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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 20-F

(Mark One)

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

OR

☒           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

OR

☐           TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______________________ to ___________________________

OR

☐           SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

Commission file number: 001-36298

GEOPARK LIMITED

(Exact name of Registrant as specified in its charter)

Bermuda

(Jurisdiction of incorporation)

Calle 94 N° 11-30, 8^o floor

Bogotá, Colombia

(Address of principal executive offices)

Pedro E. Aylwin Chiorrini

Director of Legal and Governance

GeoPark Limited

Calle 94 N° 11-30, 8^o floor

Bogotá, Colombia

Phone: +57 1 743 2337

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

Copies to:

Maurice Blanco, Esq.

Yasin Keshvargar, Esq.

Davis Polk & Wardwell LLP

450 Lexington Avenue

New York, NY 10017

Phone: (212 ) 450 4000

Fax: (212) 701 5800

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

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

None

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

None

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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: 60,238,026

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.

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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. ☒

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

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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 ☒ 

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GEOPARK LIMITED

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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.

“boepd” means barrels of oil equivalent per day.

“bopd” means barrels of oil per day.

“British thermal unit” or “btu” means the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“basin” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“CEOP” (Contrato Especial de Operación) means a special operating contract the Chilean signs with a company or a consortium of companies for the exploration and exploitation of hydrocarbon wells.

“completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“developed acreage” means the number of acres that are allocated or assignable to productive wells or wells capable of production.

“developed reserves” are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify developed reserves as undeveloped.

“development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“E&P Contract” means exploration and production contract.

“economic interest” means an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires.

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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:

“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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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

Certain definitions

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

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Financial statements

Our historical financial data presented does not include any results or other financial information of any acquisitions, including the acquisition of Amerisur, 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, 2021 and 2020 and for each of the years ended years ended December 31, 2021, 2020 and 2019 (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, 2021 have been audited by Pistrelli, Henry Martin y Asociados S.R.L., (member of Ernst & Young Global), 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 2021,” relate to our fiscal year ended on December 31 of that calendar year.

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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 before net finance cost (determined in accordance with the indentures governing our Notes due 2024 and 2027, which do not give effect to the adoption of IFRS 16 Leases), 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 in commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects and other events defined therein. 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 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 2021, 2020 and 2019.

Oil and gas reserves and production information

DeGolyer and MacNaughton 2021 Year-end Reserves Report

The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia, Chile, Brazil and Argentina is derived from estimates of the proved reserves as of December 31, 2021. 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 and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in the Llanos 32, Llanos 34, Platanillo and CPO-5 Blocks in Colombia, the Fell Block in Chile, the BCAM-40 (Manati) Block in Brazil and the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina.

Market share and other information

Market data, other statistical information, information regarding recent developments in Colombia, Chile, Brazil, Argentina and Ecuador 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.

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

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:

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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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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:

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Risks relating to our business

The COVID-19 pandemic has and may continue to adversely impact our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The unprecedented nature of the current situation 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 have adversely impacted the global economy and created significant volatility in the global financial markets. COVID-19 significantly impacted the world economy in 2020 and 2021 and may continue to do so in the years to come. Many countries have imposed travel bans on millions of people and additionally people in many locations have been subject to quarantine measures. Businesses have been dealing with lost revenue and disrupted supply chains. Countries have imposed lockdowns in response to the pandemic and, as a result of the disruption to businesses, millions of workers have lost their jobs. The COVID-19 pandemic has also resulted in significant volatility in the financial and commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. Numerous governments have implemented measures to provide both financial and non-financial assistance to the affected entities. We have applied and used any extension granted, specifically in Colombia, Brazil, Argentina, Peru and Spain. In Colombia, we entered into an agreement with the tax authority to pay the 2019 income tax in twelve installments from August 2020 to July 2021.Despite the uncertainty of the lasting effect of the COVID-19 outbreak, the crude oil demand recovery resulted in improvements in market conditions from the end of 2020 and onwards.

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. Additionally, because we have implemented remote working procedures for a significant portion of our workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, we rely on such persons having sufficient access to our information technology systems, including through telecommunication hardware, software and networks. If a significant portion of our workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, our business, financial condition, cash flows, and results of operations may be materially adversely affected.

The unprecedented nature of the current situation resulting from the COVID-19 pandemic 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, financial condition, cash flows, or results of operations. Such results will depend on future events, which we cannot predict, including the scope, duration and potential reoccurrence of the COVID-19 pandemic or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines and treatments, the demand for and the prices of oil and natural gas and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have amplified, and may continue to amplify, the other risks identified in this annual report.

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

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

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

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These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and methanol price movements. For example, oil and natural gas prices have fluctuated significantly. From January 1, 2019, to February 28, 2022, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$101.0 per barrel, Henry Hub natural gas average spot prices ranged from a low of US$1.6 per mmbtu to a high of US$5.5 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$260.4 per metric ton to a high of US$657.6 per metric ton. Furthermore, oil, natural gas and methanol prices do not necessarily fluctuate in direct relationship to each other.

Starting in March 2020, the oil market experienced a significant over-supply condition that resulted in a sharp drop in prices, with Brent falling from over US$50 per barrel at the beginning of March 2020, up to US$16 per barrel in late April 2020. There were two key drivers for this market scenario. On the demand side, the sustained impact of the COVID-19

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pandemic across the world and the associated containment measures, resulted in a sharp and sudden drop in fuel demand and hence on crude demand as well. This impact had been felt since early 2020 but accelerated significantly in March and April.

Concurrently, on the supply side, during the first week of March 2020, OPEC and non-OPEC producers (sometimes referred to as OPEC+) met to discuss the prospect of extending or increasing oil production cuts that had been first put in place in late 2016 and had been renewed and expanded ever since. No consensus was reached among the 24 participating countries, effectively eliminating output reduction targets as of April 1, 2020. As a consequence, OPEC+ countries and especially Saudi Arabia, significantly increased production during April 2020.

The combined impact of sharply lower demand and growing supply led the market into a significant oil surplus with inventories building around the world and prices dropping to levels last seen in the early 2000s.

In mid-April, in the midst of a significant reduction of demand, OPEC+ agreed to a historical 9.7 MMbbl/d output cut. They were joined by other G-20 countries, which indicated they would reduce their production between 3 and 5 MMbbl/d. Following this agreement, global crude production dropped significantly with high compliance from OPEC+ countries and economic-driven shut-ins in other regions, especially the United States and Canada, helping re-attain some balance in the market during the second half of 2020.

The crude oil market continued normalizing during early 2021 and shifted into an undersupply condition towards the end of the year. This condition was mainly driven by continued demand recovery while supply grew at a slower pace. OPEC+ paced output increase and capital discipline elsewhere, and especially within the US Shale producers, were the key factors for moderate supply growth. In addition, natural gas prices spike 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 ongoing armed conflict, and the continuation of, or any increase in, the armed conflict between Russia and Ukraine, has led and may continue to lead to volatility in the price of global oil and gas. In addition, 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 certain other countries, as of March 2022, including additional countries that may enforce prohibitions of a similar nature in the future, has led to and is expected to continue to lead to volatility in the price of global oil and gas.

The crude price trajectory is highly uncertain for the months to come, as the long-term economic impact of COVID-19 and the armed conflict in Ukraine may impact energy demand around the globe.

For the year ended December 31, 2021, 94% of our revenues were derived from oil. Because we expect that our production mix will continue to be weighted towards oil, our financial results are more sensitive to movements in oil prices.

As of December 31, 2021, natural gas comprised 6% of our revenues. A decline in natural gas prices could negatively affect our future growth, particularly for future gas sales where we may not be able to secure or extend our current long-term contracts.

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

For example, during 2021, an impairment loss was recognized for US$4.3 million (compared to an impairment loss recognized for US$133.9 million in 2020). After conducting an impairment test procedure for the year ended December 31, 2021 we recognized an impairment loss of US$17.6 million in the Fell Block due to the decline in the proved reserves

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estimates in 2021 and the commercial viability decreasing significantly as a consequence of the lower crude prices relative to its high cash costs of production in 2020, and we recognized a reversal of impairment loss of US$ 13.3 million in the Aguada Baguales and El Porvenir Blocks in 2021 due to the known market price of the blocks in the context of the transaction described in Note 36.3.1 to our Consolidated Financial Statements. See Note 37 to our Consolidated Financial Statements for details regarding the key assumptions considered in our impairment test and Note 1.1 for details regarding the impact of COVID-19 and the oil price crisis in our business.

Continuing our hedging strategy, we entered into derivative financial instruments to manage exposure to oil price risk. These derivatives were zero-premium collars and were placed with major financial institutions and commodity traders. We entered into the derivatives under ISDA Master Agreements and Credit Support Annexes.

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 its ability to both maximize ongoing projects and to preserve its 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 in 2021 and 2022, oil prices 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—2022 Strategy and Outlook” and Note 1.1 to our Consolidated Financial Statements.

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 our suppliers. Equally, those third parties may be unable to meet their contractual obligations to us as a result of the oil price crisis, impacting on our operations.

In budgeting for our future activities, we have relied on a number of assumptions, including, with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects and our ability to obtain needed financing with respect to any further acquisitions and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, conditions in the financial markets, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. In addition, we opportunistically seek out new assets and acquisition targets to complement our existing operations and have financed such acquisitions in the past through the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority stakes in certain operations to our partners. We may need to raise additional funds more quickly if one or more of our assumptions prove

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to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. The ultimate amount of capital that we will expend may fluctuate materially based on market conditions, our continued production, decisions by the operators in blocks where we are not the operator, the success of our drilling results and future acquisitions. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

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, 2021, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Chile, Argentina and Brazil was 6.4 years. According to estimates, if on January 1, 2022, we ceased all drilling and development activities, including recompletions, refracs and workovers, our proved developed producing reserves base in Colombia, Chile, Brazil, and Argentina would decline 24% 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 2021, the oil and gas production was sold to three clients which concentrate 99% of the Colombian subsidiaries’ revenue (accounting for 89% of our 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. The outstanding contracts for Colombian production extend through 2023. We manage our counterparty credit risk associated to sales contracts by including, in certain contracts, early payment conditions to minimize the exposure.

In Chile, the oil production is sold to ENAP, the State-owned oil and gas company (accounting for 1% of our consolidated revenue), and the gas production is sold to the local subsidiary of Methanex, a Canadian public company (representing 2% of our consolidated revenue).

In Brazil, all the hydrocarbons from the Manati Field are sold to Petrobras, the Brazilian State-owned company, which is the operator of the Manati Field (accounting for 3% of our consolidated revenue). See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.”

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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.

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Business Overview—Significant Agreements—Colombia” and “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Chile.”

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

Although a majority of our revenues is denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Colombia, Chile, Brazil and Argentina 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.

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. Since December 2018, we decided to manage exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, we entered into derivative financial instruments with local banks in Colombia, for an amount equivalent to US$83.7 million as of December 31, 2019, in order to anticipate any currency fluctuation with respect to estimated income taxes to be paid during the first half of the following year. As of December 31, 2021 and 2020, we have no currency risk management contracts in place.

Through our Brazilian operations, we are exposed to fluctuations in the real against the US$, as our Brazilian revenues and expenses are mostly denominated in reais. In the past, the Brazilian Central Bank has occasionally intervened to control unstable movements in foreign exchange rates. We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to permit the real to float freely or will intervene in the exchange rate market through the return of a currency band system or otherwise. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or there are reasons to foresee a serious imbalance, temporary restrictions may be imposed on remittances of foreign capital abroad. We cannot assure you that such measures will not be taken by the Brazilian government in the future. The real has experienced frequent and substantial variations in relation to the US$ and other foreign currencies, which could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations.

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

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

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

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

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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.

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—2022 Strategy and Outlook.” We incurred capital expenditures of US$129.3 million and US$75.3 million during the years ended December 31, 2021 and 2020, 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 including capital expenditures for Amerisur assets).

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. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.

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

Oil and gas exploration and production is speculative and involves a high degree of risk and hazards. In particular, our operations may be disrupted by risks and hazards that are beyond our control and that are common among oil and gas companies, including environmental hazards, blowouts, industrial accidents, occupational safety and health hazards, technical failures, labor disputes, community protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and other accidents. For example, on February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for

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the eradication of coca plantations in the area, blocking access to the Platanillo operations. The protest was not directed at us or at the oil industry, however, to protect our employees, we evacuated all personnel and shut in the production of 2,400 barrels per day between March 4, 2021, and March 11, 2021.

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

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

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

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

For example, in 2021, the drilling and completion cost for the exploratory well Alea oeste 1 in our Platanillo Block in Colombia was originally estimated at US$5.4 million, but the actual cost was US$6.2 million, mainly due to a sidetrack required after a disruption in our operations.

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.

Furthermore, with the recent oil price decline we have begun to prioritize lower-risk, higher netback and quick cash flow generating projects, while implementing operating, administrative and capital cost-reduction measures.

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

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

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

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

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

Our oil and gas reserves estimate in Colombia, Chile, Brazil and Argentina as of December 31, 2021 are based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimate set forth in the D&M Reserves Reports are based on certain assumptions that may prove inaccurate. DeGolyer and MacNaughton’s primary economic

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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. Results of drilling, testing and production after the date of the estimate may require revisions to be made. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate of our oil and gas reserves. Accordingly, reserves estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and if such recovered quantities are substantially lower than the initial reserves estimates, this could have a material adverse impact on our business, financial condition and results of operations.

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

Our ability to market our oil and natural gas production depends substantially on the availability and capacity of processing facilities, transportation facilities (such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated by third parties. Our failure to obtain such facilities on acceptable terms or on a timely basis could materially harm our business. We may be required to shut down oil and gas wells because access to transportation or processing facilities may be limited or unavailable when needed. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to 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. In order 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, blockage risks and supporting our sustainable performance by reducing carbon emissions. During 2020, the Jacana-ODL flowline was converted into the Oleoducto del Casanare Pipeline (“ODCA”) after receiving authorization from the Ministry of Energy and Mines to operate as such. We also inaugurated a truck unloading facility at Jacana Field and connected Tigana field to ODCA at the end of the year. During 2021, ODCA was a key element in the transport of crude production of our Llanos 34 field. If the Oleoducto de Los Llanos “ODL” (the main delivery point for our Colombian production) were to have any maintenance or operational issues, we would resort to alternative delivery points via truck transportation. During May and June 2021, extensive protests and demonstrations across Colombia affected overall logistics and supply chains, restricting our crude oil transportation, drilling and the mobilization of personnel, equipment, and supplies. These events caused us to manage production curtailments that started in early May 2021 and normalized towards the end of June 2021.

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 Oloeducto Binacional Amerisur (“OBA”) pipeline that connects us to the Ecuador pipeline system.

Trucking transportation was key to our crude delivery strategy during 2021 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 Chile, we transport the crude oil we produce in the Fell Block by truck to ENAP’s processing, storage and selling facilities at the Gregorio Refinery. As of the date of this annual report, ENAP purchases all of the crude oil we produce in Chile. We rely upon the continued good condition, maintenance and accessibility of the roads we use to deliver the crude

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oil we produce. If the condition of these roads were to deteriorate or if they were to become inaccessible for any period of time, this could delay delivery of crude oil in Chile and materially harm our business.

In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, the principal purchaser of the gas we produce. If ENAP’s pipelines were unavailable, this could have a materially adverse effect on our ability to deliver and sell our product to Methanex, which could have a material adverse effect on our gas sales.

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.

In Ecuador, future production from blocks acquired in 2019 is expected to be 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 continue 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.

In Argentina, we deliver a portion of our oil production and all of our gas production via existing pipeline infrastructure controlled by third parties. While both the oil and gas pipeline systems in Argentina are well-developed and have operated reliably in the past, we cannot guarantee this will continue in the future. In addition, as Argentina’s production grows, pipeline capacity may become insufficient. We also deliver a portion of our crude production at well-head. This volume is lifted from our loading facilities by third-party operated trucks contracted by our clients. The roads around our fields are in good condition but changes in those conditions could adversely affect our operations. Our failure to secure transportation or access to pipelines or other facilities on acceptable terms or on a timely basis could materially harm our business.

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

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

In Colombia, although we have agreements with many landowners and are in negotiations with others, the economic expectations of landowners have generally increased, which may delay access to existing or future sites. In addition, the expectations and demands of local communities on oil and gas companies operating in Colombia may also increase. As a result, local communities have demanded that oil and gas companies invest in remediating and improving public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure that was previously paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are now dealing with increasing difficulties resulting from instances of social unrest, temporary road blockages and conflicts with landowners.

In some areas operated by us in Putumayo, illegal groups fight to dominate the territory, amongst other reasons, to control illegal activities such as the cultivation and commercialization of illicit crops. Furthermore, these illegal groups oppose to our entrance, to avoid the parallel entrance of governmental entities in these territories under disputes.

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

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February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for the eradication of coca plantations in the area, blocking access to the Platanillo operations.

Other legal proceedings such as land restitution, a judicial process implemented as a consequence of the peace agreement in Colombia focused 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.

In Ecuador, we are in an early diagnosis stage with local landowners and communities and we could suffer delays in the exploration and operation of the fields.

Under the terms of some of our various CEOPs, 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.

In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain periods specified in our various special operation contracts (CEOPs, 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 these prospects. The costs to maintain or operate the CEOPs, 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 2020, after fulfilling the committed exploratory commitments, four exploratory blocks were relinquished to the ANP. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Brazil.”

A significant amount of our reserves or production have been derived from our operations in certain blocks, including the Llanos 34, CPO-5, Platanillo and Llanos 32 Blocks in Colombia, the Fell Block in Chile and the BCAM-40 Concession in Brazil.

For the year ended December 31, 2021, the Llanos 34 Block contained 79% of our net proved reserves and generated 67% of our production, the CPO-5 Block contained 6% of our net proved reserves and generated 10% of our total production, the Platanillos Block contained 2% of our net proved reserves and generated 5% of our production, the Llanos 32 Block contained 3% of our net proved reserves and generated 1% of our production, the Fell Block contained 5% of our net proved reserves and generated 6% of our total production and the BCAM-40 Concession contained 3% of our net proved reserves and generated 5% of our production. While our continuing expansion with new exploratory blocks incorporated in our portfolio mean that the above-mentioned blocks may be expected to be a less significant component of our overall business, we cannot be sure that we will be able to continue diversifying our reserves and production. Resulting from these, any government intervention, impairment or disruption of our production due to factors outside of our control or any other material adverse event in our operations in such blocks would have a material adverse effect on our business, financial condition and results of operations.

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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.

Under certain CEOPs, 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 CEOPs, E&P contracts, production sharing contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2021, the aggregate outstanding amount of this potential liability for guarantees was US$74.9 million, mainly related to capital commitments in the VIM-3, Llanos 34, PUT-8, PUT-9, PUT-12 and Platanillo Blocks in Colombia, the Campanario Block in Chile, and the Perico and Espejo Blocks in Ecuador. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 33.2 to our Consolidated Financial Statements.

Additionally, certain of the CEOPs, 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 CEOPs contain provisions enabling exploration extensions.

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.” In order to avoid the breach of an E&P contract due to unfulfillment of our exploration commitments, regulation gives us the option to transfer those commitments to other E&P contracts, subject to meeting certain regulatory conditions.

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

In Brazil, concession agreements 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 of our respective obligations under the concession agreement (subject to a cure period). Administrative or monetary sanctions may also be applicable, as determined by the ANP, which shall be imposed based on applicable law

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and regulations. In the event of early termination of a concession agreement, the compensation to which we are entitled may not be sufficient to compensate us for the full value of our assets. Moreover, in the event of early termination of any concession agreement due to failure to fulfill obligations thereunder, we may be subject to fines and/or other penalties.

In Argentina, hydrocarbon exploration permits and exploitation concessions are subject to termination for: (a) failure to pay any annual license fees within three months after they are due; (b) failure to pay royalties within three months after they are due; (c) material and unjustified failure to comply with the specified obligations in respect to productivity, conservation, investments, works or special benefits; (d) repeated infringement of the obligations to submit demandable information, to facilitate inspections by the competent authority or to employ the proper techniques for the execution of the works; (e) failure to request an exploitation concession after a commercial discovery or to submit a development program after obtaining an exploitation concession; (f) the bankruptcy of the holder declared by a court; (g) the death or liquidation of the holder; or, (h) failure to comply with the obligation to transport hydrocarbons for third parties under open access conditions or repeated infringement of the tariff regime approved for such transport. Before declaring the termination under any of the grounds provided under items (a), (b), (c), (d), (e), and (h), notice shall be served, requiring the holder to remedy any such infringement. Upon expiration, relinquishment or termination of any permit or concession, the holder of such permit or concession shall surrender to the government the acreage together with all of the improvements, facilities, wells and other equipment that may have been used in the performance of the activities.

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.  

Early termination or nonrenewal of any CEOP, 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 sell all of our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility.

For the year ended December 31, 2021, all of our natural gas sales in Chile were made to Methanex under a long-term contract, the Methanex Gas Supply Agreement, which expires on December 31, 2026. In 2019, we amended the gas supply agreement with Methanex to increase the purchase commitment up to 460,000 SCM/d of gas to accommodate increased production from our successful drilling in the Jauke project. In 2020, we amended the gas supply agreement to increase the purchase commitment to 550,000 SCM/d if Methanex is operating two trains. In 2021 we negotiated an amendment to the gas supply agreement to increase the purchase commitment to 600,000 SCM/d. This amendment is still in process of being executed. Sales to Methanex represented 2% of our consolidated revenues for the year ended December 31, 2021. Methanex also buys gas from ENAP and a consortium that Methanex has formed with ENAP. If Methanex were to decrease or cease its purchase of gas from us, this would have a material adverse effect on our revenues derived from the sale of gas.

Methanex has two methanol producing facilities (trains) at its Cabo Negro production facility, near the city of Punta Arenas in southern Chile. Methanex has relied on local suppliers of natural gas, including ENAP, for its operations. We alone cannot supply Methanex with all the natural gas it requires for its operations. Over the past years, Argentina has been approving gas exports to Chile and other countries, including to Methanex. These are annual authorizations which depend on the supply and demand balances of Argentina.

In the past, the Methanex plant was idled due to an anticipated insufficient supply of natural gas. In July 2020, the Methanex plant shut down because of a technical failure which affected our natural gas production and sales for 10 days. See “Item 4. Information on the Company—B. Business Overview—Marketing and delivery commitments—Chile.”

However, we cannot be sure that Methanex will continue to purchase the gas from us, including the above committed levels, or that its efforts to reduce the risk of future shut-downs will be successful, which could have a material adverse

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effect on our gas revenues. Additionally, we cannot be sure that Methanex will have sufficient supplies of gas to operate its plant and continue to purchase our gas production or that methanol prices would be sufficient to cover the operating costs. We cannot be sure that we would be able to sell our gas production to other parties or on similar terms, which could have a material adverse effect on our business, financial condition and results of operations.

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

As of December 31, 2021, we are not the operator of 24% or sole owner of 43% of the blocks included in our portfolio. See “Item 4. Information on the Company—B. Business Overview—Operations in Colombia”, “—Operations in Chile”, “—Operations in Brazil”, “—Operations in Argentina” and “—Operations in Ecuador.”

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, Brazil, Argentina and Ecuador. Our dependence on our partners could prevent us from realizing our target returns for those discoveries or prospects.

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

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 example, 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.

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

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

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:

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

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to properly evaluate acquisitions, alliances or investments, we may not achieve the anticipated benefits of any such transaction, and we may incur costs in excess of what we anticipate.

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

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, 2021, 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:

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, 2021, 63% 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.

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.

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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.

Furthermore, the COVID-19 pandemic is currently having an indeterminable adverse impact on the world economy and has begun to have numerous worldwide effects on general commercial activity. At this time, given the uncertainty of the lasting effect of the COVID-19 pandemic, its impact on our customers cannot be determined.

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

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

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

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

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

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

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We and our operations are subject to numerous environmental, social, health and safety laws and 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 actions. For instance, non-governmental organizations seeking to preserve the environment may bring actions against us or other oil and gas companies in order to, among other things, halt our activities in any of the countries in which we operate or require us to pay fines. Additionally, in Colombia, recent rulings have provided that environmental licenses are administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts on our E&P contracts.

In Colombia, the Supreme Court of Justice issued ruling STC3460-2018 on April 5th, 2018, whereby it declared the Amazonia zone as subject of rights to be protected by the authorities. The Supreme Court ordered local, regional and national authorities to adopt measures to reduce deforestation in the Amazonia and protect the environment. This ruling could indirectly affect our operations in the Putumayo E&P contracts operated by Amerisur, as authorities are expected to issue regulations restricting oil and gas operations in the area.

We have not been and may not be at all times in complete compliance with environmental permits that we are required to obtain for our operations and the environmental and health and safety laws and regulations to which we are subject. If we fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain, maintain or renew permits in a timely manner or at all, our operations could be adversely affected, impeded, or terminated, which could have a material adverse effect on our business, financial condition or results of operations.

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

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

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

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We have set a target to reduce operational Scope 1 and 2 GHG emissions by 50 percent by year-end 2030 from a 2019 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 the 2030 GHG reduction target and the 2050 net zero ambition is subject to numerous risks and uncertainties and actions taken in implementing such target and ambition may also expose us to certain additional and/or heightened financial and operational risks. 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. 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 2030 GHG reduction target or 2050 net zero emissions ambition on the current timelines, or at all.

In addition, achieving the 2030 GHG reduction target and 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.

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. Developing and implementing such 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 facilitate a higher flow of hydrocarbons into the wellbore. We may eventually contemplate, after due environmental approvals, such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs in Chile,

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especially shale formations. In Colombia, the Council of State is reviewing the regulation for “non-conventional hydrocarbons” and its decision will impact the future of unconventional oil and gas resources in Colombia. The ANH is leading some non-conventional pilot projects (Kalé and Platero in Valle Medio del Magdalena) which have not started yet.  The environmental license for Kalé has already been obtained and we will apply for the environmental license for Platero in 2022. Drilling in these pilot projects by the ANH is expected to begin in 2023. The way in which these pilot projects are carried out will surely impact the future of these resources in Colombia. We currently are not aware of any proposals in Chile, Brazil, Argentina or Ecuador 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, 2021, we had US$674.1 million outstanding amount of indebtedness on a consolidated basis, consisting primarily of our US$171.9 million Notes due 2024 and our US$499.9 million Notes due 2027.

Our indebtedness could:

The indentures governing our Notes due 2024 and our Notes due 2027 include covenants restricting dividend payments. 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 2024 or our Notes due 2027 would not trigger an event of default.

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

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

The global cyber-threats constantly evolve and the oil and gas industry is exposed to it.

Digital technologies have become an integral part of our business. The oil and gas industry has become increasingly dependent on computer and telecommunications systems to conduct exploration, development and production activities.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also escalated in the world. Our industry is subject to fast-evolving risks from cyber threat actors, including states, criminals, terrorists, hacktivists and insiders.

Although we have implemented a strong cyber security strategy and procedures to prevent and assure the confidentiality, availability and security of our data, we cannot guarantee that these measures will be enough for this purpose. Cyber-attacks, whose techniques are regularly renewed, are becoming more and more sophisticated.

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Therefore, it is necessary to continue identifying and fixing any technical vulnerabilities and weaknesses in the operating processes, as well as to continue strengthening capabilities to detect and react to incidents. This includes the need to strengthen security controls in the supply chain (from our partners and other third parties), as well as to ensure the security of the services in the cloud. 

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As a result of the circumstances brought by the COVID-19 pandemic, security measures related to remote access and teleworking of employees and collaborators have been reviewed and strengthened, but no assurance can be provided that such security measures will be effective.

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A breach or failure of our digital infrastructure – including control systems – due to breaches of our cyber defenses, or those of third parties, negligence, intentional misconduct or other reasons, could seriously disrupt our operations. This could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and legal liability.

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Furthermore, the rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and coordinated means, is a challenge we must face and any delay or failure to detect cyber incidents could compound these potential harms. This could result in significant losses including the cost of remediation and reputational consequences.

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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 computers.

Although to date cyber-attacks have not had a material impact in our operations or financial results, there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber-incident.

As cyber threats continue to evolve, we may be required to expend significant additional resources to continue modifying and enhancing our protective measures and to investigate and remediate any information security vulnerabilities.

In August 2021, we strengthened our corporate insurance package, with the acquisition of a cyber security insurance policy, to get coverage and indemnification from a potential cyber-attack or data breach. However, no assurances can be made as to whether the insurance policy will be enough to cover all our potential liability.

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We operate in an industry with significant environmental, social, governance (ESG) and climate related risks.

Our operations in Latin America are in areas of significant biodiversity value and many have historical and current ties to indigenous peoples’ lands. Indigenous project affected communities have a growing expectation of the right to free, prior and informed consent based on the United Nations Declaration on the Rights of Indigenous Peoples and national legislation across Latin America increasingly recognizes the right to free, informed and prior consultation. These updates to laws and expectations introduce the need for greater resources put toward community engagement and understanding as well as benefit sharing mechanisms. We may be exposed to challenges related to proper biodiversity management, as some operations exist in key biodiversity areas. This could delay and/or increase the cost of our exploration and development projects. Changes in laws, international norms, investor expectations and other stakeholder perceptions could result in increased liabilities and project expenses.

Amerisur’s exploration blocks carry significant costs related to biodiversity management and reputational risk due to overlapping claims of rightful ownership.

With the acquisition of Amerisur in January 2020, we have assumed significant and unpredictable costs for biodiversity management if we are to comply with best industry practices aligned to IFC’s Performance Standard 6. Costs related to mitigation measures to protect the habitat could be larger than currently anticipated due to unanticipated findings in baseline biodiversity studies.

Nine out of twelve of the Amerisur’s oil and gas development and exploration blocks in Colombia overlap with indigenous territories that are either formalized or are being considered for formal tribal land title under the Colombian land restitution law. In all instances we have taken ownership and responsibility over the consultation process with indigenous groups and ensure that broad community support is achieved for our presence in these areas. Project completion and cost expectations could change depending on the agreements achieved. Prolonged negotiations with indigenous communities and affected communities more generally, could draw the attention of international non-profit organizations and potentially result in social unrest, protests and blockades or legal actions, which could provoke material cost overruns and impacts to our reputation.

In Colombia, despite the fact that we closed prior consultations with tribal communities in our PUT-12 Block, some of the communities ignored such consultations and openly oppose to any hydrocarbons exploration and production activities in their territories, with the cooperation of environmental and indigenous NGO’s. Furthermore, this tribal communities are subject of precautionary measurements issued by the Human Rights Interamerican Commission, whereby the Colombian Government is obliged to adopt measures to protect the life and integrity of these communities. In addition, some of these tribal communities are also subject of precautionary measures issued by a Colombian Land Restitution Judge, who forbid all hydrocarbons and industrial activities within the communities’ legal territories and within those territories subject to the land restitution. This scenario may replicate in other areas operated by us, which may adversely affect our operations in the Putumayo area.

Pursuant to the prior consultation processes with indigenous communities and other ethnic groups, we comply with the applicable legislation in each of the countries in which we operate, as well as the provisions of ILO Convention 169. We also implement processes and best practices such as those established in IFC standard No. 7. We recognize that our entry and stay in the territories is determined by the social license granted to us by the indigenous communities that inhabit it, and that we will make all our efforts to gain their trust and acceptance to achieve a relationship of mutual benefit in the long term.

We may also become liable for the results of a litigation in the United Kingdom, where 270 members of the community of the area of influence of the Platanillo Block operated by us, claim to have suffered damages derived from Amerisur’s hydrocarbons exploration and production activities since 2009. Liabilities in this process may amount up to £4.47 million (equivalent to US$6.0 million as of December 31, 2021) if the court evidences the damages claimed by the 270 community members.

For example, on February 25, 2021, some communities in the Putumayo basin began protesting against the Government of Colombia for the eradication of coca plantations in the area, blocking access to the Platanillo operations.

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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.

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:

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 blockades, expropriation, piracy, tribal conflicts and governmental policies that may: disrupt our operations; require us to incur greater costs for security; restrict the movement of funds or limit repatriation of profits; lead to U.S. government or international sanctions; limit access to markets for periods of time; or influence the market’s perception of the risk associated with investments in these countries.

Some countries in the geographic areas where we operate have experienced, and may experience in the future, political instability, and losses caused by these disruptions may not be covered by insurance. For example, during 2019, Chile and Colombia 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 Chilean and Colombian economy and our businesses in those countries. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material

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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.

For example, in spring 2022 there will be national elections in Colombia to elect a new president and a new Congress. A new president and national government may take positions on oil and gas policy issues that are contrary to our interests. Changes regarding oil and gas or investment regulations and policies or a shift in political attitudes in Colombia are beyond our control and may significantly reduce our ability to expand our operations or operate a profitable business.

Our operations may also be adversely affected by laws and policies of the jurisdictions, including Bermuda, Colombia, Chile, Brazil, Argentina, Ecuador, Spain, the United Kingdom and other jurisdictions in which we do business, that affect foreign trade and taxation, and by uncertainties in the application of, possible changes to (or to the application of) tax laws in these jurisdictions. For example, in 2020, the Chilean and Spanish governments and, in 2021 the Argentine and the Colombian governments introduced tax reforms. See Note 16 to our Consolidated Financial Statements.

With regards to Chile, although our CEOPs have protection against tax changes through invariability tax clauses, potential issues may arise on certain aspects not clearly defined in current or future tax reforms.

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

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

The success of our business and the effective operation of the fields in each of our countries of operation depend upon continued good relations and cooperation with applicable governmental authorities and agencies, including national oil companies such as Ecopetrol, ENAP, Petrobras, YPF and Petroecuador. For instance, for the year ended December 31, 2021, 100% of our crude oil and condensate sales in Chile were made to ENAP, the Chilean state-owned oil company. In addition, our Brazilian operations in BCAM-40 Concession provide us with a long-term off-take contract with Petrobras, the Brazilian state-owned company that covers 100% of net proved gas reserves in the Manati Field, one of the largest non-associated gas fields in Brazil. If we, the respective host governments and the national oil companies are not able to cooperate with one another, it could have an adverse impact on our business, operations and prospects.

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

Under Colombian, Chilean, Brazilian, Argentine and Ecuadorian 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, Chilean, Brazilian, Argentine and Ecuadorian 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, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities. Any delays in receiving government approvals in such countries may delay our operations or may affect the status of our contractual arrangements or our ability to meet contractual obligations.

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

The Colombian, Chilean, Brazilian, Argentine and Ecuadorian 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. In Argentina, energy regulation gives absolute priority to domestic gas supply, which in case of a gas shortage occurs, will restrict our ability to fulfill our export commitments, if any. This regulation also established subsidies to domestic gas prices, which may negatively affect our revenues considering market prices. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Argentina.”

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.

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

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

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have in the future a negative impact on the Colombian economy or on our business, which may affect our employees or assets.

Our operations in Colombia are subject to security and human rights risks

Civil disturbances and criminal activities such as drug trafficking, vandalism, extortion or kidnapping may disrupt our operations in Colombia. Such incidents may halt or delay exploration and production, increase operating costs, result in harm to employees or trespassers, decrease operational efficiency and increase community tensions. In addition, the manner in which our personnel and the Colombian government respond to civil disturbances and criminal activities can give rise to additional risks where those responses are not conducted in a manner that is consistent with international standards relating to human rights. While we remain committed to strengthening our security processes and protocols, there is no guarantee that such incidents will not occur in the future. For example, in 2021, our supply chain in the Llanos and Putumayo basins was affected by a series of extensive protests and demonstrations across Colombia that included road blockades, which resulted in temporary production curtailments.

In addition, various laws, conventions and guidelines relating to human rights may impact our operations, including those mandating prior consultations with indigenous communities. While we have experience managing these consultations, one or more groups may oppose our current and future operations or further development of our projects or operations. Such opposition may be directed through legal or administrative proceedings or expressed in manifestations such as protests, roadblocks or other forms of public expression against our activities, and may have a negative impact on our reputation, operation and financial results. Opposition by such groups to our operations may require modification of, or preclude the operation or development of, our projects or may require us to enter into agreements with such groups or local governments with respect to our projects, which may result in considerable delays to the advancement of our projects.

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:

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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.

On November 6, 2019, our Board of Directors declared the initiation of a quarterly cash dividend of US$0.0413 per share. The first one was paid on December 10, 2019 and the second one was paid on April 8, 2020. After that, on April 20, 2020 we declared the temporary suspension of quarterly cash dividends and share buybacks as part of our revised work program for 2020 to help address the recent decline in oil prices. On November 4, 2020 we declared an extraordinary cash dividend and a quarterly cash dividend of $0.0206 per share each one, paid on December 9, 2020 to our shareholders of record at the close of business on November 20, 2020. The quarterly cash dividend supplements the existing share buyback program which as of December 31, 2020, has returned US$75.3 million in value to shareholders during 2019 and 2020.  

On March 10, 2021, and May 5, 2021, our Board of Directors declared quarterly cash dividend of US$0.0205 per share payable on April 13, 2021, and May 28, 2021, to our shareholders of record at the close of business on March 31, 2021, and May 17, 2021, respectively.

On August 4, 2021 and November 10, 2021, our Board of Directors declared a quarterly cash dividend of US$0.041 per share payable on August 31, 2021, and December 7, 2021, to our shareholders of record at the close of business on August 17, 2021, and November 23, 2021, respectively.

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On March 9, 2022, our Board of Directors declared a quarterly cash dividend of US$0.082 per share payable on March 31, 2022, to our shareholders of record at the close of business on March 24, 2022.

Due to losses resulting from the oil price decline, accumulated losses amount to US$314.8 million as of December 31, 2021, and our total equity as of December 31, 2021, is negative US$61.9 million.

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.

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 60,238,026 common shares were outstanding as of December 31, 2021. 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 2024 and Notes due 2027 could discourage an acquisition of us by a third party.

Certain provisions of the Notes due 2024 and 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 2024 will have the right, at their option, to require us to repurchase all of their

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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 senior management held 20.5% of our outstanding common shares as of March 12, 2022, 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 expense, 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 from time to time attempt to effect changes to our business or governance, with respect to climate change or otherwise, by means such as shareholder proposals, public campaigns, proxy solicitations or otherwise. 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 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.

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

There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. 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.

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.

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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 the manner in which 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.

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integration of Amerisur’s assets in Colombia. In 2021, we drilled our first exploratory well in the Perico Block and we accepted an offer to divest non-core Argentina assets for a consideration of US$16 million, which closed on January 31, 2022.

We have built our company around three principal capabilities:

Our business model reflects our principal capabilities:

Asset Management, Performance & Quality

Effectively and profitably manage our entire asset portfolio and teams, work with partners, obtain regulatory and other permits, and carry out our work programs to explore, develop and produce our oil and gas reserves and resources.

Exploration & Subsurface

Use our brainpower, experience, creativity and discipline to find and develop new oil and gas reserves – based on the best science, solid economics and the ability to take the necessary managed risks.

Operations & Execution

Execute in a timely manner to be the safest lowest cost producer, and with the necessary know-how to profitably drill, produce, transport and sell our oil and gas with the drive and creativity to find solutions, overcome obstacles, seize opportunities and achieve results.

Nature & Neighbors

Having the cleanest and kindest hydrocarbons by minimizing the impact of our projects on the environment, making our operational footprint cleaner and smaller, and being the preferred neighbor and partner by creating a mutually beneficial exchange with the local communities where we work.

Value Delivery & Generation

Create consistent stakeholder value through disciplined capital allocation, rigorous and comprehensive risk management, self-funded and flexible work programs, capital and operating cost efficiency, maximizing the value of every barrel, expanding scale, protecting the balance sheet and returning tangible value to our shareholders.

Commitment & Culture

Build a performance-driven and trust-based culture, based on SPEED, that values and protects our communities, employees, environment and shareholders to underpin and strengthen our long-term plan for success.

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

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

History

We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, who have over 40 years of international oil and natural gas experience, respectively. Mr. O’Shaughnessy served as our Chairman until June 8, 2021. Mr. Park currently serves as our Chief Executive Officer and Deputy Chairman of the Board. In 2021, Sylvia Escovar Gomez was appointed as new Chair of the Board.

We are a leading independent oil and natural gas exploration and production (“E&P”), company with operations in Latin America. During 2021, we operated in Colombia, Chile, Brazil, Argentina and Ecuador.

Our History can be summarized by our growth in each country and our performance in the capital markets:

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

Colombia

In the first quarter of 2012, we moved into Colombia by acquiring three privately held E&P companies: (i) Winchester Oil and Gas S.A., a Colombian branch of a sociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS (“Winchester”), (ii) La Luna Oil Company Limited S.A., a sociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) Hupecol Cuerva LLC, a limited liability company incorporated under the laws of the state of Delaware, which merged into GeoPark Colombia SAS (“Cuerva”). These acquisitions provided us with an attractive platform of reserves and resources in Colombia.

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 with Parex to assume a 50% working interest in the Llanos 94 Block.

On January 16, 2020, we acquired the entire share capital of Amerisur, a company previously listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. The principal activities of Amerisur were exploration, development and production of oil and gas reserves in Latin America.

Brazil

Since 2013, we have participated many times in the Brazilian ANP Bid Rounds and every time we participated we have been awarded exploratory concessions.

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As of 2014, following the Rio das Contas acquisition, we have a 10% working interest in the BCAM-40 Concession, which includes an interest in the Manati Gas Field operated by Petrobras.

On November 22, 2020, we signed an agreement to sell our 10% non-operated working interest in the Manati gas field to Gas Bridge for a total consideration of R$144.4 million (approximately US$27 million as of the date of the agreement at the exchange rate of R$5.35 to US$1.00), including a fixed payment of R$124.4 million plus an earn-out of R$20.0 million, which is subject to obtaining certain regulatory approvals. The transaction was agreed with an effective date of December 31, 2020 and is subject to certain conditions, including the acquisition by Gas Bridge of the remaining 90% working interest and operatorship of the Manati gas field. As of the date of this annual report these conditions have not been met.

Argentina

In December 2017, we agreed to purchase from Pluspetrol, a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina. We entered into an asset purchase agreement with Pluspetrol, dated December 18, 2017 (the “APA”). The transaction closed on March 27, 2018.

In June 2018, we announced a partnership with YPF, the state-owned oil company of Argentina, on the Los Parlamentos block – a large high potential block in the Neuquén Basin with both conventional and unconventional prospects. The assignment of rights agreement was signed in October 2019.

During May 2021, we initiated a process to evaluate farm-out or divestment opportunities to sell our 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, the sale and purchase and assignment agreement was signed for a total consideration of US$16 million, subject to working capital adjustments. Closing of the transaction took place on January 31, 2022.

Peru

In October 2014, we expanded our footprint into Peru by acquiring the Morona Block in a joint operation with Petroperu. This transaction awarded us a 75% working interest of the Morona Block. In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement dated October 1, 2014 and its amendments were closed on December 1, 2016, following the issuance of Supreme Decree 031-2016-MEM.

On July 15, 2020, we notified our irrevocable decision to retire from the non-producing Morona Block (Block 64) in Peru, due to extended force majeure, which allows for the termination of the license contract. On April 6, 2021, the final agreement with Petroperu was signed and, on May 31, 2021, the joint operation agreement was terminated. On September 28, 2021, the supreme decree approving the assignment was issued by the Peruvian Government, and the public deed corresponding to that assignment was executed by us and Petroperu on November 15, 2021. Consequently, from such date, Petroperu holds all the rights and obligations under the Morona Block license contract.

Ecuador

On May 22, 2019, we signed final participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico (GeoPark non-operated, 50% working interest) Blocks in Ecuador, which were awarded to GeoPark in the Intracampos Bid Round held in Quito, Ecuador in April 2019. We assumed a commitment of carrying out 3D seismic in the Espejo Block and drilling four exploration wells in each block, which amounts to US$39 million in capital expenditures for our working interest, until June 2025.

In December 2021 we drilled and completed the first exploration well in the Perico Block, which resulted in discovery of oil, with testing activities currently underway and we are carrying out the acquisition of 60 sq km of 3D seismic in the Espejo Block, targeting to spud the first exploration well in the second half of 2022.

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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.

In September 2017, we issued US$425.0 million aggregate principal amount of 6.50% senior notes due 2024. The net proceeds from the Notes were used by us (i) to make a capital contribution to our wholly-owned subsidiary, Agencia, providing it with sufficient funds to fully repay senior secured notes due 2020 and to pay any related fees and expenses, including a call premium, and (ii) for general corporate purposes, including capital expenditures, such as the acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in the Neuquén Basin in Argentina and to repay existing indebtedness, including the Itaú loan.

In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027. The net proceeds from the Notes were used by us (i) to make an intercompany loan to our wholly-owned subsidiary, GeoPark Colombia S.A.S., providing it with sufficient funds to pay the total consideration for the acquisition of Amerisur (see Note 36.1 to our Consolidated Financial Statements) and to pay related fees and expenses, and (ii) for general corporate purposes.

In April 2021, we executed a series of transactions that included a successful tender to purchase US$255.0 million of the 2024 Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.

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The tender total consideration included the tender offer consideration of US$1,000 for each US$1,000 principal amount of the 2024 Notes plus the early tender payment of US$50 for each US$1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes.

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The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. The debt issuance cost for this transaction amounted to US$2.0 million. The Notes are fully and unconditionally guaranteed jointly and severally by GeoPark Chile SpA and GeoPark Colombia.

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Following these transactions, we reduced our total indebtedness nominal amount by US$105.0 million and improved our financial profile by extending our debt maturities.

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

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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, 2021. For information on our working interests in each of these blocks, see “—Our assets” below.

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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, 2021.

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Our commitment to growth has translated into a strong compounded annual growth rate (“CAGR”), of 8% for production in the period from 2017 to 2021, as measured by boepd in the table below.

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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, 2021.

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Our assets

We have a well-balanced portfolio of assets that includes working and/or economic interests in 42 hydrocarbon blocks, 41 of which are onshore blocks, including 10 in production as of December 31, 2021. Our assets give us access to more than 6.7 million gross exploratory and productive acres.

According to the D&M Reserves Report, as of December 31, 2021, the blocks in Colombia, Chile, Brazil and Argentina in which we have a working interest had 87.8 mmboe of net proved reserves, with 90%, 5%, 3% and 3% of such net proved reserves located in Colombia, Chile, Brazil and Argentina, respectively.

We produced a net average of 37.6 mboepd during the year ended December 31, 2021, of which 83%, 6%, 6% and 5%, were in Colombia, Chile, Argentina and Brazil, respectively, and of which 86% was oil.

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Our strengths

We believe that we benefit from the following competitive strengths:

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

Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys 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.

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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.

Continue to grow a risk-balanced asset portfolio

We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In general, when we enter a new country we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term possibility of production, to generate cash flows; (ii) an inventory of adjacent 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 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, each country, has a local team running the business who recommends and advocates for the projects with which they want to move forward. The corporate team then ranks 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, the corporate team decides the amount of capital to be invested and allocates that capital to the highest value-adding projects. As an example, for the 2022 capital allocation process, over 115 projects were selected which comprise our 2022 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.

We generated US$216.8 million and US$168.7 million in cash from operations in the years ended December 31, 2021 and 2020, respectively, and had US$100.6 million and US$201.9 million of cash and cash equivalents as of December 31, 2021 and 2020, respectively.

As of December 31, 2021, we had US$674.1 million of total outstanding indebtedness and over 99% of our debt is scheduled to mature in 2024 (25.5%) and 2027 (74.2%).

In April 2021, we executed a series of transactions that included a successful tender to purchase US$255.0 million of the 2024 Notes that was funded with a combination of cash in hand and a US$150.0 million new issuance from the

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reopening of the 2027 Notes. The new notes offering, and the tender offer closed on April 23, 2021, and April 26, 2021, respectively.

The tender total consideration included the tender offer consideration of US$1,000 for each US$1,000 principal amount of the 2024 Notes plus the early tender payment of US$50 for each US$1,000 principal amount of the 2024 Notes. The tender also included a consent solicitation to align the covenants of the 2024 Notes to those of the 2027 Notes.

The reopening of the 2027 Notes was priced above par at 101.875%, representing a yield to maturity of 5.117%. The debt issuance cost for this transaction amounted to US$2.0 million. The Notes are fully and unconditionally guaranteed jointly and severally by GeoPark Chile SpA and GeoPark Colombia S.A.S.

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Following these transactions, we reduced our total indebtedness nominal amount by US$105.0 million and improved our financial profile by extending our debt maturities.

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In June 2020, we entered into an offtake and prepayment agreement with Trafigura, under which we sold and delivered a portion of our Colombian crude oil production to Trafigura. The offtake agreement also provided us with a prepayment line of up to US$75 million in the form of prepaid future oil sales. The availability period for the prepayment agreement expired on August 10, 2021. We have not withdrawn any amount from this prepayment agreement.

In January 2020, we issued US$350.0 million aggregate principal amount of 5.50% senior notes due 2027 (the “Notes due 2027”). The Notes due 2027 contain incurrence-based limitations on the amount of indebtedness we can incur. See Note 27 to our Consolidated Financial Statements.

Strong cash flow

We benefit from a strong cash flow from operating activities. For the year ended December 31, 2021, cash flows from operating activities were US$216.8 million. Our cash flows from operating activities plays a significant role in funding our capital expenditures.

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 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.

Since December 2018 we decided to manage our future exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, we entered into derivative financial instruments with local banks in Colombia, for an amount equivalent to US$83.7 million in 2019 and US$92.1 million in 2018, in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. As of December 31, 2021, and 2020, we have no currency risk management contracts in place.

In relation to the cash consideration payable for the acquisition of Amerisur, we were exposed to fluctuations of the British pound sterling as of December 31, 2019. Consequently, we decided to manage this exposure by entering into a deal-contingent forward with a British bank, in order to anticipate any currency fluctuation.

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Since 2020, we have entered into Vasconia-based derivative contracts, a new instrument within our hedging portfolio. These derivatives protect both the overall crude price exposure to ICE Brent as well as the Vasconia differential, which reflects the quality adjustment for our Llanos Basin crude production in Colombia.

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$1.1 billion as of December 31, 2021. 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.

On January 16, 2020, we acquired the entire share capital of Amerisur, a company listed on the Alternative Investment Market (“AIM”) of the London Stock Exchange. The principal activities of Amerisur were exploration, development and production for oil and gas reserves in Latin America. Amerisur 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 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. For example, as commodity prices were projected to decline throughout 2020, on March 19, 2020, we announced a decision to shift our development plan primarily to our operations in the Llanos 34 Block to focus on the Llanos Basin, which had demonstrated strong returns on capital. Our operating team reacted quickly to pivot our operations that were unburdened by drilling obligations and worked with our service partners to coordinate a smooth and efficient transition to a new plan. Since then, we were able to control production costs, as exemplified by our average operating costs for the Llanos 34 Block, which were US$5.8 per boe for the year ended December 31, 2021.

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 Chile, we believe we have strong long-term commercial relationships with Methanex and ENAP, and 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.

In February 2018, we announced the formation of a new long-term strategic partnership to jointly acquire, invest in, and create value from upstream oil and gas projects with the objective of building a large-scale, economically-profitable and risk-balanced portfolio of assets and operations across Latin America with ONGC Videsh, the wholly-owned subsidiary and international arm of Oil and Natural Gas Corporation Limited, India’s national oil company.

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Maintain our commitment to environmental, safety, human rights and social responsibility

A major component of our business strategy is our focus on and commitment to our safety, environmental and social responsibilities, in line with international standards. We see this as a fundamental element of ensuring long-term business initiatives. We are committed to minimizing the impact of our projects on the environment and aim to create mutually beneficial relationships with the local communities in which we operate in order to enhance our ability to create sustainable value in our projects. These commitments are embodied in our in-house value system, which we refer to as “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment and Community Development). Our S.P.E.E.D. program was developed in accordance with several international quality standards, including ISO 14001 (for environmental management issues), ISO 45001 (for occupational health and safety management issues), ISO 26000 (for social accountability and workers’ rights issues), and associations guidelines including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.”

During 2016, we began the ISO 14001 certifying process through programs related to the efficient use of natural resources and compliance with environmental regulation. We have also provided training to our staff and the communities in which we operate with respect to these matters.

In August 2017, we obtained the ISO 14001:2015 certification for our environmental management process for the design, construction, operation, maintenance, modernization and dismantlement of GeoPark Colombia S.A.S.’s facilities, and the performance of exploration and oil and gas production activities in the Llanos 34 and VIM-3 blocks with a commitment to continuously improve our processes. We obtained the ISO 14001:2015 re-certification in 2018 and in 2020 the certification was renewed and extended until August 2023.

Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-3:2006 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 country meet the commitment it took on at the 2015 United Nations Climate Change Conference.

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. Once again in 2021 we won the “Best Social Practices in the Energy Industry” award through our ‘Viviendas Sostenibles’ housing program that improves the living conditions and welfare of our Casanare and Putumayo neighbors. 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.

In spite of physical distancing due to the COVID-19 pandemic, in 2021 we kept in permanent contact with the local communities in which we operate, contributing to food security for vulnerable households and supporting local and national authorities’ efforts to halt the spread of the virus.

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 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 January 2022 GeoPark was added to the Bloomberg Gender-Equality Index, including companies with best-in-class gender-related practices and policies. In January 2021, we participated in but were not included due to our market capitalization, but we were highlighted nevertheless for our score.

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In 2021, we reported our S.P.E.E.D. 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) and the Sustainability Accounting Standards Board (SASB, 2018).

Among the material sustainability topics included in our 2020 S.P.E.E.D. and ESG report are: safety and health management, supply chain management, stakeholder relations, legal compliance, employee development and training, integrated water resources management, energy efficiency, emissions management, biodiversity protection, social risk assessment, and relationship with indigenous communities.

On March 26, 2021, we received a rating of BBB (on a scale of AAA-CCC) in the MSCI ESG Ratings assessment. We progressed from B in 2018 to BBB in 2021. The improvement in ratings was principally due to governance and greenhouse gas emission plan. The 2021 upgrade was based on our improvements in Health & Safety and Carbon Emissions.

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 the Voluntary Principles on Security and Human Rights is reflected in our S.P.E.E.D. program, as well as in all our policies and procedures. Human rights aspects are integrated into relevant internal management processes, tools, and trainings. On-going activities, business relationships and new business opportunities are assessed for potential human rights impacts and aspects, following a risk-based approach, with continued efforts to strengthen the diversity of our workforce, considering gender, nationality, background, ethnicity, competence, age and preferences.

In 2021, we continued the strengthening of our processes for managing human rights in our supply chain and on raising awareness. A compliance appendix, covering human rights and anti-corruption standards for suppliers, was introduced for all material contracts.

On October 13, 2021, five United Nations rapporteurships on human rights matters, coordinated by the working group on the issue of human rights and transnational corporations and other business enterprises, delivered to our Chief Executive Officer a letter under the special procedures of the United Nations Human Rights Council, to request: i) clarification on the information received from the Siona Buenavista Indigenous community, located in Puerto Asis, Putumayo, related with human rights alleged violations and, ii) information on the Human Rights Due Diligence procedures, policies, processes and actions implemented by us to prevent, mitigate and remediate human rights violations within its operations.

On December 7, 2021, we replied to the letter received from the UN Special Procedures Secretariat dated October 13, 2021, providing information on each of the matters addressed therein.

On December 14, 2021, and January 4, 2022, the chancelleries of Chile and Colombia submitted their reply to the United Nations Human Rights Council letter, respectively.

In February 2022, we met with the Latin American representative to the UN Working Group on Business and Human Rights, to establish direct contact with this group, which will enable further communication as may be required.

Transparency, ethics and anti-corruption

Transparency is a cornerstone of good governance. 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.

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We support and engage in global transparency initiatives through our membership in the Extractive Industries Transparency Initiative (EITI). Since 2018, we have actively participated in the Colombian EITI initiative and taken part of a multi-stakeholder working group organized by Transparency International Colombia in preparation of the report.

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.

Our CEO, 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 12, 2022, Mr. Park held 14.0% 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, 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 12, 2021, our executive directors and key management (excluding one of our founding shareholders, Mr. James F. Park) owned 2.1% 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 are continuously looking for opportunities to innovate driving efficiency, employee productivity, engagement, collaboration, communication, and decision-making leveraging technology in all areas of our organization. We believe we have successfully incorporated new digital capabilities like artificial intelligence, machine learning, internet of things, big data, automation and cloud computing. During 2021, we implemented more than 40 innovative initiatives with top partners like Microsoft, Google, Halliburton, Cisco, SAP, among others. The following are some of the projects that have been part of or innovation culture:  

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Other innovation projects such as the optimization and implementation of water disposal, oil data capture, electrical reliability, artificial intelligence for geologists, automation of critical processes and data portals are part of the Digital Innovation roadmap that we intend to advance going forward. We continue to look for opportunities that drive efficiency, mitigate risk, reduce costs, and increase production using internal and external talent with advanced technology.

For a more in-depth discussion of our 2021 results, liquidity and its capital resources, please see “Item 5—Operating and Financial Review and Prospects”.

2022 Strategy and Outlook

Oil prices have been volatile over the past years. In preparation for continued volatility and the prolonged effects of the COVID-19 pandemic, we have developed multiple scenarios for our 2022 capital expenditure program.

Our preliminary base capital program for 2022 considered a reference oil price assumption of US$65-70 per barrel and called for approximately US$160-180 million to fund our exploration and development which we intend to fund through cash flows from operations and cash-in-hand, to be allocated approximately as follows:

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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$50 per barrel and consists of an alternative capital expenditure program of approximately US$120 million-US$150 million consisting mainly of certain low risk and quick cash flow generating projects. The upside scenario work program considers a reference oil price assumption above US$80 per barrel or higher and consists of an alternative capital expenditure program of approximately US$190 million-US$220 million to be selected from identified projects designed to increase reserves and production.

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In order to secure minimum oil prices for our 2022 production and beyond, we have commodity risk management contracts in place covering a portion of our production for 2022 and 2023 and monitor market conditions on a continuous basis to evaluate additional new commodity risk management contracts for the future.

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Additionally, we continue to monitor the potential impact of the COVID-19 pandemic and the oil price volatility as a result of the armed conflict in Ukraine on our financial condition, cash flows and results of operations.

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Our operations

We have a well-balanced portfolio of assets that includes working and/or economic interests in 42 hydrocarbon blocks, 41 of which are onshore blocks, including 10 in production as of December 31, 2021.

Our well-balanced portfolio of assets provides the ability to quickly optimize capital allocation as market conditions change. The current crisis, however, is still evolving and may become more severe and complex. For additional information about the business risks relating to the COVID-19 pandemic and related governmental actions, See “Item 3. Key Information—D. Risk factors—Risks relating to our business—The COVID-19 pandemic has and may continue to adversely impact our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The unprecedented nature of the current situation 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”.

Operations in Colombia

As of December 31, 2021, our Colombian assets gave us access to more than 3,690,000 gross exploratory and productive acres across 23 blocks in what we believe to be one of South America’s most attractive oil and gas geographies.

Since we entered Colombia in 2012, we have achieved consistent growth and we were able to maintain our oil production and proved reserves, mainly achieved through successful exploration and development activities we made at our operated Llanos 34 Block, which as of December 31, 2021 accounts for 81% of our production and 88% of our proved reserves in Colombia.

The table below shows average production and proved oil and gas reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, 2021, 2020 and 2019:

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Highlights of the year ended December 31, 2021 related to our operations in Colombia included:

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

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

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The table summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2021.

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The table summarizes information about the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 2021

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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 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 63,529 gross acres (257 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 2021 we engaged in exploration and development activities that resulted in 10 new oil fields discoveries and increased proved reserves and oil production year by year up to a peak oil production of 34,995 bopd. Average net production in 2021 was 25,187 bopd and net reserves of 69.6 mmboe. By the end of 2021, we have drilled more than 160 wells, with 139 producer wells that have accumulated more than 139 million barrels of oil. The Llanos 34 Block has three reservoirs: the Guadalupe Formation, which produces 88% of our oil production in the Block, Mirador, which produces 11% of our oil production in the Block and Gacheta, which produces 1% of our oil production in the Block, with an API gravity between 13° and 30.6°. During these 10 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, 24 kilometers of power grid, more than 45 kilometers of flowlines for fluid transfer, 136 kilometers of roads and a 42 kilometers oil pipeline. In December 2020, we connected the Tigana field in the Llanos 34 Block to the ODCA pipeline in, further reducing truck traffic, contributing to further reduce operational risk, costs and carbon emissions. As of the date of this annual report, outstanding investment commitments of US$17.4 million related to this block correspond to the drilling of 3 exploratory wells before November 10, 2021. Due to a private agreement with the partner in the block, the investment commitment incurred by us amounts to US$12.8 million. As of the date of this annual report, we had already drilled the three exploratory wells and are waiting for ANH’s approval to fulfill the investment commitment.

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 50,211 gross acres (203 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, 2021, our average net production in the Llanos 32 Block was 456 bopd. As of the date of this annual report, outstanding investment commitments related to this block correspond to the drilling of 5 exploratory wells before February 20, 2022. Due to a private agreement with the partner in the block, the investment commitment incurred by us amounts to US$9.2 million. As of the date of this annual report, the five exploratory wells have already been drilled and ANH approval of the fulfillment of the investment commitment is pending.

Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific Rubiales Energy 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 Pacific, who subsequently assigned its participation interest to Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A.

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 its exploratory phase 1 as of the date of this

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annual report and cover approximately 530,309 gross acres (2,146 sq. km.). We have requested the Ministry of Interior to certify if there are indigenous communities present in the area and the Ministry confirmed the presence of such communities. Therefore, we conducted the due prior consultation process with the communities. On March 15, 2022 the prior consultation process concluded, and the contract entered into exploratory phase 1 in which the commitments are: acquisition of 3D seismic, reprocessing of 2D seismic and drilling of two exploratory wells for an estimated amount of US$9.5 million for Llanos 86 Block and US$8.4 million for Llanos 104 Block as of the date of this annual report.

Llanos 87 Block. GeoPark 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. The Ministry of Interior certified the absence of indigenous communities in the area. We are the operator of this contract that is currently in exploratory phase 1 and covers approximately 107,624 gross acres (435 sq. km.). Phase 1 commitments are reprocessing of 3D seismic, drilling of four exploratory wells and acquisition of aero geophysics before January 18, 2023, with an estimated amount of US$13.2 million as of the date of this annual report.  

Llanos 123 and Llanos 124 Blocks: GeoPark and Hocol, each with fifty percent (50%) working interest executed an E&P contract 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 covers approximately 115,956 gross acres (469 sq. km.). As of the date of this annual report, outstanding investment commitments of US$16.8 million related to these blocks correspond to (i) reprocessing 3D seismic, acquiring geochemistry and drilling of two exploratory wells for Llanos 123 Block with an estimated amount of US$6.8 million before January 14, 2024, and; (ii) the acquisition of 3D seismic, reprocessing of 3D seismic, acquisition of geochemistry and drilling of three exploratory wells for Llanos 124 Block with an estimated amount of US$10.0 million before January 14, 2024.

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. This contract is in its exploratory phase 1 and covers approximately 89,175 gross acres (360.8 sq. km.). We acquired a 50% working interest from Parex and obtained ANH’s approval to such transfer in May, 2020. As of the date of this annual report, outstanding investment commitments of US$10.9 million related to this block correspond to the acquisition of 3D seismic, reprocessing of 3D seismic and drilling of 3 exploratory wells before October 1, 2023.

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. As of the date of this annual report this contract is in exploratory phase 2 in which the pending commitment correspond to the acquisition, processing and interpretation of 230 sq. km. of 3D seismic for an amount of US$2.8 million before July 8, 2024. There are two commercial fields called Mariposa and Indico. Average net production in 2021 was 3,722 bopd and net reserves were 5.1 mmboe.

Magdalena Basin:

VIM-3 Block. On July 23, 2014, we were awarded an exploratory license during the 2014 Colombia Bidding Round, carried out by the ANH. The VIM-3 Block is located in the Lower Magdalena Basin. In 2018, we filed a request before the ANH to terminate the E&P Contract due to environmental restrictions in the block. These restrictions became apparent once the National Authority of Environmental Licenses issued the environmental license. As of the date of this annual report, the termination was approved by the ANH with a remaining commitment for an amount of US$9.3 million, which were transferred to CPO-5 Block in Colombia. As of the date of this annual report, the relinquishment of the Block is still pending.

Putumayo Basin:

Andaquies Block. We are the operator of and have a 100% working interest in the Andaquies Block, which covers approximately 114,879 gross acres (465 sq. km.). As of the date of this annual report the contract is in phase 3 of the exploration period. On February 14, 2020, we presented our withdrawal from the E&P Contract and requested the ANH

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to approve the transfer of the pending commitments to the Llanos 32 Block. On February 20, 2020, the ANH approved the request. We and the ANH already began the process of relinquishment of the E&P Contract and its subsequent liquidation.  

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.). As of the date of this annual report the contract is in phase 3 of the exploration period, which exploration commitment consists 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. Furthermore, on September 2006, the former operator declared an Evaluation Area and presented an Evaluation Program in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coatí-1 well. Both, the phase 3 and the Temblon Evaluation Program, are currently suspended due to force majeure events (relating to prior consultations).

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 27,300 gross acres (110 sq. km.). On September 11, 2009, we began the commercial exploitation of the Platanillo Block (Alea 1 and Platanillo 2 wells, began). Average net production in 2021 was 1,766 bopd and net reserves of 1.9 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. As of the date of this annual report, 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 July 5, 2023.

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 (492 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 12 Block. We are the operator of and have a 60% working interest in the Putumayo 12 Block, which covers approximately 134,534 gross acres (544 sq. km.). Pluspetrol Colombia Corporation (“Pluspetrol”) is the owner of the remaining 40% 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$14.4 million related to this block consist of the drilling of one exploratory well, the acquisition of 131 km. of 2D seismic, and the acquisition of geochemistry before November 29, 2021. On February 23, 2021, we requested the termination of the contract due to the occurrence of force majeure events related with judicial procedures initiated by ethnic communities.

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.). The contract is in phase 0, as the applicable prior consultation process must be completed. The Ministry of Interior certified the presence of two indigenous communities for the execution of the seismic commitment for phase 1. Prior consultations with the two ethnic communities are ongoing. Phase 1 commitments consist of the acquisition of 98 km. of 2D seismic and the drilling of one exploratory well for an estimated net amount of US$16.1 million as of the date of this annual report.

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Putumayo 30 Block. We are the operator of and have a 100% working interest in the Putumayo 30 Block, which covers approximately 95,172 gross acres (385 sq. km.). On February 23, 2021, we submitted to the ANH our request to withdraw from to the E&P contract and transfer the remaining commitments to other E&P contracts. The ANH approved the request. The remaining investment was transferred to Llanos 34 Block and Platanillo Block. The contract is in process of termination as of the date of this annual report.

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. The contract is in preliminary phase, whereby applicable prior consultation processes must be completed. The Ministry of Interior certified the presence of one indigenous community for the execution of the seismic commitment for phase 1. As of the date of this annual report, the contract is in phase 0 as the applicable prior consultation process must be completed, and outstanding investment commitments of US$9.5 million related to this block consist of the acquisition of 105.6 sq. km. of 3D seismic and the drilling of two exploratory wells. Prior consultation has not been initiated with the ethnic community due to the restrictions that derive from the issuance of Municipal Agreement 007 of Puerto Guzmán. Preliminary phase is suspended due to the occurrence of force majeure events from April 1, 2020, to June 20, 2022.

Tacacho Block. We are the operator of and have a 50% working interest in the Tacacho Block, which covers approximately 589,009 gross acres (2,384 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$1.2 million related to this block consist of the acquisition, processing and interpretation of 480 km. of 2D seismic. Phase 1 is suspended due to the occurrence of force majeure events related with social and public order conditions of the area as of the date of this annual report.

Terecay Block. We are the operator of and have a 50% working interest in the Terecay Block, which covers approximately 586,625 gross acres (2,374 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$2.9 million related to this block consist of the acquisition, processing and interpretation of 476 km. of 2D seismic. Phase 1 is suspended due to the occurrence of force majeure events related with social and public order conditions of the area as of the date of this annual report.

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.

Operations in Chile

Our Chilean assets currently give us access to 716,000 of gross exploratory and productive acres across 4 blocks in a large fully-operated land base across the Magallanes Basin, with existing reserves, production and cash flows.

Our Chilean blocks are located in the provinces of Última Esperanza, Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil and gas-producing area. As of December 31, 2021, the Magallanes Basin accounted for all of Chile’s oil and gas production.

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

Highlights of the year ended December 31, 2021, related to our operations in Chile included:

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

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The table below summarizes information about the blocks in Chile in which we have working interests as of and for the year ended December 31, 2021.

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Fell Block

In 2006, we became the operator and 100% interest owner of the Fell Block. When we first acquired an interest in the Fell Block in 2002, it had no material oil and gas production. Since then, we have completed more than 1,100 sq. km. of 3D seismic surveys and drilled 140 exploration and development wells. In the year ended December 31, 2021, we produced an average of 2,397 boepd, in the Fell Block, consisting of 87% gas.

The Fell Block has an area of 367,800 gross acres (1,488 sq. km.) and its center is located approximately 140 km. northeast of the city of Punta Arenas. It is bordered on the north by the international border between Argentina and Chile and on the south by the Magellan Strait.

From 2006 through August 2011, we successfully explored and developed the Fell Block, which allowed us to transition approximately 84% of the Fell Block’s area from an exploration phase into an exploitation phase, which we expect will last through 2032. There are no minimum work and investment commitments under the Fell Block CEOP associated with the exploitation phase.

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

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

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

In the first and second quarters of 2012, we entered into three CEOPs with ENAP and Chile granting us working interests in the Isla Norte, Campanario and Flamenco Blocks, located in the center-north of the Tierra del Fuego Province of Chile. We are the operator of all three of these blocks, with working interests of 60%, 50% and 50%, respectively. We believe that these three blocks, which collectively cover 347,700 gross acres (1,407 sq. km.) and are geologically contiguous to the Fell Block.

Flamenco Block. We are the operator of, and have a 50% working interest in, the Flamenco Block, in partnership with ENAP. The block covers approximately 105,900 gross acres (428 sq. km.). In June 2013, we discovered a new oil and gas field in the block following the successful testing of the Chercán 1 well, the first well drilled by us in Tierra del Fuego.

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We have completed all the committed activities for the first and second exploration periods under the CEOP governing the Flamenco Block. We opted out of the third exploration period, and as of the date of this annual report, the exploration phase in the Flamenco Block has been concluded.

Isla Norte Block. We are the operator of and have a 60% working interest in partnership with ENAP in the Isla Norte Block, which covers approximately 97,650 gross acres (395 sq. km.). As of the date of this annual report, we had completed 100% of the commitments of the first exploratory period and outstanding investment commitments of US$0.9 million related to this block correspond to one exploratory well of the second exploratory period.

Campanario Block. We are the operator of, and have a 50% working interest in, the Campanario Block, in partnership with ENAP. The block covers approximately 144,150 gross acres (583 sq. km.). As of the date of this annual report, we had completed 100% of the commitments of the first exploratory period and outstanding investment commitments of US$5.0 million related to this block correspond to two exploratory wells of the second exploratory period. The drilling campaign relating to the committed wells of Isla Norte and Campanario Blocks started in February 2020 but due to the COVID-19 pandemic, the execution of the 2020 work plan was interrupted.

Therefore, in April 2020, January 2021, and July 2021, we presented to the Ministry of Energy notifications of declaration of force majeure, which were approved and we obtained an extension of the second exploratory period to fulfill the commitments of the Campanario and Isla Norte Blocks until the first quarter of 2023.

During 2020 we fulfilled all the committed activities for the second exploration period under the CEOP governing the Flamenco Block, and we have outstanding investment commitment of US$5.9 million as of the date of this annual report, consisting of two exploratory wells before April 20, 2023, on the Campanario Block, and one exploratory well before February 19, 2023, on the Isla Norte 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, 2021 related to our operations in Brazil included:

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The map below shows the location of our concessions in Brazil in which we have a current or future working interest:

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The following table sets forth information as of December 31, 2021 on our concessions in Brazil in which we have a current or future working interest: