at fair value, IFRS 13 requires a disclosure of fair value measurements by level according to
the following fair value measurement hierarchy:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either
directly (that is, as prices) or indirectly (that is, derived from prices).
Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs).
F-47
Table of Contents
25.3.1 Fair value hierarchy
The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value as of
December 31, 2023, and 2022, on a recurring basis:
Amounts in US$ ‘000
Assets
Derivative financial instrument assets
Commodity risk management contracts
Total Assets
Liabilities
Derivative financial instrument liabilities
Commodity risk management contracts
Total Liabilities
Amounts in US$ ‘000
Assets
Cash and cash equivalents
Money market funds
Derivative financial instrument assets
Commodity risk management contracts
Total Assets
Liabilities
Derivative financial instrument liabilities
Commodity risk management contracts
Total Liabilities
Level 1
Level 2
2023
As of December 31,
—
—
—
—
3,775
3,775
70
70
3,775
3,775
70
70
Level 1
Level 2
As of December 31,
2022
242
—
242
—
—
—
967
967
19
19
242
967
1,209
19
19
There were no transfers between Level 2 and 3 during the period.
The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as of
December 31, 2023.
25.3.2 Valuation techniques used to determine fair values
Specific valuation techniques used to value financial instruments include:
● The use of quoted market prices or dealer quotes for similar instruments.
● The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided
market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and
are within level 2 of the fair value hierarchy.
● The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the
resulting fair value estimates are included in level 2.
25.3.3 Fair values of other financial instruments (unrecognized)
The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the
majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest
receivable/payable is either close to current market rates or the instruments are short-term in nature.
Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short-term portion where interest has
already been fixed. They are classified under other financial liabilities and measured at their amortized cost.
The fair value of these financial instruments as of December 31, 2023, amounts to US$ 443,690,000 (US$ 431,660,000 in
2022). The fair values are based on market price for the Notes and cash flows discounted for other borrowings using a rate
based on the borrowing rate and are within level 1 and level 2 of the fair value hierarchy, respectively.
F-48
Table of Contents
Note 26 Equity
26.1 Share capital and Share premium
Issued share capital
Common stock (amounts in US$ ‘000)
The share capital is distributed as follows:
Common shares, of nominal US$ 0.001
Total common shares in issue
Authorized share capital
US$ per share
Number of common shares (US$ 0.001 each)
Amount in US$
2023
2022
55
58
55,327,520
55,327,520
57,621,998
57,621,998
0.001
0.001
5,171,949,000
5,171,949
5,171,949,000
5,171,949
Details regarding the share capital of the Company are set out below.
26.1.1 Common shares
As of December 31, 2023, 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
Shares outstanding at the end of 2021
Buyback program
Buyback program
Stock awards
Buyback program
Buyback program
Shares outstanding at the end of 2022
Stock awards
Buyback program
Stock awards
Buyback program
Buyback program
Buyback program
Shares outstanding at the end of 2023
Month
Mar 2022
Jun 2022
Jul 2022
Sep 2022
Dec 2022
Feb 2023
Mar 2023
May 2023
Jun 2023
Sep 2023
Dec 2023
Shares
movement
(millions)
(0.2)
(0.5)
0.1
(1.1)
(0.9)
0.6
(0.6)
0.1
(1.1)
(0.5)
(0.8)
Shares
closing
(millions)
60.2
60.0
59.5
59.6
58.5
57.6
57.6
58.2
57.6
57.7
56.6
56.1
55.3
55.3
US$(`000)
Closing
60
60
60
60
59
58
58
58
58
58
57
56
55
55
26.1.2 Stock Award Program and Other Share Based Payments
Non-Executive Directors Fees
During 2023, the Company issued 99,590 shares (75,636 in 2022 and 64,269 in 2021) to Non-Executive Directors in
accordance with contracts as compensation, generating a share premium of US$ 1,133,000 (US$ 1,040,000 in 2022 and US$
861,000 in 2021). The number of shares issued is determined considering the contractual compensation and the fair value of
the shares for each relevant period.
F-49
Table of Contents
Stock Award Program and Other Share Based Payments
On February 3, 2023, 350,938 common shares were issued as part of the compensation agreements related to the CEO
transition which occurred in 2022, generating a share premium of US$ 4,799,000. On July 15, 2022, 52,058 common shares
were issued as part of the founding executive employment agreement in place with the former Chief Executive Officer
(104,439 in 2021), generating a share premium of US$ 800,000 (US$ 800,000 in 2021).
On February 3, 2023, 246,110 common shares were issued as a result of the vesting of the first tranche of the Long-Term
Incentive program (“LTIP”) oriented to executive officers which was granted in 2022, generating a share premium of US$
1,505,000.
During 2023, 82,472 common shares were issued as part of other equity incentive plans vested during the year, generating a
share premium of US$ 281,000.
26.1.3 Buyback Program
The Company has recurring buyback programs to repurchase its own shares. The latest renewal took place on November 8,
2023, and established a program to repurchase up to 10% of the shares outstanding, or approximately 5,611,797 shares, until
December 31, 2024.
In addition to any repurchases under the aforementioned repurchase program, the Company has authority from its Board of
Directors to repurchase, on a standalone basis, up to US$ 50,000,000 of its common shares in 2024.
During 2023, the Company purchased 3,073,588 common shares (2,743,722 in 2022 and 960,454 in 2021) for a total amount
of US$ 31,239,000 (US$ 36,265,000 in 2022 and US$ 11,841,000 in 2021). These transactions had no impact on the Group’s
results.
26.2 Cash distributions
On November 6, 2019, the Company’s Board of Directors declared the initiation of quarterly cash distributions.
The following table summarizes the cash distributions for each of the years presented:
Date of distribution
April 13, 2021
May 28, 2021
August 31, 2021
December 7, 2021
Date of declaration
March 10, 2021
May 5, 2021
August 4, 2021
November 10, 2021
Cash distributions for the year ended December 31, 2021
March 31, 2022
March 9, 2022
June 10, 2022
May 11, 2022
September 8, 2022
August 10, 2022
November 9, 2022
December 7, 2022
Cash distributions for the year ended December 31, 2022
March 31, 2023
March 8, 2023
May 31, 2023
May 3, 2023
September 7, 2023
August 9, 2023
November 8, 2023
December 11, 2023
Cash distributions for the year ended December 31, 2023
These distributions are deducted from Other Reserves.
F-50
US$ per share
Total amount
in US$ ‘000
0.0205
0.0205
0.0410
0.0410
0.0820
0.0820
0.1270
0.1270
0.1300
0.1300
0.1320
0.1340
1,133
1,220
2,442
2,429
7,224
4,847
4,809
7,345
7,281
24,282
7,505
7,378
7,383
7,449
29,715
Table of Contents
Note 27 Borrowings
Amounts in US$ ‘000
Outstanding amounts as of December 31
Notes due 2027
Classified as follows:
Current
Non-current
2023
2022
500,981
500,981
12,528
488,453
497,642
497,642
12,528
485,114
On January 17, 2020, the Company placed US$ 350,000,000 aggregate principal amount of 5.500% senior secured notes due
2027 (the “Notes due 2027”), which were offered in a private placement to qualified institutional buyers in accordance with
Rule 144A under the Securities Act, and outside the United States to non U.S. persons in accordance with Regulation S under
the Securities Act. The Notes due 2027 were priced at 99.285% and carry a coupon of 5.50% per annum (yield 5.625% per
annum). Final maturity will be January 17, 2027.
In April 2021, the Company reopened its Notes due 2027, issuing an additional US$ 150,000,000 principal amount. The
reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. The Notes due 2027 were offered in
a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the
United States to non-U.S. persons in accordance with Regulation S under the Securities Act. The Notes due 2027 are fully and
unconditionally guaranteed by GeoPark Colombia, S.L.U.
From April 2021 to September 2022, the Company repurchased and cancelled its US$ 425,000,000 aggregate principal
amount of 6.500% senior secured notes due 2024 (the “Notes due 2024”). In April 2021, the Company executed a tender to
purchase US$ 255,000,000 of the Notes due 2024, funded with a combination of cash in hand and the abovementioned
reopening of the Notes due 2027. From March to September 2022, the Company repurchased and cancelled the remaining
amount of the Notes due 2024 for a nominal amount of US$ 170,000,000. The difference between the carrying amount of debt
that was repurchased or redeemed and the consideration paid was recognized within ‘Financial expenses’ in the Consolidated
Statement of Income.
The indenture governing the Notes due 2027 includes incurrence test covenants that provide, among other things, that the Net
Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.5
times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may
limit the Company’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. Incurrence
covenants, as opposed to maintenance covenants, must be tested by the Company before incurring additional debt or
performing certain corporate actions including but not limited to dividend payments, restricted payments and others. As of the
date of these Consolidated Financial Statements, the Company complies with all the indentures’ provisions and covenants.
On August 3, 2023, GeoPark Colombia S.A.S., as borrower, and GeoPark Limited, as guarantor, signed a senior unsecured
credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. which provides
GeoPark with access to up to US$ 80,000,000, with an availability period until November 3, 2024, and final maturity on
August 3, 2025. The agreement establishes a commitment fee of 1.85% per annum with respect to undrawn amounts and an
interest rate of SOFR + 3.70% with respect to amounts drawn. “SOFR” (Secured Overnight Financing Rate) is a broad
measure of the cost of borrowing cash overnight collateralized by treasury securities. As of the date of these Consolidated
Financial Statements, GeoPark has not withdrawn any amount under this credit facility.
As of the date of these Consolidated Financial Statements, the Group has access to the abovementioned US$ 80,000,000
senior unsecured committed credit facility and to US$ 179,600,000 in uncommitted credit lines.
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Table of Contents
Note 28 Leases
The Consolidated Statement of Financial Position shows the following amounts relating to leases:
Amounts in US$ ‘000
Right of use assets
Production, facilities and machinery
Buildings and improvements
Lease liabilities
Current
Non-current
The Consolidated Statement of Income shows the following amounts relating to leases:
Amounts in US$ ‘000
Depreciation charge of Right of use assets
Production, facilities and machinery
Buildings and improvements
Unwinding of long-term liabilities (included in Financial results)
Expenses related to short-term leases (included in Production and operating cost and
Administrative expenses)
Expenses related to low-value leases (included in Administrative expenses)
2023
2022
24,201
4,250
28,451
8,911
23,387
32,298
32,034
4,977
37,011
10,000
22,051
32,051
2023
2022
2021
(7,858)
(792)
(8,650)
(3,168)
(838)
(775)
(6,057)
(988)
(7,045)
(2,838)
(2,614)
(708)
(5,526)
(1,136)
(6,662)
(1,453)
(1,101)
(906)
The table below summarizes the amounts of Right-of-use assets recognized and the movements during the reporting years:
Amounts in US$‘000
Right-of-use assets as of January 1
Additions / changes in estimates
Foreign currency translation
Assets held for sale (Note 36.1)
Depreciation
Right-of-use assets as of December 31
2023
37,011
137
444
(491)
(8,650)
28,451
2022
21,014
22,462
580
—
(7,045)
37,011
The table below summarizes the amounts of Lease liabilities recognized and the movements during the reporting years:
Amounts in US$‘000
Lease liabilities as of January 1
Additions / changes in estimates
Exchange difference
Foreign currency translation
Liabilities associated with assets held for sale (Note 36.1)
Unwinding of discount
Lease payments
Lease liabilities as of December 31
F-52
2023
32,051
137
7,061
174
(26)
3,168
(10,267)
32,298
2022
20,744
22,462
(6,426)
284
—
2,838
(7,851)
32,051
Table of Contents
Note 29 Provisions and other long-term liabilities
Amounts in US$ ‘000
As of January 1, 2022
Addition to provision / changes in estimates
Exchange difference
Foreign currency translation
Amortization
Unwinding of discount
Amounts used during the year
As of December 31, 2022
Addition to provision / changes in estimates
Exchange difference
Foreign currency translation
Amortization
Unwinding of discount
Amounts used during the year
Liabilities associated with assets held for sale (Note 36.1)
As of December 31, 2023
Asset retirement
obligation (a)
Deferred
Income (b)
Other (c)
Total
45,842
(4,942)
(669)
(577)
—
2,641
(1,392)
40,903
7,374
1,172
717
—
2,794
(2,502)
(26,922)
23,536
3,331
—
(167)
—
(2,407)
—
—
757
—
180
—
(127)
—
—
—
810
13,675
(2,670)
(1,147)
14
—
547
(132)
10,287
2,460
560
(13)
—
494
(4,051)
—
9,737
62,848
(7,612)
(1,983)
(563)
(2,407)
3,188
(1,524)
51,947
9,834
1,912
704
(127)
3,288
(6,553)
(26,922)
34,083
(a) 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).
(b) ‘Deferred income’ relates to government grants and other contributions relating to the purchase of property, plant and
equipment in Colombia. The amortization is in line with the related assets.
(c)
‘Other’ mainly includes environmental obligations in Colombia and Peru.
Legal proceeding in the United Kingdom
On January 8, 2020, Amerisur Resources Limited (“Amerisur”) received a copy of a claim form issued in the High Court of
England and Wales (the “Court”) by Leigh Day solicitors on behalf of a group of claimants (the “Claimants”) described as
members of a farming community in the department of Putumayo in Colombia, seeking compensation for economic and non-
economic damages said to be caused by alleged environmental contamination and pollution caused by Amerisur’s operations
in the region. Following initial court hearings, an interim freezing order was imposed on Amerisur for an amount of GBP
4,465,600 of its assets located in the United Kingdom. On November 10, 2020, the freezing order was discharged by
agreement between the parties as Amerisur provided alternative security in the form of a letter of credit.
On February 6, 2023, the Court ordered Amerisur to pay the sum of GBP 330,022 (equivalent to US$ 409,000). On August 11,
2023, a settlement (the “Settlement”) was signed between Leigh Day and Amerisur, made on a no-admission of liability basis
and included a payment made by Amerisur. All Claimants represented by Leigh Day agreed to the Settlement. On October 2,
2023, the Court approved the Settlement, the litigation was discontinued, and the letter of credit was cancelled.
GeoPark had a provision for this contingent liability, which was originally recognized at the moment of the acquisition of
Amerisur in 2020. All payments made by Amerisur during 2023 were applied to the previously recognized contingent liability,
thus generating a gain of US$ 2,568,000 that was recorded in “Other income (expenses)” in the Consolidated Statement of
Income.
F-53
Table of Contents
Note 30 Trade and other payables
Amounts in US$ ‘000
V.A.T
Trade payables
Customer advance payments
Other short-term advance payments (a)
Outstanding commitments in Chile (b)
Staff costs to be paid
Royalties to be paid
Taxes and other debts to be paid
To be paid to co-venturers (Note 34)
Classified as follows:
Current
Non-current
2023
975
108,977
—
450
5,869
10,852
791
9,381
522
137,817
137,817
—
2022
8,513
102,125
481
—
—
9,306
9,403
8,963
2,815
141,606
141,606
—
(a) Advance payment collected in relation with the sale of the Group´s business in Chile (see Note 36.1).
(b)
Investment commitments in the Campanario and Isla Norte Blocks as a result of sale agreement of the Group´s business
in Chile (see Note 36.1).
The average credit period (expressed as creditor days) during the year ended December 31, 2023, was 90 days (2022: 69
days).
The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable
approximation of fair value.
Note 31 Share-based payment
The Group has established different stock awards programs and other share-based payment plans to incentivize the directors,
executive officers and employees, enabling them to benefit from the increased market capitalization of the Company.
During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees,
directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company
and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs
that the Company decides to implement throughout such term. The maximum number of shares available for issuance under
the Plan is 5,000,000 Shares.
In 2020, a share-based compensation program for employees was approved for approximately 800,000 shares, to vest in 2023.
On February 17, 2023, the Compensation Committee reviewed the Group’s results and the performance conditions established
in the program and approved 152,030 shares to be delivered to participants, due to the fact that, throughout the vesting period,
the performance conditions included in the program were only partially achieved and, to a lesser extent, the Group had lower
hirings than estimated and not all the beneficiaries continued being employees at the vesting date.
On March 8, 2022, the Company’s Board of Directors approved a pool of approximately 215,000 shares oriented for retention
of key employees and new hires bonuses, under the Stock Awards Program. Vesting of the plan is in a three-years period from
the grant date.
During 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a
Long-Term Incentive program (“LTIP”) for executive officers. Main characteristics of the program are:
● All executive officers are eligible.
● Grants are awarded annually to executive officers.
F-54
Table of Contents
● The components of the Program are the following:
-
-
-
20% Time-based Restricted Share Units (RSUs) vesting ratably in three equal installments on each of the first
three anniversaries of the grant date;
35% Relative Performance Share Units based on relative total shareholder return (TSR) and measured over
three-year performance period relative to peer group; and
45% Absolute Performance Share Units (PSUs) based on absolute total shareholder return (TSR) and measured
over three-year performance period.
In February 2023, 246,110 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”) as a
consequence of the vesting of the first tranche of the abovementioned plan, and the Compensation Committee approved a new
grant effective as of February 14, 2023, of 197,197 shares to vest during a three-year period.
In December 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee,
approved a Long-Term Incentive program for employees and new hirings. Main characteristics of the program are:
● All employees (non-top management) and new hirings are eligible.
● 3-year program, with a grant date of January 2, 2023, or the date on which the employees are hired.
● The components of the program are the following:
-
-
-
30% Time-based RSUs: vesting annually ratably in three equal installments;
30% Company Performance: measured over three-year performance period (December 2022-December 2025);
and
40% Absolute Performance Shares: share price at the date of vesting must be higher than the share price at the
date of grant or date of hiring.
● The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026.
Details of these costs and the characteristics of the different stock awards programs and other share-based payments are
described in the following table:
Year of issuance
2023
2022
2020
Subtotal
Shares granted to Non-Executive Directors
Shares granted to Executive Directors (a)
VCP (b)
LTIP for executives
Awards at the Awards granted Awards Awards Awards at Charged to net profit/loss
year end 2023 2022 2021
in the year
beginning
exercised
forfeited
No. of Shares
Amounts in US$ '000
—
191,400
405,919
597,319
—
375,937
—
571,984
1,545,240
795,412
12,000
807,412
99,590
—
—
268,129
1,175,131
(105,695)
—
(6,112)
(9,444)
(253,889)
(61,980)
(365,696)
(71,424)
(99,590)
—
— (359,271)
—
—
— (248,825)
(779,110)
(365,696)
689,717
187,844
90,050
967,611
1,452
990
—
2,442
— 1,133
126
—
3,627
7,328
16,666
—
591,288
1,575,565
—
619
1,691
2,310
1,041
3,560
2,016
2,111
11,038
—
—
862
862
861
800
4,098
—
6,621
(a)
(b)
Includes compensation agreements from CEO transition.
The plan named Value Creation Plan (“VCP”), oriented to key management, was approved in 2019. The performance
metrics were not achieved to execute this program and is not currently in place.
The awards that are forfeited correspond to employees that had left the Group before vesting date.
Note 32 Interests in Joint operations
The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Ecuador,
Brazil, Chile and Argentina.
GeoPark is the operator in the Llanos 34, Llanos 86, Llanos 87, Llanos 104, Llanos 123, Llanos 124, Mecaya, PUT-8, PUT-9,
PUT-36, Tacacho and Terecay Blocks in Colombia, in the Espejo Block in Ecuador, in the POT-T-785 Block in Brazil, and in
the Flamenco, Campanario and Isla Norte Blocks in Chile.
F-55
Table of Contents
The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been
recognized in the Consolidated Statement of Financial Position and Statement of Income:
Subsidiary /
Joint operation
2023
GeoPark Colombia S.A.S.
Llanos 34 Block
Llanos 32 Block
Llanos 86 Block
Llanos 87 Block
Llanos 94 Block
Llanos 104 Block
Llanos 123 Block
Llanos 124 Block
CPO-5 Block
CPO-4-1 Block
Amerisur Exploración Colombia Limitada Sucursal
Colombia
Mecaya Block
PUT-8 Block
PUT-9 Block
PUT-36 Block
Tacacho Block
Terecay Block
GeoPark Ecuador S.A.
Espejo
Perico
GeoPark Brasil Exploração y Produção de Petróleo e
Gas Ltda.
Manati Field
POT-T‑785
GeoPark TdF S.p.A.
Flamenco Block
Campanario Block
Isla Norte Block
GeoPark Argentina S.A.
Los Parlamentos Block
Puelen Block
Interest
PP&E
Other Total
Assets
Assets
Total
Liabilities
Net Assets/
Operating
(Liabilities) Revenue profit (loss)
45 % 354,361
12.5 % 2,493
50 % 5,532
50 % 16,621
50 %
—
50 % 5,536
50 % 16,292
50 %
—
30 % 182,484
102
50 %
50 % 3,948
50 % 9,118
50 % 4,454
50 % 2,950
—
50 %
—
50 %
50 % 10,072
50 % 22,231
359,440
5,079
2,493
—
5,759
227
17,271
650
—
—
5,856
320
17,327
1,035
170
170
— 182,484
109
7
51
306
68
50
103
36
213
—
3,999
9,424
4,522
3,000
103
36
10,285
22,231
(7,641)
(655)
—
(1,211)
(336)
—
(520)
(166)
(1,540)
—
(40)
—
—
—
—
—
(467)
(889)
351,799
1,838
5,759
16,060
(336)
5,856
16,807
4
180,944
109
464,146
7,811
—
1,527
—
—
8,648
—
148,594
—
3,959
9,424
4,522
3,000
103
36
—
—
—
—
—
—
9,818
21,342
1,450
17,647
10 % 5,233
160
70 %
17,546
—
22,779
160
(12,788)
—
9,991
160
14,019
—
50 %
50 %
60 %
50 %
18 %
—
—
—
—
—
—
—
—
—
2
—
—
—
—
2
(1,336)
(5,438)
(1,018)
—
(60)
(1,336)
(5,438)
(1,018)
—
(58)
—
—
—
—
—
295,556
5,661
(187)
(17,722)
(1,044)
(186)
4,006
(7,496)
50,032
(96)
(66)
(8)
(66)
(2)
(8)
(8)
(1,897)
258
4,955
—
(178)
(5,113)
(1,000)
(7,086)
(51)
F-56
Table of Contents
Subsidiary /
Joint operation
2022
GeoPark Colombia S.A.S.
Llanos 34 Block
Llanos 32 Block
Llanos 86 Block
Llanos 87 Block
Llanos 94 Block
Llanos 104 Block
Llanos 123 Block
Llanos 124 Block
CPO-5 Block
CPO-4-1 Block
Amerisur Exploración Colombia Limitada Sucursal
Colombia
Mecaya Block
PUT-8 Block
PUT-9 Block
PUT-36 Block
Tacacho Block
Terecay Block
GeoPark Ecuador S.A.
Espejo
Perico
GeoPark Brasil Exploração y Produção de Petróleo
e Gas Ltda.
Manati Field
POT-T‑785
GeoPark TdF S.p.A.
Flamenco Block
Campanario Block
Isla Norte Block
GeoPark Argentina S.A.
CN-V Block
Los Parlamentos Block
Puelen Block
Sierra del Nevado Block
Interest
PP&E
Other Total
Assets
Assets
Total
Net Assets/
Liabilities
(Liabilities) Revenue
Operating
profit (loss)
45 % 295,639
12.5 % 2,324
970
50 %
50 % 15,038
50 %
576
50 % 1,001
50 % 1,172
50 % 1,207
30 % 199,748
102
50 %
50 % 3,908
50 % 7,927
50 % 4,420
50 % 2,931
—
50 %
—
50 %
297,923
2,284
2,324
—
970
—
15,038
—
576
—
1,001
—
1,172
—
—
1,207
— 199,748
102
—
—
—
—
—
—
—
3,908
7,927
4,420
2,931
—
—
(2,104)
(371)
—
(41)
(233)
—
—
—
(344)
—
(17)
—
—
—
—
—
295,819
1,953
970
14,997
343
1,001
1,172
1,207
199,404
102
3,891
7,927
4,420
2,931
—
—
721,326
9,791
—
—
—
—
—
—
184,160
—
—
—
—
—
—
—
50 % 10,727
50 % 15,195
593
8,506
11,320
23,701
(5,406)
(5,315)
5,914
18,386
—
10,671
402,425
7,066
(60)
(390)
(5,632)
(60)
(60)
(60)
69,422
—
(62)
(61)
(62)
(60)
(3,699)
(300)
(5,151)
4,533
10 % 5,665
168
70 %
18,537
—
24,202
168
(12,602)
—
11,600
168
19,873
—
11,240
—
50 %
50 %
60 %
50 %
50 %
18 %
18 %
—
—
—
—
—
—
—
—
—
—
—
—
10
1
—
—
—
—
—
10
1
(1,314)
(422)
(160)
(14)
(93)
(105)
(4)
(1,314)
(422)
(160)
(14)
(93)
(95)
(3)
—
—
—
—
—
—
—
(261)
(115)
(131)
(131)
(176)
(69)
(8)
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Table of Contents
Subsidiary /
Joint operation
2021
GeoPark Colombia S.A.S.
Llanos 34 Block
Llanos 32 Block
Llanos 86 Block
Llanos 87 Block
Llanos 94 Block
Llanos 104 Block
Llanos 123 Block
Llanos 124 Block
CPO-5 Block
Amerisur Exploración Colombia Limitada Sucursal
Colombia
Mecaya Block
PUT-8 Block
PUT-9 Block
PUT-36 Block
Tacacho Block
Terecay Block
GeoPark Perú S.A.C. - Sucursal Ecuador
Espejo
Perico
GeoPark Brasil Exploração y Produção de Petróleo
e Gas Ltda.
Manati Field
POT-T‑785
GeoPark TdF S.p.A.
Flamenco Block
Campanario Block
Isla Norte Block
GeoPark Argentina S.A.U.
CN-V Block
Los Parlamentos Block
Puelen Block
Sierra del Nevado Block
Interest
PP&E
Other Total
Assets
Assets
Total
Net Assets/
Liabilities
(Liabilities) Revenue
Operating
profit (loss)
45 % 260,589
12.5 % 2,730
408
50 %
50 % 1,220
50 % 1,489
434
50 %
907
50 %
50 %
841
30 % 210,154
50 % 3,837
50 % 7,070
50 % 4,342
50 % 2,870
50 % 3,629
226
50 %
262,455
1,866
2,730
—
408
—
1,220
—
1,489
—
434
—
907
—
—
841
— 210,154
—
—
—
—
—
—
3,837
7,070
4,342
2,870
3,629
226
1,210
6,107
(5,573)
(197)
—
—
(270)
—
—
—
(929)
(84)
—
—
—
—
—
(610)
(4,535)
50 % 1,132
50 % 4,658
78
1,449
256,882
2,533
408
1,220
1,219
434
907
841
209,225
486,779
7,690
—
—
—
—
—
—
88,479
341,473
5,378
(60)
(60)
(171)
(60)
(60)
(60)
55,131
3,753
7,070
4,342
2,870
3,629
226
600
1,572
—
—
—
—
—
—
—
—
10 % 6,851
157
70 %
18,269
—
25,120
157
(13,657)
—
11,463
157
20,109
—
50 %
50 %
60 %
50 %
50 %
18 %
18 %
—
—
—
—
—
—
—
—
—
—
149
—
12
1
—
—
—
149
—
12
1
(2,082)
(551)
(138)
(528)
—
(18)
(5)
(2,082)
(551)
(138)
(379)
—
(6)
(4)
—
—
—
—
—
—
—
—
—
—
—
—
—
(589)
(669)
9,899
—
(137)
(106)
(122)
(839)
(285)
(55)
(10)
Capital commitments are disclosed in Note 33.2.
Note 33 Commitments
33.1 Royalty and economic rights commitments
33.1.1 Royalty
In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis
using the level of production sliding scale detailed below:
Average daily production in barrels
Up to 5,000
5,000 to 125,000
125,000 to 400,000
400,000 to 600,000
Greater than 600,000
Production Royalty rate
8%
8% + (production - 5,000) * 0.1
20%
20% + (production - 400,000) * 0.025
25%
The production royalty rate depends on the crude quality. When the API is lower than 15°, the payment is reduced to the 75%
of the total calculation.
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In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly
minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties
generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as
established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of
royalties applicable to a concession, the ANP takes into consideration, among other factors, the geological risks involved and
the production levels expected. In the Manati Block, royalties are calculated at 7.5% of gas production.
In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties were calculated at 5% of crude oil
production sold and 3% of gas production sold. In the Flamenco Block, Campanario Block and Isla Norte Block, royalties
were calculated at 5% of oil and gas production sold.
33.1.2 Overriding royalty
GeoPark is obligated to pay an overriding royalty of 4% and 2.5%, respectively, to the previous owners of the Llanos 34 and
CPO-5 Blocks, based on the production and sale of hydrocarbons discovered in the blocks. During 2023, the Group has
accrued US$ 27,453,000 (US$ 34,032,000 in 2022 and US$ 22,562,000 in 2021) in relation with these overriding royalty
agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the
Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they are exploratory blocks with no production during
2023, these agreements had no impact on the Group’s results.
33.1.3 Economic rights
According to each E&P Contract, the Colombian National Hydrocarbons Agency (“ANH”) has an economic right, offered by
the operator at the moment of the ANH bid. This economic right, which is based on the production of the block after royalty
discount, is equal to 1% in the Llanos 32, Llanos 34 and Llanos 123 Blocks, 3% in the Llanos 87 Block, 23% in the CPO-5
Block and 0% in the Platanillo Block.
When the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI
price exceeds certain price level previously determined, the Group should also deliver to ANH a share of the production net of
royalties in accordance with a formula defined in each E&P Contract, which basically depends on the WTI price and the crude
quality.
33.2 Capital commitments
During 2023, the Group incurred investments of US$ 54,640,000 to fulfil its commitments, at GeoPark’s working interest.
33.2.1 Colombia
The future investment commitments assumed by GeoPark, at its working interest, are up to:
● Llanos 32 Block: 5 exploratory wells before February 20, 2022. As of the date of these Consolidated Financial
Statements, the total investments needed to fulfill the commitments in the block have already been incurred and the
ANH approval is pending.
● Llanos 86 Block: 3D seismic and 1 exploratory well (US$ 9,849,000) before June 19, 2026.
● Llanos 87 Block: 3D seismic reprocessing, aerogeophysic and 4 exploratory wells (US$ 13,663,000) before May 14,
2023. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the
commitments in the block have already been incurred and the ANH approval is pending.
● Llanos 94 Block: 1 exploratory well (US$ 3,467,000) before October 1, 2025. As of the date of these Consolidated
Financial Statements, GeoPark agreed to transfer its 50% working interest to its joint operation partner and thus
GeoPark will no longer be liable for this capital commitment in the block.
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● Llanos 104 Block: 3D seismic and 1 exploratory well (US$ 8,752,000) before June 19, 2026.
● Llanos 123 Block: 3D seismic reprocessing, geochemistry and 2 exploratory wells (US$ 7,130,000) before January
14, 2024. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the
commitments in the block have already been incurred and the ANH approval is pending.
● Llanos 124 Block: 3D seismic acquisition and reprocessing, geochemistry and 3 exploratory wells (US$ 10,422,000)
before January 14, 2024. As of the date of these Consolidated Financial Statements, the total investments needed to
fulfill the commitments in the block have already been incurred or transferred to another block, and the ANH
approval is pending.
● CPO-4-1 Block: 1 exploratory well (US$ 2,922,000) before September 19, 2025.
● CPO-5 Block: 3D seismic acquisition, processing and interpretation and 1 exploratory well (US$ 2,794,000) before
May 18, 2027. Pursuant to a private agreement with the joint operation partner, the investment commitment assumed
by GeoPark amounts to US$ 9,313,000. As of the date of these Consolidated Financial Statements, the exploratory
well has already been drilled and the ANH approval is pending.
● Coati Block: 3D seismic and 2D seismic acquisition (US$ 4,500,000). The evaluation area is currently suspended.
On November 3, 2022, GeoPark submitted to the ANH a request to withdraw from the exploration period of the
Coati E&P contract and transfer the pending commitments to other E&P contracts. As of the date of these
Consolidated Financial Statements, GeoPark completed the transfer of the pending commitments in the block and the
ANH approval is pending.
● Mecaya Block: 3D seismic or 1 exploratory well (US$ 2,000,000). The exploratory period is currently suspended.
Pursuant to a private agreement with the joint operation partner, the investment commitment to be incurred by
GeoPark amounts to US$ 600,000.
● PUT-8 Block: 3D seismic acquisition and reprocessing and 3 exploratory wells (US$ 13,107,000) before June 14,
2024. Part of the 3D seismic committed in the block has already been acquired during 2020 and 2021. On October
25, 2022, GeoPark submitted to the ANH a request to transfer the investment commitment related to the pending 3D
seismic to the Platanillo Block. As of the date of these Consolidated Financial Statements, such investment has been
fulfilled and the ANH approval is pending.
● PUT-9 Block: 3D seismic acquisition and 2 exploratory wells (US$ 10,550,000). GeoPark has signed a private
agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark
amounting to US$ 4,365,000. The exploratory period is currently suspended.
● PUT-14 Block: 2D seismic acquisition and 1 exploratory well (US$ 16,122,000). On March 10, 2022, GeoPark
submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer the pending commitments
to the Platanillo and CPO-5 Blocks. As of the date of these Consolidated Financial Statements, the total investments
needed to fulfill the commitments have already been incurred and the ANH approval is pending.
● The PUT-36 Block is in a preliminary phase that is suspended as of the date of these Consolidated Financial
Statements. During this preliminary phase, GeoPark must request from the Ministry of Interior a certificate that
indicates presence or no presence of indigenous communities and develop previous consultation, if applicable. Only
when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks
will enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the
block over three-years term of phase 1 would be 3D seismic acquisition and 2 exploratory wells (US$ 11,742,000).
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Table of Contents
● Tacacho Block: 2D seismic acquisition, processing and interpretation (US$ 4,080,000). GeoPark has signed a private
agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark
amounting to US$ 1,224,000. The exploratory period is currently suspended. On September 21, 2022, GeoPark
submitted to the ANH a request for termination of the E&P contract. As of the date of these Consolidated Financial
Statements, the request is under review by the ANH.
● Terecay Block: 2D seismic acquisition, processing and interpretation (US$ 4,046,000). GeoPark has signed a private
agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark
amounting to US$ 2,856,000. The exploratory period is currently suspended. On September 21, 2022, GeoPark
submitted to the ANH a request for termination of the E&P contract. As of the date of these Consolidated Financial
Statements, the request is under review by the ANH.
33.2.2 Ecuador
The investment commitments assumed by GeoPark, at its 50% working interest, in the Espejo and Perico Blocks during the
first exploratory period are up to:
● Espejo Block: 3D seismic and 4 exploratory wells before June 17, 2025 (US$ 20,912,000). As of the date of these
Consolidated Financial Statements, GeoPark has already performed the 3D seismic and drilled two of the four
committed exploratory wells.
● Perico Block: 4 exploratory wells before June 16, 2025 (US$ 18,084,000). As of the date of these Consolidated
Financial Statements, the total investments needed to fulfill the commitments in the block have already been
incurred.
33.2.3 Brazil
The future investment commitments assumed by GeoPark are up to:
● POT-T-785 Block: 3D seismic and electromagnetic survey before April 29, 2025 (US$ 72,000).
● REC-T-58 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000).
● REC-T-67 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000).
● REC-T-77 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000).
● POT-T-834 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000).
33.2.4 Chile
The remaining investment commitments to be assumed 100% by GeoPark for the second exploratory phase in the Campanario
and Isla Norte Blocks are up to:
● Campanario Block: 2 exploratory wells before April 25, 2024 (US$ 5,002,000).
● Isla Norte Block: 1 exploratory well before February 19, 2024 (US$ 867,000).
As of December 31, 2023, the Group has established guarantees for its total commitments.
As part of the divesting process detailed in Note 36.1, GeoPark remains responsible for these outstanding investment
commitments and consequently recognized a corresponding liability as of December 31, 2023.
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Table of Contents
Note 34 Related parties
Controlling interest
The main shareholders of GeoPark Limited as of December 31, 2023, based solely on Schedules 13D and 13G filed with the
SEC, are:
Shareholder
James F. Park (a)
Gerald E. O’Shaughnessy (b)
Compass Group LLC (c)
Renaissance Technologies LLC (d)
Socoservin Overseas SPF S.à.r.l. (e)
Cobas Asset Management, SGIIC, SA (f)
Other shareholders
Common
shares
8,817,251
3,673,392
3,312,589
3,091,863
2,889,315
2,808,406
30,734,704
55,327,520
Percentage of outstanding
common shares
15.94 %
6.64 %
5.99 %
5.59 %
5.22 %
5.08 %
55.54 %
100.00 %
(a) Held by James F. Park directly and indirectly through GoodRock, LLC, which is controlled by Mr. Park. The information
set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G
filed with the SEC on February 14, 2024. 352,400 of Mr. Park’s shares have been pledged pursuant to lending
arrangements.
(b) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP; GPK Holdings, LLC; The Globe
Resources Group, Inc.; and other investment vehicles. The information set forth above and listed in the table is based
solely on the disclosure set forth in Mr. O’Shaughnessy most recent Schedule 13D filed with the SEC on February 2,
2024. 3,435,000 of Mr. O’Shaughnessy’s shares have been pledged pursuant to lending arrangements.
(c) The information set forth above and listed in the table is based solely on the disclosure set forth in Compass Group LLC’s
most recent Schedule 13G filed with the SEC on February 14, 2024.
(d) The information set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most
recent Schedule 13G filed with the SEC on February 13, 2024.
(e) The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’
most recent Schedule 13G filed with the SEC on July 25, 2023.
(f) The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset
Management’s most recent Schedule 13G filed with the SEC on February 12, 2024.
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Table of Contents
Balances outstanding and transactions with related parties
Account (Amounts in US$´000)
2023
To be recovered from co-venturers
To be paid to co-venturers
2022
To be recovered from co-venturers
To be paid to co-venturers
Geological and geophysical expenses
Administrative expenses
2021
To be recovered from co-venturers
To be paid to co-venturers
Geological and geophysical expenses
Administrative expenses
Transaction
in the year
Balances
at year
end
Related Party
Relationship
— 8,630
(522)
—
Joint Operations
Joint Operations
Joint Operations
Joint Operations
— 8,750
— (2,815)
160
492
Joint Operations
Joint Operations
— Carlos Gulisano
— Pedro E. Aylwin
Joint Operations
Joint Operations
Former Non-Executive Director (a)
Former Executive Director (b)
— 4,680
—
(953)
160
656
Joint Operations
Joint Operations
— Carlos Gulisano
— Pedro E. Aylwin
Joint Operations
Joint Operations
Former Non-Executive Director (a)
Former Executive Director (b)
(a) Corresponding to consultancy services. Carlos Gulisano acted as a Director of the Company until July 2022.
(b) Corresponding to wages and salaries acting as Director of Legal and Governance. In 2022, also includes consultancy
services. In addition, Aylwin, Mendoza, Luksic & Valencia Law firm, where Pedro Aylwin is a partner and has a
participation through Asesorías e Inversiones A&P Ltda, provided general legal services to all the Chilean entities, in
Chilean corporate, labor, environmental, regulatory, and commercial laws.
There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related
parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial
Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11.
Note 35 Auditors Fees
Amounts in US$‘000
Audit fees
Audit related fees
Tax services fees
Total Auditors Fees
2023
2022
977
34
3
1,014
946
24
27
997
2021
1,088
—
47
1,135
Fees are shown net of VAT and other associated tax charges.
On October 17, 2023, Ernst & Young Audit S.A.S. (“EY Colombia”), member of Ernst & Young Global Limited, was
appointed as the Group’s external auditor, effective for the consolidated audit for the year ended December 31, 2023,
succeeding Pistrelli, Henry Martin y Asociados S.R.L. (“EY Argentina”), also member of Ernst & Young Global Limited, that
served as the Group’s external auditor from 2020 to 2023.
Note 36 Business transactions
36.1 Chile
On December 20, 2023, GeoPark signed a Stock Purchase Agreement to sell its wholly owned subsidiary GeoPark Chile
S.p.A. and its subsidiaries, GeoPark Fell S.p.A., GeoPark TdF S.p.A. and GeoPark Magallanes Limitada, which comprise the
entire business of GeoPark in Chile, for a total consideration of US$ 4,000,000, subject to working capital adjustments. At that
date, GeoPark collected an advanced payment of US$ 450,000.
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Table of Contents
As part of the agreement, GeoPark remains responsible for the outstanding investment commitments in the Campanario and
Isla Norte Blocks for US$ 5,002,000 and US$ 867,100, respectively. Consequently, as of December 31, 2023, GeoPark
recognized a liability for the full amount of those commitments.
Additionally, GeoPark keeps the private right over unconventional activities that would be carried out in the Fell Block and
95% of the revenue derived from such activities over the current operating contract.
The divestment transaction closed on January 18, 2024, and consequently GeoPark received an additional payment of US$
2,792,000, plus a preliminary working capital adjustment of US$ 486,000. The remaining outstanding amount of US$ 758,000
was agreed to be received in 23 monthly equal installments.
As of December 31, 2023, the amount of Property, plant and equipment and Right-of-use assets corresponding to the
abovementioned subsidiaries and the liabilities associated with them have been classified as held for sale for US$ 28,419,000
and US$ 26,948,000, respectively. Immediately before the classification as held for sale, the recoverable amount of the net
assets was estimated and an impairment loss of US$ 13,332,000 was recognized in the Consolidated Statement of Income. In
addition, the deferred income tax asset was written down for US$ 2,533,000 as it was assessed as non-recoverable due to the
transaction. The restructuring and other costs incurred because of the divestment process for US$ 3,873,000 were recognized
within the ‘Other (expenses) income’ line item in the Consolidated Statement of Income.
36.2 Los Parlamentos Block (Argentina)
On October 27, 2023, GeoPark agreed to transfer its 50% working interest in the Los Parlamentos Block in Argentina to its
joint operation partner and thus, once formally approved by local authorities, GeoPark will no longer be liable to remaining
capital commitments or other legal obligations resulting from its participation in the block. As a result of this transaction,
GeoPark incurred in a net loss of US$ 2,939,000 in the Consolidated Statement of Income, which is composed by a loss of
US$ 7,023,000 within the ‘Other (expenses) income’ line item due to the payment to the joint operation partner, net of a gain
of US$ 4,084,000 within the ‘Foreign exchange (loss) gain’ line item due to transactions with U.S. dollar-denominated
Argentine securities contributed to the local subsidiary when transferred and disposed in Argentina.
36.3 Aguada Baguales, El Porvenir and Puesto Touquet Blocks (Argentina)
In August 2021, the Company’s Board of Directors approved the decision to evaluate farm-out or divestment opportunities to
sell its 100% working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina,
including the associated gas transportation license through the Puesto Touquet pipeline.
On November 3, 2021, GeoPark signed a sale and purchase and assignment agreement for a total consideration of US$
16,000,000, subject to working capital adjustment. At that moment, GeoPark collected an advance payment of US$ 1,600,000.
The divestment transaction closed on January 31, 2022, after the corresponding regulatory approvals were granted and
GeoPark received the remaining outstanding payment from the purchaser. In April 2022, GeoPark paid a working capital
adjustment amounting to US$ 370,000. As a consequence of this transaction, GeoPark recognized a gain of US$ 3,983,000
within the ‘Other (expenses) income’ line item.
As of December 31, 2021, the amount of Property, plant and equipment related to the blocks and the liabilities associated with
them had been classified as held for sale. Immediately before the classification as held for sale, the recoverable amount of the
blocks was estimated and an impairment reversal of US$ 13,307,000 was recognized in the Consolidated Statement of
Income. The reversal was limited so that the carrying amount of the blocks does not exceed the lower of its recoverable
amount, or the carrying amount that would have been determined, net of depreciation, had no impairment loss been
recognized for the blocks in prior years (see Note 37).
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36.4 REC-T-128 Block (Brazil)
In 2021, GeoPark performed a farm-out transaction to sell its 70% interest in the REC-T-128 Block in Brazil. The total
consideration was US$ 1,100,000, which was collected at closing in 2021, plus a contingent payment of up to US$ 710,000,
subject to international oil price and field production performance. On August 1, 2022, GeoPark collected the contingent
payment of US$ 710,000.
Note 37 Impairment test on Property, plant and equipment
The management of the Group considers as cash-generating unit (“CGU”) each of the blocks or group of blocks in which the
Group has working or economic interests. The blocks with no material investment on property, plant and equipment or with
operations that are not linked to oil and gas prices were not subject to the impairment test.
As of December 31, 2023, the Chilean business divestment transaction described in Note 36.1 was considered to be an
impairment indicator for the Fell Block, as the carrying amount of the net assets related to the block exceeded their fair value
less cost of disposal. Consequently, the net assets related to the Fell Block were impaired to their known selling price.
Additionally, Management assessed impairment indicators for each of the other CGUs, such as future Brent oil prices based
on internal estimates and other available sources, the amounts of reserves certified by D&M, changes in market and tax
conditions, between others, and concluded that there were no impairment indicators at year-end.
As a consequence of the evaluation, the following amounts of impairment loss were (recognized) reversed:
Amounts in US$‘000
Chile (a)
Argentina (b)
2023
(13,332)
—
(13,332)
2022
2021
— (17,641)
— 13,307
— (4,334)
(a) Recognition of impairment loss in the Fell Block due to the known selling price of the related net assets in the context of
the transaction described in Note 36.1 in 2023, and due to the decline in the proved reserves estimation in 2021.
(b) Reversal of impairment loss in the Aguada Baguales and El Porvenir Blocks due to the known market price of the blocks
in the context of the transaction described in Note 36.3.
Note 38 Supplemental information on oil and gas activities (unaudited)
The following information is presented in accordance with ASC No. 932 “Extractive Activities- Oil and Gas”, as amended by
ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the
current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published
on December 31, 2008. This information includes the Group’s oil and gas production activities carried out in each country.
Table 1 - Costs incurred in exploration, property acquisitions and development
The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended
December 31, 2023, 2022 and 2021. The acquisition of properties includes the cost of acquisition of proved or unproved oil
and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped
properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for
developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary
costs to maintain facilities for the existing developed reserves.
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Table of Contents
Amounts in US$‘000
Year ended December 31, 2023
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development (a)
Total costs incurred
Amounts in US$‘000
Year ended December 31, 2022
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development (a)
Total costs incurred
Amounts in US$‘000
Year ended December 31, 2021
Acquisition of properties
Proved
Unproved
Total property acquisition
Exploration
Development (a)
Total costs incurred
Colombia
Ecuador
Brazil
Chile
Argentina
Total
—
—
—
66,953
125,997
192,950
—
—
—
13,331
372
13,703
—
—
—
107
255
362
—
—
—
56
(564)
(508)
—
—
—
1,481
—
1,481
—
—
—
81,928
126,060
207,988
Colombia Ecuador
Brazil
Chile
Argentina
Total
—
—
—
48,771
89,231
138,002
—
—
—
26,521
648
27,169
—
—
—
—
(212)
(212)
—
—
—
116
9,952
10,068
—
—
—
779
—
779
—
—
—
76,187
99,619
175,806
Colombia
Brazil
Chile
Argentina
Total
—
—
—
40,828
81,310
122,138
—
—
—
3
(2,212)
(2,209)
—
—
—
3,940
1,900
5,840
—
—
—
998
2
1,000
—
—
—
45,769
81,000
126,769
(a)
Includes the effect of change in estimate of assets retirement obligations.
Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as of December 31, 2023, 2022 and 2021, for proved and unproved oil and
gas properties, and the related accumulated depreciation as of those dates.
Amounts in US$‘000
As of December 31, 2023
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects
Unproved properties
Gross capitalized costs
Accumulated depreciation
Total net capitalized costs
Colombia Ecuador Brazil
Chile (b)
Total
165,666
841,063
15,770
69,823
1,092,322
(447,716)
644,606
—
31,149
—
10,426
41,575
(8,522)
33,053
4,121
48,448
11
330
52,910
(47,388)
5,522
74,491
330,024
—
—
404,515
(379,448)
25,067
244,278
1,250,684
15,781
80,579
1,591,322
(883,074)
708,248
(a)
Includes capitalized amounts related to asset retirement obligations and impairment loss recognized in Chile for US$
13,332,000.
(b) Classified as ‘Assets held for sale’ as of December 31, 2023, due to the divestment process closed in January 2024. See
Note 36.1.
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Table of Contents
Amounts in US$‘000
As of December 31, 2022
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects
Unproved properties
Gross capitalized costs
Accumulated depreciation
Total net capitalized costs
Colombia Ecuador Brazil
Chile
Total
144,672
672,424
16,099
102,760
935,955
(354,981)
580,974
—
18,191
—
9,991
28,182
(2,316)
25,866
3,565
44,716
268
290
48,839
(42,885)
5,954
74,490
343,926
113
—
418,529
(371,171)
47,358
222,727
1,079,257
16,480
113,041
1,431,505
(771,353)
660,152
(a) Includes capitalized amounts related to asset retirement obligations.
Amounts in US$‘000
As of December 31, 2021
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
Other uncompleted projects
Unproved properties (b)
Gross capitalized costs
Accumulated depreciation
Total net capitalized costs
Colombia Brazil
Chile
Argentina
Total
125,078
580,931
26,136
94,419
826,564
(282,616)
543,948
3,333
42,008
250
271
45,862
(38,741)
7,121
72,766
334,993
818
—
408,577
(358,417)
50,160
201,177
—
957,932
—
27,204
—
—
94,690
— 1,281,003
— (679,774)
601,229
—
(b) Includes capitalized amounts related to asset retirement obligations, impairment loss recognized in Chile for US$
17,641,000 and impairment loss reversed in Argentina for US$ 13,307,000.
(a) Do not include Ecuador capitalized costs.
Table 3 - Results of operations for oil and gas producing activities
The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and
gas producing activities for the years ended December 31, 2023, 2022 and 2021. Income tax for the years presented was
calculated utilizing the statutory tax rates.
Amounts in US$‘000
Year ended December 31, 2023
Revenue
Production costs, excluding depreciation
Operating costs
Royalties and economic rights in cash
Total production costs
Exploration expenses
Accretion expense (a)
Impairment loss for non-financial assets
Depreciation, depletion and amortization
Results of operations before income tax
Income tax expense
Results of oil and gas operations
Colombia Ecuador Brazil
Chile
Argentina
Total
702,401
19,097
14,019
15,644
— 751,161
(10,242)
(10,242)
(309)
(87)
—
(6,205)
2,254
(564)
1,690
(3,850)
— (1,096)
(4,946)
(90)
(560)
(7,678)
(548)
(8,226)
(56)
(1,478)
— (13,332)
(8,278)
(15,726)
—
(15,726)
(1,047)
7,376
(2,508)
4,868
— (142,782)
— (84,877)
— (227,659)
(38,331)
(1,481)
—
(2,794)
— (13,332)
— (108,265)
360,780
— (168,833)
191,947
(1,481)
(1,481)
(121,012)
(83,233)
(204,245)
(36,395)
(669)
—
(92,735)
368,357
(165,761)
202,596
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Table of Contents
Amounts in US$‘000
Year ended December 31, 2022
Revenue
Production costs, excluding depreciation
Operating costs
Royalties and economic rights in cash
Total production costs
Exploration expenses
Accretion expense (a)
Depreciation, depletion and amortization
Results of operations before income tax
Income tax expense
Results of oil and gas operations
Amounts in US$‘000
Year ended December 31, 2021
Revenue
Production costs, excluding depreciation
Operating costs
Royalties and economic rights in cash
Total production costs
Exploration expenses
Accretion expense (a)
Impairment loss for non-financial assets
Depreciation, depletion and amortization
Results of operations before income tax
Income tax (expense) benefit
Results of oil and gas operations
Colombia Ecuador Brazil
Chile
Argentina
Total
978,423
10,671
19,873
29,196
1,962
1,040,125
(78,323)
(249,303)
(327,626)
(28,424)
(621)
(72,386)
549,366
(192,278)
357,088
(3,220)
(3,753)
— (1,546)
(5,299)
—
(504)
(1,509)
12,561
(4,271)
8,290
(3,220)
(4,768)
—
(2,315)
368
(92)
276
(12,961)
(1,165)
(14,126)
(116)
(1,516)
(12,754)
684
(103)
581
(1,306)
(273)
(1,579)
(779)
—
—
(396)
(99,563)
(252,287)
(351,850)
(34,087)
(2,641)
(88,964)
562,583
— (196,744)
365,839
(396)
Colombia Brazil
Chile
Argentina
Total
618,268
20,109
21,471
28,695
688,543
(72,043)
(106,341)
(178,384)
(11,276)
(576)
—
(54,588)
373,444
(115,768)
257,676
(2,954)
(1,642)
(4,596)
(10,280)
(770)
(11,050)
(14,490)
(4,270)
(18,760)
(535)
— (4,509)
(1,319)
— (17,641)
(12,806)
(25,854)
3,878
(21,976)
(2,933)
12,045
(4,095)
7,950
(998)
(710)
13,307
(8,152)
13,382
(4,684)
8,698
(99,767)
(113,023)
(212,790)
(16,783)
(3,140)
(4,334)
(78,479)
373,017
(120,669)
252,348
(a) Represents accretion of ARO and other environmental liabilities.
Table 4 - Reserve quantity information
Estimated oil and gas reserves
Proved reserves represent estimated quantities of oil (including crude oil and condensate) and natural gas, which available
geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs
under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be
expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or
combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and
reliability of basic data, and production history.
The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such
estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued
by the SEC at the end of 2008.
The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, 2023, 2022, 2021
and 2020 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and
MacNaughton Corp. 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
F-68
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932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no.
69 Disclosures about Oil and Gas Producing Activities).
Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be exactly measured,
and the reserve estimation depends on the quality of available information and the interpretation and judgement of the
engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the
quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the
assumptions on which they are based.
The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2023, 2022, 2021 and 2020 are
summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
As of December 31, 2023
As of December 31, 2022
As of December 31, 2021
As of December 31, 2020
Oil and
Oil and
Oil and
condensate Natural gas
condensate Natural gas
condensate Natural gas
(Mbbl)
(MMcf)
(Mbbl)
(MMcf)
(Mbbl)
(MMcf)
Oil and
condensate
(Mbbl)
Natural gas
(MMcf)
Net proved developed
Colombia (a)
Ecuador (b)
Brazil (c)
Chile (d)
Argentina (e)
Total consolidated
Net proved undeveloped
Colombia (f)
Ecuador (b)
Chile (d)
Argentina (g)
Total consolidated
43,120
1,017
28
619
—
44,784
16,225
1,278
479
—
17,982
1,075
—
8,888
9,956
—
19,919
46,623
322
8
1,115
—
48,068
1,065
—
9,443
14,103
—
24,611
47,766
—
43
755
1,186
49,750
1,207
—
13,601
15,196
3,379
33,383
43,817
—
34
798
1,685
46,334
— 17,765
—
—
476
855
—
—
18,241
855
— 31,019
—
—
—
575
603
—
— 32,197
— 45,240
—
—
1,229
1,563
104
—
46,573
1,563
1,695
—
13,927
19,054
5,599
40,275
—
—
5,661
—
5,661
Total proved reserves
62,766
20,774
66,309
24,611
81,947
34,946
92,907
45,936
(a) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 94% and 6% (96% and
4% in 2022, 98% and 2% in 2021, and 97% and 3% in 2020) of the proved developed reserves, respectively.
(b) Perico Block accounts for 100% of the reserves (Perico and Espejo Blocks accounted for 85% and 15% of the reserves,
respectively, in 2022).
(c) BCAM-40 Block accounts for 100% of the reserves.
(d) Fell Block accounts for 100% of the reserves.
(e) Aguada Baguales, Puesto Touquet and El Porvenir Blocks accounted for 45%, 21% and 33% in 2021 (50%, 26% and
24% in 2020) of the proved developed reserves, respectively.
(f) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 97% and 3% (95% and
5% in 2022, 97% and 3% in 2021, and 96% and 4% in 2020) of the proved undeveloped reserves, respectively.
(g) Aguada Baguales Block accounted for 100% of the proved undeveloped reserves.
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Table 5 - Net proved reserves of oil, condensate and natural gas
Net proved reserves (developed and undeveloped) of oil and condensate:
Thousands of barrels
Reserves as of December 31, 2020
Increase (decrease) attributable to:
Revisions (a)
Extensions and discoveries (b)
Production
Reserves as of December 31, 2021
Increase (decrease) attributable to:
Revisions (c)
Extensions and discoveries (d)
Disposal of Minerals in place (e)
Production
Reserves as of December 31, 2022
Increase (decrease) attributable to:
Revisions (f)
Extensions and discoveries (g)
Production
Reserves as of December 31, 2023
Colombia
89,057
Ecuador
—
Brazil
34
Chile
2,027
Argentina
1,789
Total
92,907
(3,207)
3,375
(10,440)
78,785
(2,677)
204
—
(11,924)
64,388
3,617
2,549
(11,209)
59,345
—
—
—
—
—
632
—
(310)
322
324
1,937
(288)
2,295
18
—
(9)
43
(27)
—
—
(8)
8
26
—
(6)
28
(597)
—
(100)
1,330
(169)
603
(434)
1,789
(3,955)
3,978
(10,983)
81,947
— (2,282)
422
836
—
—
(1,760)
— (1,760)
(29)
(12,432)
— 66,309
(161)
1,591
(412)
—
(81)
1,098
3,555
—
—
4,486
— (11,584)
— 62,766
(a) For the year ended December 31, 2021, the Group’s oil and condensate proved reserves were revised downward by 4.0
mmbbl. The primary factors leading to the above were:
- Lower than expected performance from the existing wells that reduced the proved developed reserves in Colombia (8.9
mmbbl), in Argentina (0.3 mmbbl), and in Chile (0.3 mmbbl).
- A decrease of 0.6 mmbbl in Chile due to a change in a previously adopted development plan in the Fell Block.
- Such decrease was partially offset by a higher average oil prices resulted in a 5.7 mmbbl, 0.1 mmbbl and 0.3 mmbbl
increase in reserves from the blocks in Colombia, Argentina and Chile, respectively.
(b)
In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Argentina are due
to the Aguada Baguales Field.
(c) For the year ended December 31, 2022, the Group’s oil and condensate proved reserves were revised downward by 2.3
mmbbl. The primary factors leading to the above were:
- A decrease of 3.6 mmbbl in Colombia due to a change in the royalties payment in certain fields from cash to kind.
- Such decrease was partially offset by a higher average oil prices resulted in a 0.6 mmbbl and 0.1 mmbbl increase in
reserves from the blocks in Colombia and Chile, respectively.
- Higher than expected performance from the existing wells that increase the proved reserves in Colombia (0.3 mmbbl)
and in Chile (0.3 mmbbl).
(d)
In Colombia, the extensions and discoveries are primary due to the Cante Flamenco new field in CPO-5 Block and in
Ecuador are due to the Jandaya, Yin and Tui new fields in the Perico Block and the Pashuri field in the Espejo Block.
(e) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada
Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3).
(f) For the year ended December 31, 2023, the Group’s oil and condensate proved reserves were revised upwards by 3.5
mmbbl. The primary factors leading to the above were:
- An increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan.
- An increase of 1.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells.
- An increase of 0.4 mmbbl in Colombia due to a change in the royalties’ payment in certain fields from kind to cash.
- An increase of 0.3 mmbbl in Ecuador due to higher average oil prices.
- Such increase was partially offset by lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl.
(g) The extensions and discoveries are primarily due to various fields in the Llanos Basin in Colombia and the Jandaya field
extension in the Perico Block in Ecuador.
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Net proved reserves (developed and undeveloped) of natural gas:
Millions of cubic feet
Reserves as of December 31, 2020
Increase (decrease) attributable to:
Revisions (a)
Production
Reserves as of December 31, 2021
Increase (decrease) attributable to:
Revisions (b)
Disposal of Minerals in place (c)
Production
Reserves as of December 31, 2022
Increase (decrease) attributable to:
Revisions (d)
Production
Reserves as of December 31, 2023
Colombia Brazil
Chile
1,695
13,927
24,715
Argentina
5,599
Total
45,936
14
(502)
1,207
141
—
(283)
1,065
219
(209)
1,075
3,470
(3,796)
13,601
(886)
—
(3,272)
9,443
1,659
(2,214)
8,888
(3,553)
(4,403)
16,759
1,501
—
(4,157)
14,103
(9)
(3,283)
10,811
(636)
(1,584)
3,379
(705)
(10,285)
34,946
—
(3,227)
(152)
—
756
(3,227)
(7,864)
24,611
1,869
—
—
(5,706)
— 20,774
(a) For the year ended December 31, 2021, the Group’s proved natural gas reserves were revised downward by 0.7 billion
cubic feet. This was the combined effect of:
- A decrease of proved developed reserves due to lower performance of existing wells in Argentina (1.6 billion cubic
feet) and in Chile (2.7 billion cubic feet) partially offset by better-than-expected performance in the Manati Field in
Brazil (2.5 billion cubic feet).
- A decrease of 3.4 billion cubic feet in Chile due to the revision of the type well associated with the incremental activity
that reduced the proved undeveloped reserves.
- A decrease of 1.5 billion cubic feet in Chile due to a change in a previously adopted development plan in the Fell
Block.
-Such decrease was partially offset by higher average prices which resulted in an increase of 4.0 billion cubic feet, 1
billion cubic feet and 1 billion cubic feet in Chile, Brazil, and Argentina, respectively.
(b) For the year ended December 31, 2022, the Group’s proved natural gas reserves were revised upwards by 0.8 billion
cubic feet. This was the combined effect of:
- An increase of proved reserves due to better performance of existing wells in Chile (0.8 billion cubic feet) and the
Llanos 32 block in Colombia (0.1 billion cubic feet).
- Higher average prices resulted in an increase of 0.7 billion cubic feet and 0.8 billion cubic feet increase in gas reserves
in Chile and Brazil, respectively.
- The above was partially offset by lower-than-expected performance of Manati Field in Brazil (1.6 billion cubic feet).
(c) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada
Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3).
(d) For the year ended December 31, 2023, the Group’s proved natural gas reserves were revised upwards by 1.9 billion
cubic feet. This was the effect of higher-than-expected performance from the existing wells in the Manati Block in Brazil
(1.7 billion cubic feet) and the Llanos 32 Block in Colombia (0.2 billion cubic feet).
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 2023, 2022 and 2021 and using a 10% annual discount factor.
Future development and abandonment costs include estimated drilling costs, development and exploitation
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installations and abandonment costs. These future development costs were estimated based on evaluations made by the Group.
The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have
interests, as of the date this supplementary information was filed.
This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the
Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to
compare different companies and make certain projections. It is important to point out that this information does not include,
among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to
occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a
discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of
oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these
reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows
derived from the reserves of hydrocarbons.
Amounts in US$‘000
As of December 31, 2023
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
As of December 31, 2022
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
As of December 31, 2021
Future cash inflows
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
Colombia Ecuador Brazil
Chile
Argentina
Total
140,607
(45,052)
(13,768)
(27,648)
54,139
(11,436)
42,703
75,757
(22,815)
(1,204)
(4,036)
47,702
(6,476)
41,226
26,553
(8,094)
(297)
65,002
(29,519)
(1,955)
— (1,761)
31,767
(8,856)
22,911
18,162
(2,504)
15,658
— 89,208
— (34,930)
— (1,955)
— (3,449)
— 48,874
— (7,171)
— 41,703
111,384
(50,343)
(41,359)
—
19,682
5,205
24,887
190,449
(72,411)
(40,659)
—
77,379
(13,094)
64,285
136,152
(69,067)
(40,339)
—
26,746
6,121
32,867
— 4,355,434
— (1,752,099)
(203,376)
—
—
(795,993)
— 1,603,966
—
(442,957)
— 1,161,009
— 5,511,603
— (1,743,842)
—
(225,612)
— (1,193,419)
— 2,348,730
—
(864,075)
— 1,484,655
109,678
(61,660)
(49,200)
(2,947)
(4,129)
4,471
342
4,716,229
(1,881,211)
(288,955)
(760,601)
1,785,462
(492,729)
1,292,733
4,027,686
(1,633,889)
(147,045)
(764,309)
1,482,443
(430,250)
1,052,193
5,229,599
(1,633,818)
(182,701)
(1,191,658)
2,221,422
(839,621)
1,381,801
4,381,191
(1,715,554)
(197,461)
(754,205)
1,713,971
(496,150)
1,217,821
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Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves
Colombia Ecuador Brazil
— 25,378
759,233
Amounts in US$‘000
Present value as of December 31, 2020
Sales of hydrocarbon, net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Net changes in income taxes
Accretion of discount
Present value as of December 31, 2021
Sales of hydrocarbon, net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Disposal of Minerals in place
Net changes in income taxes
Accretion of discount
Present value as of December 31, 2022
Sales of hydrocarbon, net of production costs
Net changes in sales price and production costs
Changes in estimated future development costs
Extensions and discoveries less related costs
Development costs incurred
Revisions of previous quantity estimates
Net changes in income taxes
Accretion of discount
Present value as of December 31, 2023
Chile
Argentina
17,032
(11,520)
64,048
(18,731)
—
4,111
(23,776)
—
1,703
32,867
(19)
(16,855)
(3,145)
20,674
(1,020)
—
465
244
(2)
342
Total
801,624
(560,896)
1,005,171
99,168
79,913
91,988
(88,204)
(257,154)
121,123
1,292,733
— (15,677)
— 19,393
861
—
—
—
—
—
— 11,957
— (2,780)
—
2,571
— 41,703
(2,732)
(15,317)
(14,697)
39,457
— (6,909)
(22,675)
(933)
—
—
— 11,153
15,513
—
—
3,287
64,285
(10,483)
28,873
—
— (2,441)
—
—
1,673
—
4,515
—
22,911
15,658
(6,673)
(2,893)
(17,908)
63,619
500
10,642
(21,808)
1,566
42,703
(8,143)
21,490
(4,440)
—
—
9,159
(2,218)
2,467
41,226
(6,362)
(33,595)
5,142
—
7
(11,019)
—
6,429
24,887
— (924,280)
989,474
—
59,566
—
35,627
—
105,348
—
(74,779)
—
(342)
(342)
— (203,697)
—
205,005
— 1,484,655
— (512,703)
— (611,666)
(7,745)
—
136,376
—
116,503
—
113,038
—
174,743
—
—
267,808
— 1,161,009
(516,844)
924,875
96,364
80,933
87,877
(76,850)
(254,618)
116,851
1,217,821
(891,534)
956,926
93,657
6,754
94,195
(87,851)
—
(205,370)
197,203
1,381,801
(491,525)
(596,668)
9,461
72,757
115,996
104,256
198,769
257,346
1,052,193
F-73
Exhibit 2.4
DESCRIPTION OF SECURITIES
The following description of our capital stock is a summary and does not purport to be complete. It is subject to
and qualified in its entirety by reference to our by-laws, which are incorporated by reference as an exhibit to the
Annual Report on Form 20-F for the year ended December 31, 2023 of which this Exhibit is a part. We encourage
you to read the bylaws for additional information.
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 by-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.
Share Capital
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 March 19, 2024, there are 55,470,850 common shares
outstanding. All of our issued and outstanding common shares are fully paid and non-assessable. We also have
employee incentive programs, pursuant to which we have granted share awards to our senior management and
certain key 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.
Shareholders’ rights
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.
Election and Removal of Directors
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 nine 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.
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.
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.
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.
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.
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.
Comparison of Bermuda law to Delaware Corporate Law
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 mergers and acquisitions, takeovers and
shareholder lawsuits. 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. Because the
following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us
and our shareholders.
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’ 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. 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.
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.
Exhibit 8.1
Jurisdiction
Details of the subsidiaries of GeoPark Limited as of December 31, 2023, are set out below:
Name
GeoPark Argentina S.A.
GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.
GeoPark Chile S.p.A.
GeoPark Fell S.p.A.
GeoPark Magallanes Limitada
GeoPark TdF S.p.A.
GeoPark Colombia S.A.S.
GeoPark Colombia S.A.S. Sucursal Panama
GeoPark Colombia S.L.U.
GeoPark Perú S.A.C.
GeoPark Ecuador S.A.
GeoPark México S.A.P.I. de C.V.
GeoPark E&P S.A.P.I. de C.V.
GeoPark (UK) Limited
Amerisur Resources Limited
Amerisur Exploración Colombia Limited
Amerisur Exploración Colombia Limited Sucursal Colombia
Yarumal S.A.S.
Fenix Oil & Gas Limited
Fenix Oil & Gas Limited Sucursal Colombia
Amerisurexplor Ecuador S.A.
Amerisur S.A.
Market Access LLP
Argentina
Brazil
Chile
Chile
Chile
Chile
Colombia
Panama
Spain
Peru
Ecuador
Mexico
Mexico
United Kingdom
United Kingdom
British Virgin Islands
Colombia
Colombia
British Virgin Islands
Colombia
Ecuador
Paraguay
United States
CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 12.1
I, Andrés Ocampo, certify that:
1. I have reviewed this annual report on Form 20-F of GeoPark Limited;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods
presented in this report;
4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the company and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the company, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
d. Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the
period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the
company’s internal control over financial reporting; and
5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report
financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the
company’s internal control over financial reporting.
Date: March 27, 2024
/s/ Andrés Ocampo
Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 12.2
I, Jaime Caballero Uribe, certify that:
1.
I have reviewed this annual report on Form 20-F of GeoPark Limited;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods
presented in this report;
4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the company and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this
report based on such evaluation; and
d. Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the
period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s
internal control over financial reporting; and
5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial
information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the
company’s internal control over financial reporting.
Date: March 27, 2024
/s/ Jaime Caballero Uribe
Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 13.1
The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the
“Company”) for the fiscal year ended December 31, 2023 (the “Report”), I, Andrés Ocampo, certify pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:
1.
2.
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Date: March 27, 2024
/s/ Andrés Ocampo
Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO 18 U.S.C.
SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the
“Company”) for the fiscal year ended December 31, 2023 (the “Report”), I, Jaime Caballero Uribe, certify pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:
1.
2.
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Exhibit 13.2
Date: March 27, 2024
/s/ Jaime Caballero Uribe
Chief Financial Officer
(Principal Financial Officer)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the Registration Statements on Form S-8 (No 333-201016, No.333-214291, No.333-228762
and No.333-228763) of GeoPark Limited of our reports dated March 27, 2024, with respect to the consolidated financial statements of
GeoPark Limited and the effectiveness of internal control over financial reporting of GeoPark Limited, included in this Annual Report (Form
20-F) of GeoPark Limited for the year ended December 31, 2023. We also consent to the reference to our firm under the headings
“Presentation of Financial and Other Information”, “ITEM 15. CONTROLS AND PROCEDURES”, “ITEM 16C. Principal Accountant
Fees and Services” and “ITEM 16F. Change in registrant’s certifying accountant” in this Form 20-F.
Exhibit 15.1
ERNST & YOUNG AUDIT S.A.S.
By /s/ Ernst & Young Audit S.A.S.
Ernst & Young Audit S.A.S.
Member of Ernst & Young Global Limited
Bogota, Colombia
March 27, 2024
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the Registration Statements on Form S-8 (No 333-201016, No.333-214291, No.333-228762
and No.333-228763) of GeoPark Limited of our report dated March 8, 2023, with respect to the consolidated financial statements of
GeoPark Limited, included in this Annual Report (Form 20-F) of GeoPark Limited for the year ended December 31, 2023.
Exhibit 15.2
PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
By /s/ Pistrelli, Henry Martin y Asociados S.R.L.
Pistrelli, Henry Martin y Asociados S.R.L.
Member of Ernst & Young Global Limited
Buenos Aires, Argentina
March 27, 2024
Exhibit 15.3
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 27, 2024
GeoPark Limited
Calle 94 N° 11-30, 8o floor
Bogotá, Colombia
Ladies and Gentlemen:
As an independent petroleum consulting firm, we hereby consent to the incorporation by reference to our year-end 2023 report of
third party dated March 1, 2024, to be used under certain headings contained in the Annual Report of GeoPark Limited on Form 20-F for the
year ended December 31, 2023, and specified in our consent letter dated March 27, 2024, addressed to GeoPark Limited, which is
referenced in the previously filed Registration Statement on Form S-8 (File Nos. 333-201016, 333-214291, and 333-228763) under the
headings “PART II – Item 3. Incorporation of Documents by Reference” and “Part II – Item 8. Exhibits” and on Form S-8 (File No. 333-
228762) under the heading “Part II – Item 8. Exhibits.”
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 27, 2024
GeoPark Limited
Calle 94 N° 11 30, 8o floor
Bogotá, Colombia
Ladies and Gentlemen:
We hereby consent to the references to DeGolyer and MacNaughton and to the inclusion of and information derived from our 2023
year-end report of third party dated March 1, 2024, regarding our independent estimates of the net proved oil, condensate, gas, and oil
equivalent reserves, as of December 31, 2023, of certain selected properties in which GeoPark Limited has represented it holds an interest in
Brazil, Chile, Colombia and Ecuador (our “Report”), as set forth under the headings “Presentation of Financial and Other Information–Oil
and gas reserves and production information,” “Item 3. Key Information–D. Risk factors,” “Item 4. Information on the Company–B.
Business Overview,” “Item 5. Operating and Financial Review and Prospects–A. Operating results,” “Item 19 Exhibits,” and “GeoPark
Limited Consolidated Financial Statements as of and for the year ended December 31, 2023” and as Exhibit No. 99.1 in the Annual Report
on Form 20-F of GeoPark Limited (the “Annual Report”).
We confirm that we have read the Annual Report and have no reason to believe that there are any misrepresentations in the
information contained therein that are derived from our Report or that are within our knowledge as a result of the services performed by us
in connection with the preparation of our Report.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Exhibit 15.4
March 27, 2024
Securities and Exchange Commission
100 F Street, N.E.
Washington, DC 20549
Ladies and Gentlemen:
We have read item 16.F – “Change in Registrant’s Certifying Accountant” of the annual report on Form 20-F for the year ended December
31, 2023 of GeoPark Limited. We agree with the statements contained therein in relation to Pistrelli, Henry Martin y Asociados S.R.L. We
have no basis to agree or disagree with other statements of the registrant contained therein.
Very truly yours,
/s/ Pistrelli, Henry Martin y Asociados S.R.L.
PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
Member of Ernst & Young Global Limited
GEOPARK LIMITED
COMPENSATION RECOUPMENT POLICY
Exhibit 97.1
This GeoPark Compensation Recoupment Policy (the “Clawback Policy” or the “Policy”) has been adopted by the Board of Directors (the
“Board”) of GeoPark Limited (the “Company”) on 7 November 2023, following the recommendation of the Compensation Committee of
the Company. This Policy provides for the recoupment of certain executive compensation in the event of an accounting restatement resulting
from material noncompliance with financial reporting requirements under U.S. federal securities laws in accordance with the terms and
conditions set forth herein. This Policy is intended to comply with the requirements of Section 10D of the Exchange Act (as defined below)
and Section 303A.14 of the NYSE Listed Company Manual (the “Listing Rule”).
1.
(a)
(b)
(c)
(d)
(e)
(f)
Definitions. For the purposes of this Policy, the following terms shall have the meanings set forth below.
“Committee” means the Compensation Committee of the Board or any successor committee thereof.
“Covered Compensation” means any Incentive-based Compensation “received” by a Covered Executive during the applicable
Recoupment Period; provided that:
(i)
(ii)
Such Covered Compensation was received by such Covered Executive: (A) after the Effective Date, (B) after he or she
commenced service as an Executive Officer, and (C) while the Company had a class of securities publicly listed on a
United States national securities exchange; and
Such Covered Executive served as an Executive Officer at any time during the performance period applicable to such
Incentive-based Compensation.
For purposes of this Policy, Incentive-based Compensation is “received” by a Covered Executive during the fiscal period in which
the Financial Reporting Measure applicable to such Incentive-based Compensation (or portion thereof) is attained, even if the
payment or grant of such Incentive-based Compensation is made thereafter.
“Covered Executive” means any current or former Executive Officer.
“Effective Date” means the date on which Listing Rule becomes effective.
“Exchange Act” means the U.S. Securities Exchange Act of 1934, as amended.
“Executive Officer” means, with respect to the Company, (i) its chief executive officer, (ii) its chief financial officer, (iii) its
principal accounting officer or if there is no accounting officer, its controller, (iv) its chief people officer, (v) its chief technical
officer, (vi) its chief operational officer, (vii) its chief exploration officer and (viii) its chief strategy, sustainability and legal officer,
or any other officer or person that succeeds any of the above or that perform policy-making functions for the Company or otherwise
meet the definition of “executive officer” under the Listing Rule. Policy-making function is not intended to include policy-making
functions that are not significant. The determination as to an individual’s status as an Executive Officer shall be made by the
Committee and such determination shall be final, conclusive, and binding on such individual and all other interested persons.
Only for the purposes of this Policy, the principal accounting officer or if there is no accounting officer, its controller, shall be
considered as Executive Officers.
(g)
“Financial Reporting Measure” means any: (i) measure that is determined and presented in accordance with the accounting
principles used in preparing the Company’s financial statements, (ii) stock price measure, or (iii) total shareholder return measure
(and any measures that are derived wholly or in part from any measure referenced in clause (i), (ii) or (iii) above). For the
avoidance of doubt, any such measure does not need to be presented within the Company’s financial statements or included in a
filing with the U.S. Securities and Exchange Commission to constitute a Financial Reporting Measure.
(h)
“Financial Restatement” means a restatement of the Company’s financial statements due to the Company’s material
noncompliance with any financial reporting requirement under U.S. federal securities laws that is required in order to correct:
(i)
(ii)
an error in previously issued financial statements that is material to the previously issued financial statements; or
an error that would result in a material misstatement if (A) the error was corrected in the current period, or (B) left
uncorrected in the current period.
For purposes of this Policy, a Financial Restatement shall not be deemed to occur in the event of a revision of the Company’s
financial statements due to an out-of-period adjustment (i.e., when the error is immaterial to the previously issued financial
statements and the correction of the error is also immaterial to the current period), or a retrospective (1) application of a change in
accounting principles; (2) revision to reportable segment information due to a change in the structure of the Company’s internal
organization; (3) reclassification due to a discontinued operation; (4) application of a change in reporting entity, such as from a
reorganization of entities under common control; (5) revision for stock splits (share subdivisions), reverse stock splits (share
consolidations), stock dividends (bonus issues) or other changes in capital structure; or (6) adjustment to provisional amounts in
connection with a prior business combination.
“Incentive-based Compensation” means (i) awards under the Annual Long Term Incentive Program, (ii) awards under the Annual
Performance Cash Bonus, (iii) benefits under the Executive Termination and Change in Control Benefits Plan and (iv) any other
compensation (including, for the avoidance of doubt, any cash or equity or equity-based compensation, whether deferred or
current), in each case that is granted, earned and/or vested based wholly or in part upon the achievement of a Financial Reporting
Measure. For purposes of this Policy, “Incentive-based Compensation” shall also be deemed to include any amounts which were
determined based on (or were otherwise calculated by reference to) Incentive-based Compensation (including, without limitation,
any amounts under any long-term disability, life insurance or supplemental retirement or severance plan or agreement or any
notional account that is based on Incentive-based Compensation, as well as any earnings accrued thereon).
“NYSE” means the New York Stock Exchange, or any successor thereof.
“Recoupment Period” means the three fiscal years completed immediately preceding the date of any applicable Recoupment
Trigger Date. Notwithstanding the foregoing, the Recoupment Period additionally includes any transition period (that results from a
change in the Company’s fiscal year) within or immediately following those three completed fiscal years, provided that a transition
period between the last day of the Company’s previous fiscal year end and the first day of its new fiscal year that comprises a
period of nine (9) to twelve (12) months would be deemed a completed fiscal year.
“Recoupment Trigger Date” means the earlier of: (i) the date that the Board (or a committee thereof or the officer(s) of the
Company authorized to take such action if Board action is not required) concludes, or reasonably should have concluded, that the
Company is required to prepare a Financial
(j)
(k)
(l)
(m)
2
2.
(a)
(b)
(c)
(d)
Restatement, and (ii) the date on which a court, regulator or other legally authorized body directs the Company to prepare a
Financial Restatement.
Recoupment of Erroneously Awarded Compensation.
In the event of a Financial Restatement, if the amount of any Covered Compensation received by a Covered Executive (the
“Awarded Compensation”) exceeds the amount of such Covered Compensation that would have otherwise been received by such
Covered Executive if calculated based on the Financial Restatement (the “Adjusted Compensation”), the Company shall
reasonably promptly recover from such Covered Executive an amount equal to the excess of the Awarded Compensation over the
Adjusted Compensation, each calculated on a pre-tax basis (such excess amount, the “Erroneously Awarded Compensation”).
If: (i) the Financial Reporting Measure applicable to the relevant Covered Compensation is stock price or total shareholder return
(or any measure derived wholly or in part from either of such measures), and (ii) the amount of Erroneously Awarded
Compensation is not subject to mathematical recalculation directly from the information in the Financial Restatement, then the
amount of Erroneously Awarded Compensation shall be determined (on a pre-tax basis) based on the Company’s reasonable
estimate of the effect of the Financial Restatement on the Company’s stock price or total shareholder return (or the derivative
measure thereof) upon which such Covered Compensation was received.
For the avoidance of doubt, the Company’s obligation to recover Erroneously Awarded Compensation is not dependent on: (i) if or
when the restated financial statements are filed; or (ii) any fault of any Covered Executive for the accounting errors or other actions
leading to a Financial Restatement.
Notwithstanding anything to the contrary in Sections 2 (a) through (c) hereof, the Company shall not be required to recover any
Erroneously Awarded Compensation if both (x) the conditions set forth in either of the following clauses (i), (ii), or (iii) are
satisfied, and (y) the Committee (or a majority of the independent directors serving on the Board) has determined that recovery of
the Erroneously Awarded Compensation would be impracticable:
(i)
(ii)
the direct expense paid to a third party to assist in enforcing the recovery of the Erroneously Awarded Compensation under
this Policy would exceed the amount of such Erroneously Awarded Compensation to be recovered; provided that, before
concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation pursuant to this
Section 2 (d) (i), the Company shall have first made a reasonable attempt to recover such Erroneously Awarded
Compensation, document such reasonable attempt(s) to make such recovery and provide that documentation to the NYSE;
recovery of the Erroneously Awarded Compensation would violate Bermuda law to the extent such law was adopted prior
to November 28, 2022 (provided that, before concluding that it would be impracticable to recover any amount of
Erroneously Awarded Compensation pursuant to this Section 2 (d) (ii)), the Company shall have first obtained an opinion of
home country counsel of Bermuda, that is acceptable to the NYSE, that recovery would result in such a violation, and the
Company must provide such opinion to the NYSE; or
(iii)
recovery of the Erroneously Awarded Compensation would likely cause an otherwise tax-qualified retirement plan, under
which benefits are broadly available to employees of the Company, to fail to meet the requirements of Sections 401(a)(13)
or 411(a) of the U.S. Internal Revenue Code of 1986, as amended (the “Code”).
(e)
The Company shall not indemnify any Covered Executive, directly or indirectly, for any losses that such Covered Executive may
incur in connection with the recovery of Erroneously Awarded
3
(f)
3.
4.
5.
6.
Compensation pursuant to this Policy, including through the payment of insurance premiums or gross-up payments.
The Committee shall determine, in its sole discretion, the manner and timing in which any Erroneously Awarded Compensation
shall be recovered from a Covered Executive in accordance with applicable law, including, without limitation, by (i) requiring
reimbursement of Covered Compensation previously paid in cash; (ii) seeking recovery of any gain realized on the vesting,
exercise, settlement, sale, transfer or other disposition of any equity or equity-based awards; (iii) offsetting the Erroneously
Awarded Compensation amount from any compensation otherwise owed by the Company or any of its affiliates to the Covered
Executive; (iv) cancelling outstanding vested or unvested equity or equity-based awards; and/or (v) taking any other remedial and
recovery action permitted by applicable law. For the avoidance of doubt, except as set forth in Section 2(d), in no event may the
Company accept an amount that is less than the amount of Erroneously Awarded Compensation; provided that, to the extent
necessary to avoid any adverse tax consequences to the Covered Executive pursuant to Section 409A of the Code, any offsets
against amounts under any nonqualified deferred compensation plans (as defined under Section 409A of the Code) shall be made in
compliance with Section 409A of the Code.
Administration. This Policy shall be administered by the Committee. All decisions of the Committee shall be final, conclusive and
binding upon the Company and the Covered Executives, their beneficiaries, executors, administrators and any other legal
representative. The Committee shall have full power and authority to: (i) administer and interpret this Policy; (ii) correct any defect,
supply any omission and reconcile any inconsistency in this Policy; and (iii) make any other determination and take any other
action that the Committee deems necessary or desirable for the administration of this Policy and to comply with applicable law
(including Section 10D of the Exchange Act) and applicable stock market or exchange rules and regulations. Notwithstanding
anything to the contrary contained herein, to the extent permitted by Section 10D of the Exchange Act and Section 303A.14 of the
NYSE Listed Company Manual, the Board may, in its sole discretion, at any time and from time to time, administer this Policy in
the same manner as the Committee.
Amendment/Termination. Subject to Section 10D of the Exchange Act and Section 303A.14 of the NYSE Listed Company Manual,
this Policy may be amended or terminated by the Committee at any time. To the extent that any applicable law, or stock market or
exchange rules or regulations require recovery of Erroneously Awarded Compensation in circumstances in addition to those
specified herein, nothing in this Policy shall be deemed to limit or restrict the right or obligation of the Company to recover
Erroneously Awarded Compensation to the fullest extent required by such applicable law, stock market or exchange rules and
regulations. Unless otherwise required by applicable law, this Policy shall no longer be effective from and after the date that the
Company no longer has a class of securities publicly listed on a United States national securities exchange.
Interpretation. Notwithstanding anything to the contrary herein, this Policy is intended to comply with the requirements of Section
10D of the Exchange Act and Section 303A.14 of the NYSE Listed Company Manual (and any applicable regulations,
administrative interpretations or stock market or exchange rules and regulations adopted in connection therewith). The provisions
of this Policy shall be interpreted in a manner that satisfies such requirements and this Policy shall be operated accordingly. If any
provision of this Policy would otherwise frustrate or conflict with this intent, the provision shall be interpreted and deemed
amended to avoid such conflict.
Other Compensation Clawback/Recoupment Rights. Any right of recoupment under this Policy is in addition to, and not in lieu of,
any other remedies, rights or requirements with respect to the clawback or recoupment of any compensation that may be available
to the Company pursuant to the terms of any other recoupment or clawback policy of the Company (or any of its affiliates) that may
be in effect from time to time, any provisions in any employment agreement, offer letter, equity plan, equity award agreement or
similar plan or agreement, and any other legal remedies available to the Company, as
4
7.
8.
(a)
(b)
(c)
(d)
well as applicable law, stock market or exchange rules, listing standards or regulations; provided, however, that any amounts
recouped or clawed back under any other policy that would be recoupable under this Policy shall count toward any required
clawback or recoupment under this Policy and vice versa.
Exempt Compensation. Notwithstanding anything to the contrary herein, the Company has no obligation to seek recoupment of
amounts paid to a Covered Executive which are granted, vested or earned based solely upon the occurrence or non-occurrence of
nonfinancial events. Such exempt compensation includes, without limitation, base salary, time-vesting awards, compensation
awarded on the basis of the achievement of metrics that are not Financial Reporting Measures or compensation awarded solely at
the discretion of the Committee or the Board, provided that such amounts are in no way contingent on, and were not in any way
granted on the basis of, the achievement of any Financial Reporting Measure.
Miscellaneous.
Any applicable award agreement or other document setting forth the terms and conditions of any compensation covered by this
Policy shall be deemed to include the restrictions imposed herein and incorporate this Policy by reference and, in the event of any
inconsistency, the terms of this Policy will govern. For the avoidance of doubt, this Policy applies to all compensation that is
received on or after the Effective Date, regardless of the date on which the award agreement or other document setting forth the
terms and conditions of the Covered Executive’s compensation became effective or was first granted or awarded, including, without
limitation, compensation received under the GeoPark Limited 2018 Equity Incentive Plan with registration No. 333-228763 and
filed with the SEC on December 12, 2018 and its related programs and any successor plan.
This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators
or other legal representatives.
All issues concerning the construction, validity, enforcement and interpretation of this Policy and all related documents, including,
without limitation, any employment agreement, offer letter, equity award agreement or similar agreement, shall be governed by, and
construed in accordance with, the laws of the State of New York, without giving effect to any choice of law or conflict of law rules
or provisions (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any
jurisdiction other than the State of New York.
The Covered Executives, their beneficiaries, executors, administrators and any other legal representative and the Company shall
initially attempt to resolve all claims, disputes or controversies arising under, out of or in connection with this Policy by conducting
good faith negotiations amongst themselves. To ensure the timely and economical resolution of disputes that arise in connection
with this Policy, any controversy or claim arising out of or relating to this Policy shall be settled by binding and confidential
arbitration before a single arbitrator administered by Judicial Arbitration and Mediation Services under its Employment Arbitration
Rules & Procedures taking place in the State of New York, and judgment on the award rendered by the arbitrator may be entered in
any court having jurisdiction thereof. To the fullest extent permitted by law, the Covered Executives, their beneficiaries, executors,
administrators and any other legal representative and the Company, shall waive (and shall hereby be deemed to have waived): (1)
the right to resolve any such dispute through a trial by jury or judge or administrative proceeding; and (2) any objection to
arbitration taking place in the State of New York.
(e)
If any provision of this Policy is determined to be unenforceable or invalid under any applicable law, such provision will be applied
to the maximum extent permitted by applicable law and shall automatically be deemed amended in a manner consistent with its
objectives to the extent necessary to conform to any limitations required under applicable law.
5
Exhibit 99.1
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 1, 2024
GeoPark Limited
Calle 94 N° 11-30, 8° floor
Bogotá, Colombia
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the extent of the
estimated net proved oil, condensate, and gas reserves of certain properties in Brazil, Chile, Colombia, and Ecuador in which GeoPark
Limited (GeoPark) has represented it holds an interest. This evaluation was completed on March 1, 2024. GeoPark has represented that these
properties account for 100 percent on a net equivalent barrel basis of GeoPark’s net proved reserves as of December 31, 2023. The net
proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of
the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item
1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by GeoPark.
Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum
remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves
attributable to the interests held by GeoPark after deducting all interests held by others, including royalties paid in kind.
Estimates of reserves should be regarded only as estimates that may change as further production history and additional information
become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to
the uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in this evaluation was obtained from GeoPark. In the preparation of this report we have relied, without
independent verification, upon such information furnished by GeoPark with respect to the property interests being evaluated, production
from such properties, current costs of operation and development, current prices for production, agreements relating to current and future
operations and sale of production, and various other information and data that were accepted as represented. A field examination was not
considered necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report.
Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of
the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating
conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses
of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and
operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing
prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are
classified as follows:
Proved oil and gas reserves – Proved oil and gas 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.
DeGolyer and MacNaughton
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if
any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it
and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a
lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists
for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if
geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of
the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the
reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based; and (B) The project has been approved for development by
all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by
the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such
period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is
by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by
actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other
evidence using reliable technology establishing reasonable certainty.
3
DeGolyer and MacNaughton
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and
techniques that are in accordance with the reserves definitions of Rules 4–10(a)(1)–(32) of Regulation S–X of the SEC and with practices
generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June
2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs,
stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by GeoPark, and
analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves
estimates were based on opportunities identified in the plan of development provided by GeoPark.
GeoPark has represented that its senior management is committed to the development plan provided by GeoPark and that GeoPark
has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment
and facilities.
The volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were
prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs,
core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water
saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP or
OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based
on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the
production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an
analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic
characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.
In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more
complete data were available.
In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which
more complete historical performance data were available.
For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery
factors and reserves production forecasts.
The reserves estimates contained herein were limited to the economic limit, as defined under the Definition of Reserves heading of
this report, or to the end of the concession, whichever occurs first.
Data provided by GeoPark from wells drilled through December 31, 2023, and made available for this evaluation were used to
prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain
properties only through November 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross
ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month.
Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil reserves include fuel oil. Fuel oil is
defined as that portion of the oil consumed in field operations. Oil and condensate reserves included in this report are expressed in thousands
of barrels (103bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have
been estimated separately and are presented herein as a summed quantity.
4
DeGolyer and MacNaughton
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs,
measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas
reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of zero degrees Celsius (°C) and at a
pressure base of 1 kilogram per square centimeter (kg/cm2) for properties located in Chile and at a temperature base of 15.5°C and at a
pressure base of 1 kg/cm2 for properties located in other countries. Gas quantities included in this report are expressed in millions of cubic
feet (106ft3).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial
reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial
reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in crude oil at initial reservoir
conditions. Gas quantities reported herein are both nonassociated gas and associated gas.
At the request of GeoPark, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of
6,000 cubic feet of gas per 1 barrel of oil equivalent.
Primary Economic Assumptions
This report has been prepared using initial prices, expenses, and costs provided by GeoPark in United States dollars (U.S.$). Future
prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following
economic assumptions were used for estimating the reserves reported herein:
Oil and Condensate Prices
GeoPark has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the
reporting period, unless prices are defined by contractual agreements. GeoPark supplied differentials to a Brent reference price
of U.S.$82.09 per barrel and the prices were held constant thereafter. For the Manati field in Brazil, the volume-weighted
average adjusted product price attributable to the estimated proved reserves was U.S.$70.68 per barrel of condensate. For the
fields located in Chile, the volume-weighted average adjusted product price attributable to the estimated proved reserves was
U.S.$68.04 per barrel of oil and condensate. For the fields located in Colombia, the volume-weighted average adjusted product
price attributable to the estimated proved reserves was U.S.$68.73 per barrel of oil. For the fields located in Ecuador, the
volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$61.27 per barrel of oil.
Gas Prices
GeoPark has represented that the gas prices are defined by contractual agreements and their expected extensions, which are
based on specific market conditions. The volume-weighted average adjusted product price attributable to the estimated proved
reserves for the Manati field in Brazil was U.S.$6.65 per thousand cubic feet (103ft3) of gas. The volume-weighted average
adjusted product price attributable to the estimated proved reserves for the fields located in Chile was U.S.$3.39 per 103ft3 of
gas. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the fields located in
Colombia was U.S.$6.00 per 103ft3 of gas.
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DeGolyer and MacNaughton
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses and capital costs, provided by GeoPark and based on existing economic conditions, were held
constant for the lives of the properties. This information included historical costs as well as operating expense and capital cost
estimates for future development. In certain cases, future expenditures, either higher or lower than current expenditures, may
have been used because of anticipated changes in operating conditions, but no general escalation that might result from
inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells,
and reclamation and restoration associated with the abandonment, were provided by GeoPark for each field or block and were
included in the year following cessation of production, except in Brazil, where abandonment costs are allocated annually into
an abandonment fund. Abandonment costs were not escalated. Operating expenses, capital costs, and abandonment costs were
considered in determining the economic viability of the undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been
prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update
932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB
and Rules 4–10(a)(1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the
SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we,
as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or
sufficient therefor.
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DeGolyer and MacNaughton
Summary of Conclusions
DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate,
and gas reserves of certain properties in which GeoPark has represented it holds an interest. The estimated net proved reserves, as of
December 31, 2023, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as
follows, expressed in thousands of barrels (103bbl), millions of cubic feet (106ft3), and thousands of barrels of oil equivalent (103boe):
Brazil
Proved Developed
Proved Undeveloped
Total Proved
Chile
Proved Developed
Proved Undeveloped
Total Proved
Colombia
Proved Developed
Proved Undeveloped
Total Proved
Ecuador
Proved Developed
Proved Undeveloped
Total Proved
Grand Total
Proved Developed
Proved Undeveloped
Total Proved
Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of
December 31, 2023
Oil and
Condensate
(103bbl)
Sales Gas
(106ft3)
Oil Equivalent
(103boe)
28
0
28
619
479
8,888
0
8,888
9,956
855
1,098
10,811
43,120
16,225
59,345
1,017
1,278
2,295
1,075
0
1,075
0
0
0
44,784
17,982
19,919
855
1,509
0
1,509
2,278
622
2,900
43,299
16,225
59,524
1,017
1,278
2,295
48,103
18,125
62,766
20,774
66,228
Notes: 1. Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas
per 1 barrel of oil equivalent.
2. Oil reserves include fuel oil quantities associated with the Platanillo field in Colombia. Fuel oil quantities were estimated to be
132 103bbl of the proved developed reserves and 158 103bbl of the total proved reserves.
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DeGolyer and MacNaughton
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s
ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31,
2023, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting
services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in
GeoPark. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of GeoPark. DeGolyer
and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
/s/ Peter Laudon
Peter Laudon, P.E., P.G.
Vice President
DeGolyer and MacNaughton
8
[SEAL]
DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Peter Laudon, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244
U.S.A., hereby certify:
1. That I am a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to GeoPark
dated March 1, 2024, and that I, as Vice President, was responsible for the preparation of this report of third party.
2. That I attended the University of Kansas, and that I graduated with a Bachelor of Science degree in Geology in the year 1988, and
that I attended the University of Missouri at Rolla, and that I graduated with both a Master of Science degree in Geology in the year
1992 and a Bachelor of Science degree in Petroleum Engineering in the year 1995; that I am a Licensed Professional Geologist and
that I am a Licensed Professional Engineer in the State of Texas; that I am a member of the American Association of Petroleum
Geologists, the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the Society of Professional Well
Log Analysts, and the American Association of Petroleum Geologists; and that I have in excess of 29 years of experience in oil and
gas reservoir studies and evaluations.
[SEAL]
/s/ Peter Laudon
Peter Laudon, P.E., P.G.
Vice President
DeGolyer and MacNaughton
9