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Basically, the taxes are:

Production Risk

For any type of contract to be entered into in Ecuador, the investing company has to take on all exploration and pro­duction risks and investments, as well as environmental responsibilities in accordance with its corresponding envi­ronmental obligations.

Furthermore, the investing company must strictly abide by all employment laws, in terms of legal requirements concerning the maximum number of foreign employees. Some contracts have allowed for arbitration as a dispute resolution mechanism; however, certain matters, such as taxes, cannot be submitted to arbitration. This is also true for certain termination provisions in the event of the investing company breaching the law (such as transfer of rights without consent).  The reform to the Law of Hydrocarbons enacted in 2021 allows the entry into investment treaties with the Government of Ecuador, allowing to freeze tax incentives in consideration for investment commitments and expanding local employment.

C.    Organizational structure

We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements.

D.    Property, plant and equipment

See “—B. Business Overview—Title to properties.”

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Factors affecting our results of operations

We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following:

Discovery and exploitation of reserves

Our results of operations depend on our level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce.

For the year ended December 31, 2021, we made total capital expenditures of US$129.3 million (US$119.9 million, US$4.3 million, US$0.1 million and US$5.0 million in Colombia, Chile, Argentina and Ecuador, respectively), consisting of US$46.2 million related to exploration.

Oil prices have been volatile, particularly since the start of the COVID-19 pandemic and the armed conflict in Ukraine. In preparation for continued volatility and the prolonged effects of the COVID-19 pandemic, we have developed multiple scenarios for our 2022 capital expenditure program. See “Item 4. Information on the Company—B. Business Overview—2022 Strategy and Outlook.”

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

If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase its work and investment program and thereby further increase oil and gas production.

Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business, results of operations and financial condition.

Oil and gas revenue and international prices

Our revenues are derived from the sale of our oil and natural gas production, as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent. The price realized for the natural gas we produce in Chile is linked to the international price of methanol, which is settled in the international markets in US$. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors.

During 2020, the oil market experienced a significant over-supply condition, mainly influenced by the COVID-19 pandemic, that resulted in a sharp drop in prices, with Brent falling from over US$50 per barrel at the beginning of March

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2020 up to US$16 per barrel in late April 2020. During 2021, the crude demand recovery resulted in some improvements in the market conditions from the end of 2020 and onwards.

We manage part of our exposure to the volatile crude oil price using derivatives. For further information related to Commodity Risk Management Contracts, please see Note 8 to our Consolidated Financial Statements.

Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price is linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin that is transported through Ecuador. In both basins, the reference price is then adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur content, delivery point and transport costs.

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In Chile, the price of oil we sell to ENAP is based on Dated Brent minus certain marketing and quality discounts such as, API, sulphur content and others. We have a long-term gas supply contract with Methanex. The price of the gas sold under this contract is determined by a formula that considers a basket of international methanol prices, including US and European price indices. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—A substantial or extended decline in oil, natural gas and methanol prices may materially adversely affect our business, financial condition or results of operations.”

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

In Argentina, the realized oil prices for our production in the Neuquén Basin follows the “Medanito” blend oil price reference, which has traditionally been linked to ICE Brent adjusted by certain marketing and quality discounts based on API, delivery point and transport costs. Though prices have been regulated by the Government in the past, they are currently being determined by market-based formulas.

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

If oil and methanol prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$17.9 million (post-tax loss would have been higher by US$21.0 million in 2020).

Production and operating costs

Our production and operating costs consist primarily of expenses associated with the production of oil and gas, the most significant of which are gas plant leasing, facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and products, among others. As commodity prices increase or decrease, our production costs may vary. We have historically not hedged our costs to protect against fluctuations.

Availability and reliability of infrastructure

Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.”

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Production levels

Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and oil and natural gas prices.

We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.”

Contractual obligations

In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P contracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various CEOPs, E&P contracts, production sharing agreements and concession contracts and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.”

Acquisitions

As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally incorporate our acquired business into our results of operations at or around the date of closing.

On January 16, 2020, we acquired the 100% share capital of Amerisur. Considering that Amerisur issues financial information monthly, we have considered the identified assets and liabilities as of December 31, 2019. If the purchase price allocation exercise had been carried out as of January 16, 2020, it would not have deferred significantly.

Functional and presentational currency

Our Consolidated Financial Statements are presented in US$, which is our presentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is the real.

Geographical segment reporting

In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non-Chilean, non-Argentine and non-Brazilian operations, primarily consisting of our corporate head office operations.

As of December 31, 2021, we divided our business into five geographical segments—Colombia, Chile, Brazil, Argentina, and Ecuador—that corresponded to our principal jurisdictions of operation. Activities not falling into these five geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment.

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Description of principal line items

The following is a brief description of the principal line items of our consolidated statement of income.

Revenue

Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place.

Commodity risk management contracts

Includes realized and unrealized gains and losses arising from commodity risk management contracts.

Production and operating costs

Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals and royalties are also included within this account. For a description of our production and operating costs, see “—Factors affecting our results of operations.”

Depreciation

Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.

Geological and geophysical expenses

Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies.

Administrative expenses

Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions.

Our administrative expenses for the year ended December 31, 2021, decreased by US$3.5 million, or 7%, compared to the year ended December 31, 2020, mainly due to staff cost reductions and higher allocation to joint operations.

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Selling expenses

Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs and selling taxes.

Our selling expenses for the year ended December 31, 2021, increased by US$2.9 million, or 49%, compared to the year ended December 31, 2020, mainly due to the sales increase during the year and also to differences in accounting for different points of sale in Colombia. Sales at the wellhead have no selling costs associated but generate lower revenue whereas transportation costs for sales to other delivery points are accounted for as selling expenses.

Write-off of unsuccessful exploration efforts

Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable.

During 2021, we recognized write-off of unsuccessful exploration efforts of US$12.3 million (US$52.7 million in 2020). See Note 20 to our Consolidated Financial Statements.

Impairment of non-financial assets

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

An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value minus costs to sell and value in use.

During 2021, we recognized a net impairment loss of US$4.3 million (US$133.9 million in 2020) that corresponded to: (1) an impairment loss recognized in the Fell Block of US$17.6 million due to the decline in the proved reserves estimation in 2021 and, (2) a reversal of impairment loss of US$13.3 million in the Aguada Baguales and El Porvenir Blocks in Argentina. See Note 37 to our Consolidated Financial Statements.

Financial results

Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses.

Recent accounting pronouncements

See Note 2.1.1 to our Consolidated Financial Statements.

Results of operations

The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes.

In preparation for continued volatility, we have developed multiple scenarios for our 2022 capital expenditure program. See “Item 4. Information on the Company –B. Business Overview—2022 Strategy and Outlook.”

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Year ended December 31, 2021 compared to year ended December 31, 2020

The following table summarizes certain of our financial and operating data for the years ended December 31, 2021 and 2020.

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The following table summarizes certain financial data.

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Revenue increased 75%, from US$393.7 million for the year ended December 31, 2020, to US$688.5 million for the year ended December 31, 2021, primarily as a result of higher realized prices. Sales of crude oil increased due to higher realized prices partially offset by lower sold volumes of 11.5 mmbbl in the year ended December 31, 2021, compared to 12.0 mmbbl in the year ended December 31, 2020, and resulted in net revenue of US$647.6 million for the year ended December 31, 2021, compared to US$359.6 million for the year ended December 31, 2020. In addition, sales of gas increased from US$34.1 million for the year ended December 31, 2020, to US$41.0 million for the year ended December 31, 2021, due to higher realized prices partially offset by lower natural gas deliveries.

The increase in 2021 net revenue of US$294.9 million is mainly explained by:

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Revenue attributable to our operations in Colombia for the year ended December 31, 2021, was US$618.3 million, compared to US$334.6 million for the year ended December 31, 2020, representing 90% and 85% of our total consolidated sales, respectively. The increase is related to an increase in the average realized price per barrel of crude oil from US$30.6 per barrel to US$58.3 per barrel, primarily due to higher reference international prices partially offset by a decrease in oil deliveries from 11.3 mmbbl to 10.9 mmbbl.

Revenue attributable to our operations in Chile for the year ended December 31, 2021, was US$21.5 million, a 1% decrease from US$21.7 million for the year ended December 31, 2020, principally due to (1) a decrease in gas sales by US$1.4 million reflecting lower deliveries, partially offset by higher average realized prices from US$16.1 per boe for the year ended December 31, 2020 to US$20.7 per boe for the year ended December 31, 2021, and, (2) an increase in oil sales by US$1.2 million reflecting higher average realized prices per barrel of crude oil from US$38.0 per barrel for the year ended December 31, 2020 to US$62.8 per barrel for the year ended December 31, 2021 (an increase of US$24.8 per barrel or a total of 65%), partially offset by a decrease in oil deliveries from 0.13 mmbbl to 0.10 mmbbl. The contribution to our revenue during the years ended December 31, 2021, and 2020 from our operations in Chile was 3.1% and 5.5%, respectively.

Revenue attributable to our operations in Brazil for the year ended December 31, 2021, was US$20.1 million, a 57% increase from US$12.8 million for the year ended December 31, 2020, principally due to higher gas deliveries from 0.5 mmboe to 0.6 mmboe to respond to the higher gas demand in Brazil plus higher realized gas prices from US$25.6 per boe for the year ended December 31, 2020, to US$37.4 per boe for the year ended December 31, 2021. The contribution to our revenue from our operations in Brazil during the years ended December 31, 2021 and 2020, was 2.9% and 3.2%, respectively.

Revenue attributable to our operations in Argentina for the year ended December 31, 2021, was US$28.7 million, a 17% increase from US$24.6 million for the year ended December 31, 2020, primary due to (1) an increase in oil sales by US$7.3 million related to an increase in average realized prices per barrel of crude oil from US$42.0 per barrel for the year ended December 31, 2020, to US$56.4 per barrel for the year ended December 31, 2021 (or a total of 34%), partially offset by a decrease in oil deliveries from 0.5 mmbbl to 0.4 mmbbl, and (2) an increase in gas sales by US$0.8 million reflecting higher gas prices due to local market conditions, plus higher deliveries. The contribution to our revenue from our operations in Argentina during the years ended December 31, 2021 and 2020 was 4.2% and 6.2%, respectively.

Production and operating costs

The following table summarizes our production and operating costs for the years ended December 31, 2021 and 2020.

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Consolidated production and operating costs increased 70%, from US$125.1 million for the year ended December 31, 2020, to US$212.8 million for the year ended December 31, 2021, primarily due to higher cash royalties as a result of the higher international prices.

Production and operating costs in Colombia increased by 93%, to US$178.4 million for the year ended December 31, 2021, as compared to US$92.3 million for the year ended December 31, 2020, primarily due to higher royalties of US$75.9 million, in line with higher oil prices and due to incremental maintenance and well intervention activities in the Llanos 34 Block.

Production and operating costs in Chile increased by 8% to US$11.1 million due to well intervention and maintenance activities that were suspended in the comparative period due to the lower oil price environment. Operating costs per boe increased to US$12.3 per boe in 2021 from US$8.2 per boe in 2020.

Production and operating costs in Brazil increased by 19%, to US$4.6 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020, mainly resulting from higher royalties due to higher realized prices and gas deliveries.  However, operating costs per boe decreased to US$4.6 for the year ended December 31, 2021, from US$5.8 per boe for the year ended December 31, 2020.

Production and operating costs in Argentina increased by 1%, to US$18.8 million for the year ended December 31, 2021, as compared to US$18.6 million for the year ended December 31, 2020, mainly due to higher operating costs per boe partially offset by lower oil deliveries. Operating costs per boe increased to US$20.8 for the year ended December 31, 2021, from US$19.8 per boe for the year ended December 31, 2020.

Geological and geophysical expenses

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Geological and geophysical expenses decreased by 47%, from US$15.0 million for the year ended December 31, 2020, to US$7.9 million for the year ended December 31, 2021, primarily as the result of cost reduction initiatives and higher allocations to capitalized projects, as a result of the exploratory activities that were suspended in the comparative period due to the lower oil price environment.

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Administrative costs

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Administrative costs decreased by 7%, from US$50.3 million for the year ended December 31, 2020, to US$46.8 million for the year ended December 31, 2021, primarily as the result of cost reduction initiatives and higher allocation to joint operations. This reduction was partially offset by an increase in consultant fees and communication and IT costs related to projects that were postponed in the previous year due to the COVID-19 pandemic.

Selling expenses

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Selling expenses increased by 49%, from US$5.8 million for year ended December 31, 2020, to US$8.7 million for the year ended December 31, 2021, primarily due to the sales increase during 2021, and also to differences in accounting for different points of sale in Colombia. Sales at the wellhead have no selling costs associated but generate lower revenue whereas transportation costs for sales to other delivery points are accounted for as selling expenses.

Commodity risk management contracts

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We recorded a loss of US$109.2 million related to commodity risk management contracts for the year ended December 31, 2021, and a profit of US$8.1 million for the year ended December 31, 2020.

Consolidated commodity risk management contracts refer to two different components, a realized and an unrealized portion. The realized loss of US$109.7 million for the year ended December 31, 2021, compared to a US$21.1 million gain for the year ended December 31, 2020, reflected Brent oil prices and commodity risk management contracts settled during the respective periods. The unrealized gain was US$0.5 million for the year ended December 31, 2021, compared to US$13.0 million loss for the year ended December 31, 2020. Unrealized results are generated from changes in the forward Brent oil price curve.

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Depreciation charges decreased by 25% from US$118.1 million for the year ended December 31, 2020, to US$89.0 million for the year ended December 31, 2021, primarily due to a decrease in the depreciation cost per boe in Chile as a consequence of the impairment losses recognized in the Fell Block in 2020 and the property, plant and equipment related to the blocks in Argentina that were reclassified as held for sale in August 2021.

Operating profit (loss)

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We recorded an operating profit of US$185.8 million for the year ended December 31, 2021, compared to an operating loss of US$110.7 million for the year ended December 31, 2020, as a result of the reasons described above.

In 2021, we recorded a write-off of unsuccessful exploration efforts of US$12.3 million that corresponded to two unsuccessful exploratory wells drilled in the Llanos 32 Block in Colombia, other exploration costs incurred in the Fell Block in Chile, an exploratory well drilled in previous years in the CPO-5 Block in Colombia and other exploration costs incurred in previous years in the PUT-30 Block in Colombia for which no additional work would be performed.

Additionally, during 2021, we recognized a net impairment loss of US$4.3 million that corresponded to: (1) an impairment loss recognized in the Fell Block of US$17.6 million due to the decline in the proved reserves estimation and, (2) a reversal of impairment loss of US$13.3 million in the Aguada Baguales and El Porvenir Blocks in Argentina 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. For further information see Note 37 to our Consolidated Financial Statements.

Financial results

Net financial results increased 2% to US$62.5 million for the year ended December 31, 2021, as compared to US$61.4 million for the year ended December 31, 2020, mainly resulting from a one-time cost of US$6.3 million associated with the strategic deleveraging process executed in April 2021 that resulted in significant debt reduction with extended maturities and lower costs of debt.

Foreign exchange gain (loss)

Foreign exchange variation was a loss of US$13.0 million for the year ended December 31, 2020, compared to a gain of US$5.0 million for the year ended December 31, 2021. The loss of 2020 mainly corresponds to the realized loss on

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currency risk management contracts of US$9.4 million resulting from derivative financial instruments to manage our future exposure to local currency fluctuations with respect to income tax balances in Colombia.

Profit (loss)before income tax

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For the year ended December 31, 2021, we recorded a profit before income tax of US$128.4 million, compared to a loss of US$185.1 million for the year ended December 31, 2020, primarily due to the reasons mentioned above.

Income tax expense

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Our effective tax rate was 52% for the year ended December 31, 2021, compared to (26)% in 2020. The increase in the effective tax rate was primarily due to the generation of profit during 2021. The 2020 income tax expense included the write-down of the deferred income tax asset in Peru due to the decision to retire from the Morona Block (US$8.4 million), the write-down of a portion of tax losses and other deferred income tax assets in Chile, Brazil and Argentina in which there was insufficient evidence of future taxable profits to offset them in accordance with the expected future cash-flows at year-end (US$24.2 million), and tax losses from non-taxable jurisdictions or where no deferred income tax benefit is recognized.

Profit (loss) for the year

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For the year ended December 31, 2021, we recorded a net profit of US$61.1 million as a result of the reasons described above, compared to a net loss of US$233.0 million for the year ended December 31, 2020.

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Year ended December 31, 2020 compared to year ended December 31, 2019

For a discussion of the results of our operations for the year ended December 31, 2020 compared to the year ended December 31, 2019, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2020 compared to the year ended December 31, 2019” in our Annual Report on Form 20-F for the year ended December 31, 2020.

B.    Liquidity and capital resources

Overview

Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including:

We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all.

Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash generated by our operations. We have also in the past entered into offtake and prepayment agreements.

Between 2005 and 2021, we raised approximately US$200 million in equity offerings at the holding company level and nearly US$1.5 billion through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities with Methanex, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.

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 senior notes due 2024. The Notes due 2024 mature on September 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on March 21 and September 21 of each year. The Indenture governing our Notes due 2024 contains incurrence-based limitations on the amount of indebtedness we can incur. This limits our capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the Notes due 2024. The net proceeds from the Notes due 2024 were used by us (i) to make a capital contribution to our wholly-owned subsidiary, Agencia, providing it with sufficient funds to fully repay the 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 the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in the Neuquén Basin in Argentina, and to repay existing indebtedness, including the Itaú loan in Brazil.

In January 2020, we issued US$350.0 million aggregate principal amount of senior notes due 2027. The Notes due 2027 mature on January 17, 2027, and bear interest at a fixed rate of 5.50% and a yield of 5.625% per year. Interest on the

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Notes due 2027 is payable semi-annually in arrears on January 17 and July 17 of each year. The Indenture governing our Notes due 2027 contains incurrence-based limitations on the amount of indebtedness we can incur. This limits our capacity to incur additional indebtedness, other than permitted debt, as specified in the indenture governing the 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 any 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.

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.

In May 2021, GeoPark Colombia S.A.S. executed a loan agreement with Bancolombia for Colombian Pesos 35.0 billion (equivalent to US$9.4 million at the moment of the loan execution) to finance working capital requirements in Colombia. The interest rate was the IBR index (interest rate of reference for short-term loans in Colombia) plus 1.6% per annum, and interests were payable monthly. The loan was set to mature in May 2022, but in August 2021, GeoPark Colombia S.A.S. fully prepaid the loan, with no additional cost.

In July 2021, GeoPark Colombia S.A.S. executed a loan agreement with Itau Bank for Colombian Pesos 37.7 billion (equivalent to US$10.0 million at the moment of the loan execution) to finance working capital requirements in Colombia. The interest rate was 5.38% per annum, and interests were payable monthly. The loan was set to mature in January 2022 but in October 2021, GeoPark Colombia S.A.S. fully prepaid the loan, with no additional cost.

On October 7, 2021, GeoPark Colombia S.A.S. signed a loan agreement with Banco BTG Pactual S.A. which provides GeoPark with access to up to US$20.0 million until October 7, 2022. The agreement establishes an interest rate of 4.50% per annum and a commitment fee of 1.95% per annum with respect to any undrawn amount. As of the date of this annual report, GeoPark Colombia S.A.S. has not withdrawn any amount from this loan.

On October 8, 2021, our Colombian subsidiaries entered into an offtake and prepayment agreement with Shell Western Supply and Trading Limited (“Shell”), one of their key customers. The prepayment agreement provides GeoPark with access to up to US$15.0 million in the form of prepaid future oil sales and has a twelve months availability period. Funds committed by Shell will be made available to GeoPark upon request and will be repaid by GeoPark, through future oil deliveries over the year after funds are disbursed. As of the date of this annual report, GeoPark has not withdrawn any amount from this prepayment agreement.

In September 2021, GeoPark was included in the S&P Global BMI Index and sub-indexes, including the S&P Emerging BMI, the S&P Colombia BMI, the S&P Latin America BMI, and the S&P Global BMI Energy, among others.

We believe that our current operations and 2022 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we would examine measures such as further capital expenditure program reductions, oil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the Company—B. Business Overview—2022 Strategy and Outlook.”

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Capital expenditures

In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview—2022 Strategy and Outlook”.

In the year ended December 31, 2021, we had total capital expenditures, related to purchase of property, plant and equipment, of US$129.3 million (US$119.9 million, US$4.3 million, US$0.1 million and US$5.0 million in Colombia, Chile, Argentina and Ecuador, respectively).

In the year ended December 31, 2020, we had total capital expenditures, related to purchase of property, plant and equipment, of US$75.3 million (US$61.6 million, US$11.9 million, US$0.7 million, US$0.4 million, US$0.4 million and US$0.3 million in Colombia, Chile, Argentina, Peru, Brazil and Ecuador, respectively).

Cash flows

The following table sets forth our cash flows for the periods indicated:

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Cash flows from operating activities

For the year ended December 31, 2021, cash flows from operating activities were US$216.8 million, a 28% increase from US$168.7 million for the year ended December 31, 2020, mainly resulting from the increase in revenues of oil reflecting higher oil and gas prices in 2021, partially offset by the cash taxes payments made during 2021.

For the year ended December 31, 2020, cash flows from operating activities were US$168.7 million, a 28% decrease from US$235.4 million for the year ended December 31, 2019, mainly resulting from the decrease in revenues of oil reflecting lower oil and gas prices in 2020, partially offset by the cost reduction initiatives carried during 2020.

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Cash flows used in investing activities

For the year ended December 31, 2021, cash flows used in investing activities were US$126.6 million, an 64% decrease from US$347.6 million for the year ended December 31, 2020. This decrease is primarily explained by the fact that we did not acquire any business in 2021 (US$272.3 million in 2020) partially offset by an increase of US$54.0 million in capital expenditures related to the purchase of property, plant and equipment.

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For the year ended December 31, 2020, cash flows used in investing activities were US$347.6 million, a 192% increase from US$119.3 million for the year ended December 31, 2019. This increase was primarily related to the acquisition of Amerisur for US$272.3 million in January 2020.

Cash flows (used in) from financing activities

Cash flows used in financing activities were US$190.4 million for the year ended December 31, 2021, compared to US$271.1 million from financing activities for the year ended December 31, 2020. This decrease was principally related to the execution of a series of transactions that included a successful tender to purchase US$255.0 million of the 2024

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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.

Cash flows from financing activities were US$271.1 million for the year ended December 31, 2020, compared to US$132.5 million used in financing activities for the year ended December 31, 2019. This increase was principally related to the net proceeds from the issuance of the 2027 Notes of US$342.5 million and a decrease in the shares repurchase payments of US$67.3 million.

Our material outstanding indebtedness is described below.

Notes due 2024 and 2027

General

On September 21, 2017, we issued US$425.0 million aggregate principal amount of senior notes due 2024. The Notes due 2024 mature on September 21, 2024, and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on March 21 and September 21 of each year.

On January 17, 2020, we issued US$350.0 million aggregate principal amount of senior notes due 2027. The Notes due 2027 mature on January 17, 2027 and bear interest at a fixed rate of 5.50% per year and a yield to maturity of 5.625%. Interest on the Notes due 2027 is payable semi-annually in arrears on January 17 and July 17 of each year.

In April 2021, the Company 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.

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 were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the Securities Act. The Notes are fully and unconditionally guaranteed jointly and severally by GeoPark Chile SpA and GeoPark Colombia S.A.S.

After these transactions, we reduced our total indebtedness nominal amount in US$105.0 million and improved our financial profile by extending our debt maturities. The current outstanding nominal amount of the 2024 Notes and 2027 Notes is US$170.0 million and US$500.0 million respectively. We recorded a loss of US$6.3 within Financial expenses for the year ended December 31, 2021 as a consequence of these transactions.

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Ranking

The Notes due 2024 and 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Chile and GeoPark Colombia (the “Guarantors”). The Notes due 2024 and 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantors (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantors; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantors and their respective subsidiaries to the extent of the value of the collateral securing such obligations.

Optional redemption

We may, at our option, redeem all or part of the Notes due 2024, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on September 21 of the years indicated below:

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We may, at our option, redeem all or part of the Notes due 2027, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 17 of the years indicated below:

Change of control

Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2024 and 2027, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2024 and 2027 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2024 and 2027 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption.

Covenants

The Notes due 2024 and 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company.

In the event the Notes due 2024 and 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2024 and 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the

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ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable.

The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to EBITDA ratio should not exceed 3.25 and the EBITDA to interest ratio should exceed 2.5. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions).

Events of default

Events of default under the indentures governing the Notes due 2024 and 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2024 and 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2024 and 2027 to become or to be declared due and payable.

Banco Santander

In October 2018, we executed a loan agreement with Banco Santander for Brazilian Real R$77.6 million (equivalent to US$20.0 million at the moment of the loan execution) to repay an existing US$-denominated intercompany loan. The interest rate applicable to this loan is the CDI plus 2.25% per annum. CDI represents the average rate of all inter-bank overnight transactions in Brazil. In September 2020, we executed the refinancing of the outstanding principal for Brazilian Real R$19.4 million (equivalent to US$3.4 million at the moment of the refinancing execution), to be paid in three installments in October 2021, April 2022 and October 2022.

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Other Agreements

In June 2020, our Colombian subsidiary executed an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment agreement provided us with access to 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 did not withdraw any amount from this prepayment agreement.

Off-balance sheet arrangements

We did not have any off-balance sheet arrangements as of December 31, 2021, or as of December 31, 2020.

C.    Research and development, patents and licenses, etc.

See “Item 4. Information on the Company——B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to properties.”

D.    Trend information

For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company—B. Business Overview—2022 Strategy and Outlook.”

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E.    Critical accounting policies and estimates

We prepare our Consolidated Financial Statements in accordance with IFRS and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as issued by the IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral component of the financial reporting process, actual results could differ from those estimates.

An accounting policy is considered critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time such estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following accounting policies represent critical accounting policies as they involve a higher degree of judgment and complexity in their application and require us to make significant accounting estimates. The following descriptions of critical accounting policies and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes and other disclosures.

Reserves estimates

The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2021 prepared by DeGolyer and MacNaughton, an independent international consultancy to the oil and gas industry based in Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management Reporting System (PRMS) framework. It incorporates many factors and assumptions including:

Our management believes these factors and assumptions are reasonable based on the information available to them at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; which may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income, which may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment that may require revision where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities and, (d) the recognition and carrying value of deferred income tax assets that may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets.

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Cash flow estimates for impairment assessments

Cash flow estimates for impairment assessments of non-financial assets require assumptions about two primary elements: future prices and reserves. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs. Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate.

For further information related to impairment of property, plant and equipment, please see Note 37 to our Consolidated Financial Statements.

Exploration and evaluation expenditures

The Group adopts the successful efforts method of accounting. Our management makes assessments and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the advice from qualified experts.

The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available.

Depreciation of oil and gas assets

Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block.

The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved and probable reserves, or future capital expenditure estimates change. Changes to proved and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues.

Asset retirement obligations

Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant liabilities. We record the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recognized, the cost is also capitalized by increasing the carrying amount of the related asset. Over time, the liability is accreted to its present value at each reporting date, and the capitalized cost is depreciated over the estimated useful life of the related asset. Estimating the future abandonment costs is difficult and

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requires management to make estimates and judgments because most of the obligations will be settled after many years. Technologies and costs are constantly changing, as well as political, environmental, health, safety and public relations considerations. Consequently, the timing and future cost of abandonment are subject to significant modification. Any change in the variables underlying our assumptions and estimates can have a significant effect on the liability and the related capitalized asset. The present value of future costs necessary for well abandonment is calculated for each area at the present value of the estimated future expenditure. The liability recognized is based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates.

The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required.

Contingencies

From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental and health & safety matters. For example, from time to time, the Company receives notices of environmental, health and safety violations. Based on what our Management currently knows, such claims are not expected to have a material impact on the Consolidated Financial Statements.

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