GPRK GeoPark Limited

ITEM 3. KEY INFORMATION

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

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

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

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

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

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

Statement of income data

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Balance sheet data

Cash flow data

Other financial data

Exchange rates

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

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

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

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

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

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

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Source: Central Bank of Brazil.

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

Source: Central Bank of Brazil.

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

B.       Capitalization and indebtedness

Not applicable.

C.       Reasons for the offer and use of proceeds

Not applicable.

D.       Risk factors

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

Risks relating to our business

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our indebtedness could:

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

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

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

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

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

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

Risks relating to the countries in which we operate

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks related to our common shares

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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